comparison of solar, nuclear and wind options for … · 400 ppm greenhouse gas equivalent...

COMPARISON OF SOLAR, NUCLEAR AND WIND OPTIONS FOR LARGE SCALE IMPLEMENTATION

David Mills Solar Heat and Power Pty Ltd

22 Enterprise Crescent, Maison Dieu Industrial Estate Singleton, NSW, 2330, Australia

Email: [email protected] web: www.solarheatpower.com

Abstract

This paper addresses the relative suitability of nuclear and solar in Australia as a primary future electricity option, since nuclear can use abundant Australian resources of U235, but the direct solar option is the biggest global resource. The background is that we are likely to need generation systems which use close to zero net emissions by mid-century. There are many energy options, but few are ready, and this paper addresses the issue about whether a viable energy system can be based mostly around solar and wind alone as a worst case. This paper investigates issues such as usefulness of various technical options in the 2050 time frame, global availability of uranium fuel, load-following operation of candidate solar and nuclear technology, net energy gained, net global pollution savings, dynamic cumulative energy gained. It is found that advanced solar and nuclear typical of the next decade have similar cost/efficiency and each can supply the electricity load if necessary. Nuclear has a severe global fuel resource problem not shared by solar. Solar has almost no fuel cost and decommissioning uncertainties while nuclear has long term back end and fuel cost uncertainties. The author proposes technology-independent support schemes based on delivered energy (feed-in laws, carbon trading) which allow increased selling price for early support of new technology, where each technology must openly pay its own real costs for meeting radiological and environmental standards, security charges, insurance, fully insured waste disposal, fuel enrichment, and fully insured decommissioning.

1. INTRODUCTION

It is now generally accepted by the scientific community and the general public that global warming caused by human activity is a serious threat to the climate. Under the increasingly more popular ‘containment and convergence’ or CC scenario, per capita greenhouse gas emissions would have to be standardised among all Annex 1 (developed) nations. A recent work along these lines by Hoehne,(2006) examined the detailed difference between 450 and 400 ppm greenhouse gas equivalent scenarios for 2050. In a 450 ppm scenario, total Annex 1 emissions would have to be reduced by 70-90% from 1990 levels by 2050. To achieve the Annex 1 450 ppm target, Hoehne models an electricity generation mix of 65% zero emission technology and 35% high efficiency gas generation technologies. Australia has 14% gas generation, almost all high efficiency combined cycle or combined heat and power plant. Increasing this to 35% would reduce the present gas resource in Australia from 91 to 36 years, so that the gas reserve might be largely gone by 2066 as a result of any such ramp up between 2010 and 2050. This suggests that in Australia, greater use of zero operational emission technologies might be preferred to retain the availability of this precious fuel. In a 400 ppm scenario, total annex 1 (developed country) emissions would have to be reduced by 80-90% from 1990 levels by 2050. To meet the 400 ppm target, Australia would need 90% zero emissions technology and 10% high efficiency gas, so that the gas usage could be ramped down from the present extending the reserve to more than a century. Currently there is no truly zero emissions technology because of the pollution embodied in technology during manufacture, but zero operational emissions technologies with 1-3% embodied emissions exist, so one would need the market component to climb 1-3% to compensate. Finally, the 400 ppm target needs significant reductions by 2020, more than 20% from 1990 levels, in order to be possible at all.

Comparison of Solar, Nuclear and Wind for Large Scale Implementation – Plenary Address Mills

Clean Energy? – Can Do! – ANZSES 2006 2

One might conclude the 400ppm target is almost out of reach and that we should try for 450ppm. However, Hoenhe concludes that a 450 ppm CO2 concentration is not a ‘safe’ option: it is likely to result in global temperature increase above 2°C, coral reefs will be affected, there will be considerable melting of ice and Increased extreme whether events. The risk of large scale climate event singularities (disasters) is low but not excluded. Larger cuts than 450 ppm may be necessary by 2050 to stabilise emissions because of possible underestimates (Mills, 2005; Murphy, 2004) in the uncertainty of the original IPCC estimations of global warming (IPCC, 2001), which could lead to temperature rises as high as 6 degrees globally, and higher still over land areas. Such an eventuality would be a disaster for the biosphere and humankind. The 450 ppm scenario implies the abandonment of coal in Annex 1 countries, unless cost-effective carbon sequestration appears. The 400 ppm scenario implies an almost complete abandonment of fossil fuel, excepting a little gas probably allocated for grid peak energy support purposes, unless there is development of a practical carbon sequestration solution. The choice of which target will be adopted will depend upon unfolding climate events, but for either scenario, technologies which operate with very low or zero emissions are needed as the basis for a new generating system. As most large systems have a lifetime of 40 years or more, this requires a new energy strategy to be in place by 2010 or thereabouts. This paper is thus an attempt present basic comparison of nuclear, solar thermal electric (STE) and wind generation as possible candidates to nearly eliminate electricity and energy contributions to global warming by mid-century. This work is primarily directed at the Australian case, using data for the State of New South Wales (NSW) as an example, but it has implications for other international energy markets. Detailed energy and emissions calculations in this paper are not produced, but will be presented in a later version to be submitted for publication.

2. STRATEGIC ELECTRICITY TECHNOLOGY OPTIONS

As is the case with current coal in Australia, it is also likely that any new energy mix will be composed of a primary technology with a few less important niche players. Any candidate primary technology must make use of a very large, long term resource and deliver an output pattern which supplies most of the required load. Niche players can appeal to specific characteristics such as the use of low cost, but limited, resources; resources with flexibility which adds to overall grid stability; or resources which may geographically limited. Any very low emissions technology proposed must also be at a technical state where rapid ramp-up must be possible after about 2010-2020, especially if events unfold which demand a 400 ppm target. Uncertainty in the ability to ramp up to the required output is the most common deficiency of the major technical alternatives.

2.1. Technical options not included

The following is a list of ‘big players’ which have potential to contribute significantly, but are unlikely to make any significant contribution by mid-century: Coal fired generation using carbon sequestration is a technology which appears to be not only far away technically as a commercially feasible option but likely to be more costly than any of the options in this paper (for one of the least expensive estimates, see Herzog and Golomb, 2004). Isolating Greenhouse gas from flue gases is a serious problem which may require building a whole new generation of pure oxygen fired coal-fired plants. Storage of gas in reservoirs looks to have serious problems due to dissolving of the surrounding rock by the CO2 and ambient saline water (Kharaka, 2006); if just one hole appears the CO2 is lost to the atmosphere quickly. Australian research, because of this issue, is largely targeted at the storage of liquid CO2 deep underground to limit leakage, but this is at least 10-20 years from the first commercialisation, and would require enormous caverns dug every day 2 km below the surface to deal with current emissions.



Hydroelectricity is significant internationally, but new sites are scarce, and dams been discovered to have greenhouse emissions similar to coal fired stations in warm climates (World Commission on Dams, 2000), where most remaining unexploited sites exist. Hydroelectricity may have to contract, not increase. Nuclear fusion is far off, with the first net energy-producing facility ITER scheduled for 2015 and cost estimates for a mid-century plant not yet on the board. Ocean Thermal Energy is a huge resource of heat, but exploiting the small temperature differences between deep water and surface water to run a turbine is inherently inefficient and likely to much more costly than land-based renewable energy. Hydrogen is currently not an energy source but an energy carrier with a small market. Importantly, the round-trip efficiency of hydrogen as an electricity supply is poor. Even using an efficient fuel cell, it would require almost doubling the size of a solar, wind or nuclear plant to supply an end-use application, compared to supply it through the electricity grid. Hydrogen, in fact, needs to become an energy resource to progress, created through some very inexpensive photo-biological solar-driven energy process so that expensive water splitting by renewable or fossil electricity is not required to produce it. This could happen, and is under active research, but no commercial process is yet on the horizon. The next group has definite prospects but major uncertainties: Deep (“hot rocks”) geothermal has significant potential as a large future resource around the world; it is claimed to be potentially low in cost (Geodynamics, 2006a), but cost and field lifetime have not been demonstrated. Although 5 MW was produced at the Fenton Hill experimental site in the USA in the 1990s (Duchane and Brown, 2002), in the course of proving this technology, there have been difficulties found in drilling and extraction (eg Geodynamics, 2006b). Nevertheless development proceeds actively, especially in Australia where if the Habanera field experiment is successful, then a base load technology with output characteristics and cost similar to base load nuclear, but without significant environmental or weapons proliferation problems, will have become available. This question should be resolved within 3-5 years. Solar photovoltaic (PV) power continues to be far too expensive for large scale use (Japan may be an exception, because of high internal energy costs) and lacks effective low-cost storage. Lack of storage is also an issue restricting market size (see next item). Concentrating PV such as the dish reflector PV technology used by Solar Systems (2006) has the potential – using the same solar resource - to rival solar thermal electricity in cost per kWh as PV receivers improve in efficiency beyond 40% in the next few years. The major long term issue is lack of a storage system: any storage system for concentrating PV must add to total kWh cost whereas thermal storage in solar thermal systems actually reduces kWh cost. While seasonal variations are similar in both types of solar system, the capacity factor of large concentrating PV systems will probably be in the 20-25% realm, while solar thermal systems could rise to three times that, and with greater hourly reliability. Unlike wind, concentrating PV would not complement STE, because both would suffer similar daily fluctuations in output. However, in scales below 10MW, concentrating PV might be significantly cheaper than STE one day. Plantation biomass is being proposed at a time when soil loss and degradation is critical, population is increasing, and more than half the Earth’s photosynthesis is already harnessed for food and materials. Land limits global usage for energy: for example, plantation ethanol will use 500 times as much land to power vehicles as STE solar power.

1 For powering the electricity grid, current domestic

1 At 2 tonnes per hectare, Australian wheat produces 800 litres (Grant, 2005) of anhydrous ethanol per

hectare. If we bravely assume small Prius-type hybrid cars we would be talking about 5 litres/100 km, running 15000 km per year, we need 750 litres of petrol per year. The ethanol contains only 2/3 the calorific value of petrol so we need 1125 litres of ethanol per year per car. Thus we can run about 800/1125 = 0.711 cars per ha. Therefore, for 13 million cars we need 18.3 million ha, more than the whole Australian wheat crop, which uses 11 million ha, and close to the entire planted area of Australia, 22 million ha. Using ‘plug-in’ versions of the same car, running from electricity at 4 km per kWh, we would need 1000 MW plants of solar electricity occupying 35,000 ha. The land required for biomass is thus more than 500 times larger to perform the same task than for direct solar electricity.



Australian coal usage of 90 million tonnes at 31 MJ/kg can be compared to the 24 million tonnes of wheat produced at 15.2 MJ/kg. The 11 million ha devoted to wheat is about half of total planted area. If it were all planted to wheat, it would have about 1/3 the energy value required to supply the current electricity system, and much less when one removes the demand for food. Most countries also have far less land per capita than Australia. Biomass may have its greatest value in liquid fuels back-up of electricity in plug-in hybrid vehicles, where 20% of current petrol requirements might be needed, and as aircraft fuel. The three electricity generation options remaining are wind, direct solar thermal electricity (STE), and nuclear. This paper will address the ability of these three options to contribute to a future complete energy mix. As they currently stand, all have technical deficiencies in this role, and one has formidable social and political disadvantages, but all are in a position for rapid growth in the required time frame to stabilise global warming. An implication here is that transport will need to be progressively electrified through the electricity grid, a development that is now likely to occur with the advent of new plug-in hybrid vehicles and pure electric vehicles, both using much improved lithium-ion battery technology (Markal and Simpson, 2006). It is almost certain that the eventual energy mix will include major inputs from some of the technologies 1 to 9 above, but this paper assesses whether a viable energy system can be based around solar and wind alone if none of these in time.

2.2. Background to Wind Generation

Wind generation dates from late in the nineteenth century but has arisen in the last 30 years as a major greenhouse pollution avoidance technology. The capacity factor

2 (CF) of wind is, in this paper,

assumed to be 30%. This limits potential contribution, but in a large national programme, the CF may drop even below this because of the use of less favourable sites. Wind has a low enough cost potential to be considered as an important potential contributor. Advantages of wind technology are: It is commercially proven and very mechanically reliable; the availability is largely determined by that of the wind itself. The technology is quick to implement. There are no waste or decommissioning issues of significance. The kWh cost is becoming competitive in some locations, particularly if carbon trading is applied. Disadvantages are: The practical resource in Australia is rather small, usually viewed as 5 GW, but the industry has on occasion spoken of a 10GW potential. Offshore locations in other countries have large potential but in Australia these are rare because of the lack of a shallow continental shelf. Wind lacks a suitable storage technology which prevents the technology from being reliably available to the grid as required. Substantial extension and fine splitting of the connecting grid may be required. Wind is currently limited in Australia to about 50% of minimum annual grid load by unpredictability of supply and a lack of commercial storage options. Any new storage technology would raise the kWh cost but improve access to peak spot prices. Bird strikes can be an issue in certain otherwise economically attractive locations. Plant lifetime is short at about 20 years (Vestas, 2005). One might argue that this allows more rapid improvement, but that is a cost issue rather than an emissions issue.

2 The capacity factor (CF) of a plant is the ratio of what a plant produces in a given period compared to what the

plant would produce at full load for 100% of the time. A plant producing only half the energy it could have at 100% output is said to have a CF of 0.5.



There is community opposition to installations in many areas. Some backup is required from fossil fuel capacity. The contribution of wind to the grid varies with the seasons and time of day, but wind has the most random variation of the three options. The availability of storage would radically transform the prospects of wind, and there are a number of groups internationally working on methods of chemical, mechanical, and electrical storage for wind plants. However, in all of these except possibly for pumped hydro, storage adds very significantly to the capital cost of the system, and is so far too expensive. Wind seasonal variations are extremely site specific and quite variable, but for the case in point, there is a tendency for wind in southern NSW to be stronger, as is shown in Fig. 1. In this region, there is a historical average of high wind speeds at the time of year when solar output dips (see Fig. 6). This could allow a larger fraction of wind in the generation mix, partly using the solar storage as backup, but a full year minute by minute simulation is required to determine whether this has a cost benefit in reducing emissions. For nuclear there would seem to be little benefit as nuclear plant can completely load follow, so any wind would reduce the capacity factor of nuclear and increase its cost.

Fig. 1. Long term average wind output at Canberra airport, showing winter/spring peaks with the dark line. The green line shows measured output over the years spanned by the horizontal axis (Australian Bureau of Meteorology).

2.3. Background to Solar Thermal Electricity

Solar energy is a thermodynamically high quality energy source, and can theoretically generate temperatures far higher than conventional fossil or nuclear plants. Solar Thermal Electricity (STE) is a technology that produces electricity using high temperature solar heat to drive heat engines, usually steam turbines. An STE system usually uses reflectors to concentrate solar energy although some development of Fresnel lens systems has been done. STE has low cost potential, the ability to store energy at low cost as heat, and access to the largest resource of all, direct solar energy. Solar generated steam can drive turbines similar to those in nuclear and coal-powered plants or even heat air to power modified gas turbines. The concept of solar thermal electricity has been successfully demonstrated in the Californian desert for two decades using commercial parabolic trough technology (Frier and Cable, 1999), and while 98% has been achieved with a field availability of more than 99%, the National Renewable Energy Laboratory uses a conservative future plant availability of 94% (NREL, 2003), due primarily to maintenance on the conventional steam turbogenerator block. Tower technology, in which small



receiver on a high tower is illuminated by a field of mirrors below, has also been developed using two-axis tracking heliostat reflectors (NREL, 2003). A third option recently developed commercially by SHP is the Compact Linear Fresnel Reflector (CLFR) system, which is an intermediate system using long steam pipe receivers on towers, illuminated by long heliostats below (Mills and Morrison, 1999; Mills et al, 2006). Recently, ANU solar tracking dish technology (Luzzi and Lovegrove, 1997) has received commercial investment for the production of high temperature superheated steam and ammonia dissociation as storage. Advantages of STE are:

1. Access to a much larger practical resource than wind or nuclear, variously estimated at around 30 times current human commercial energy use (total solar energy received is about 5000 times human energy use, but many locations cannot be used). For Australia, the current electricity generation would require about 1300 km

2 of land, a square about 36 km on a side.

This is about 1/36th the size of the largest Australian cattle station, Anne Creek, and represents about 1/6000th of the 7,617,930 km

2 land mass in Australia. Around each of

Moree and Cobar, there are about 40,000 km2 of suitable land, and there are many other

potential sites around Australia. There is clearly no resource issue for sustainable use, now or in the future.

2. STE can use low cost energy storage in thermal reservoirs. The first (oil storage) was successfully commercially demonstrated in the mid 1980’s (Frier and Cable, 1999) and the second (molten salt) is being commercialised in parabolic trough plants in Spain (Andasol, 2004). SHP is developing very low cost pressurised water storage, expected to be commercialised later in this decade. Lloyd Energy in NSW is close to building the first graphite storage system for a commercial solar plant, and Germany is developing concrete storage. Storage actually drops cost by reducing the size of turbine required.

3. Like wind, there are no waste issues of significance and the technology is very safe. 4. Unlike both wind and nuclear, local inland communities are almost universally attracted to

such solar plants for local job creation and low environmental impact. 5. Like wind, long term immunity from fuel cost rises, since no fuel is used. 6. High availability, assumed to be 94% in this paper.

Disadvantages are:

1. Capital cost is mostly upfront, higher than coal fired plant, and close to nuclear plant of similar annual output.

2. The solar resource varies during the day according to weather conditions, and completely disappears at night, necessitating the use of storage. Storage systems other than molten salt and thermal oil still need to be proven on a large commercial scale.

3. The availability of solar energy drops in winter, so that unless the system is designed for the summer load, it cannot supply the whole of the winter load; seasonal storage at high temperature is not possible except with chemical change systems like ammonia and hydrogen, using very large tanks.

4. The technology also prefers a high solar radiation regime, so it is not suitable for countries like the UK, Germany, and Japan, but can make a huge contribution to countries such as China, India, the USA, Australia, and countries in southern Europe, Africa and South America, and in countries (like northern Europe) connected to sunny regions by a continental electricity grid.

SHP is a relatively new manufacturing company specializing in low cost solar thermal arrays suitable for large scale power generation. It has recently developed the CLFR (Compact Linear Fresnel Reflector) design being commercialised in Australia and overseas, described in another paper at this conference (Le Lièvre et al, 2006). SHP is currently building the largest solar thermal plant in the southern hemisphere (38 MW) in NSW, will begin a 6.5 MW plant in Portugal in late 2006, and has the capability to develop many GW of stand-alone solar plant globally. Current CLFR technology was designed to minimise ground coverage in fossil plant supplementation applications where land was limited, but this causes summer performance to be strongly emphasised at the expense of winter.



SHP can utilise an alternative version of CLFR technology (called in this paper the ALFR) with low cost storage in sites where more even annual output is required. The seasonal variation in performance would be very similar to a standard parabolic trough system with molten salt storage (Andasol, 2002) and technologies such as the ANU parabolic dish with ammonia storage. In the ALFR, 20 hours of storage will deliver a 64% capacity factor in the climate of Moree in northern NSW. The projected seasonal performance of the ALFR will be used in this paper as a modelled example for upcoming large scale solar generation.

2.4. Background to Nuclear

For many years, nuclear power using fission has been commercialized as an alternative to fossil fuel on resource grounds. Nuclear plants use large low temperature steam turbines running at 250-320°C, so all of the complexities of nuclear technology are to supply a modest temperature heat supply for a turbine. More recently nuclear fission is now being presented as the solution to global warming and some politicians now talk of a ‘nuclear future’ as a response to climate change. Globally, there appears to be a fuel shortfall. Economically recoverable uranium fuel resources are just 2.8 million tonnes and would last just 42 years at the current level of uranium consumption, 67,000 tonnes per year (European Commission, 2001). This is consumed by 370 GW of nuclear plant. If one were to include secondary resources (such as the military inventory), a total of around 4.8 million tonnes would be available, and this would last 72 years, again at current generation levels. Currently nuclear supplies about 17% of global electricity generation, about the same as hydroelectricity. However, to be considered as a major greenhouse reduction option under the 400 ppm scenario, additional clean generation must be provided to displace practically all of the current fossil fuel used. This is in a situation where nuclear will be running hard to run to stay where it is, because a net of 60 of these 370 reactors are scheduled to be shut down by 2015 (Mycle Schneider, 2005). Discussing the fuel issue, MIT (2003) quotes the Australian Uranium Information Centre as suggesting that a doubling of Uranium price would allow mining to access poorer grade ore, increasing the resource from 2.8 million to 30 million tonnes, ignoring the much higher energy required for fuel processing, Current world generation is about 4000 GW, but is likely to double before 2040. Therefore, even if we could mine and enrich all of this extra uranium, build the necessary 8000 GW of capacity, and use advanced reactors like the AP-1000 and EPR which need about 15% less fuel than conventional reactors, the world would run out of fuel in 2056 (see Fig 2). This option would require building 60% of current global capacity each year for 35 years. As a future climate control option, even under the most optimistic scenarios, uranium comes to a sudden halt by mid-century unless a radical change in technology appears. Australia is in an unusual position, because it contains nearly 40% of the globe’s recoverable uranium, but it can use this only at the cost of reducing potential fuel exports. Thus, the current ‘open cycle’ technology can also be considered as a much longer term option for reducing domestic emissions in Australia than in most other countries. For this reason, conventional nuclear is considered in this paper as a potential climate control option for Australia even if it is clearly inadequate as a global option. An ideal base load plant is imagined to have a 100% capacity factor (CF) which is the fraction of energy a plant actually delivers as a fraction of the maximum it could deliver in the same time period. Nuclear is almost always used as a base load electricity source, but in the real world one must account for planned and unplanned outages for refuelling and maintenance. What downtime should we expect in a real plant? Knox (2001) compiled data on the reliability of 399 nuclear plants of the current basic slow neutron designs. Leeuwin and Smith (2004), in an analysis recommended by the Australian Academy of Technological Sciences and Engineering (ATSE, 2006), used Knox’s data to show that although the plants usually began reliably, their performance drops steadily with age, and by the end of their lives they had delivered a lifetime cumulative CF of 55% (Fig. 3). However, the nuclear



industry has been making great efforts to improve this poor lifetime performance. More up-to-date information was provided by R. Knox (2006), who writes that for the 410 units for which data was obtainable, the world average annual load factor for end of June 2004 was 78.1%, and the lifetime average load factor 71.4%. The total operating experience extended over 8860 reactor years.

Figure 2. Simple scenario in which world demand for electricity doubles by 2050, but ten times known economically recoverable reserves are used in a nuclear building programme to displace fossil fuel by 2050. Even with this very high fuel assumption, the fuel is used up in 2056. If nuclear were to take up a constant market share equal to the 4000GW of today’s capacity, the fuel would last until 2079. Clearly, another technology with close to zero emissions must be involved, and the wisdom of using an energy source at a rate which will use up all fuel is questionable.

Fig. 3. Presentation of data originally gathered by Knox (2002) for 399 Nuclear plants, showing a progressive drop in cumulative performance over plant lifetime. This sample represents the majority of existing nuclear plants around the world at the time of the study. The full-power lifetime of the plants, is equivalent to 22 full-load years, which, over a 40 year operational lifetime, is equivalent to a lifetime plant CF of 55%. However, performance has improved markedly since then.



The disparity between some financial assumptions used and the 8860 reactor years of real experience is of concern. Nuclear costings per kWh (for example: UKRAE, 2004; Tarjanne, 2003) often assume a constant lifetime load factor of about 90% which is much above the 78% value so far achieved according to the industry’s own data. The Australian Uranium Information Centre (UIC, 2006) assumes 91% and even goes so far as to change MIT input data (MIT, 2003) contained in that eminently authored report to allow agreement with their own estimations of cost. The plant with the highest lifetime record found by the author is Watts Bar 1 in Tennessee, USA, with a lifetime value 91.1%. However, Watts Bar is very new: it is the last reactor to come on line in the United States (as of December 31, 2002) and in 2005 the CF was 89.7%. All other lifetime figures are below this, some lower than 60%. When plants have been shut down prematurely, they do not register in current data; Mycle Schneider Consulting (2005) note that the average shut down time in a nuclear plant up to 31 March 2005 was 20.5 years, so when they have problems, they drop out early. About 150 plants have been shut down, most prematurely. Mycle Schneider also note that the average lifetime for existing nuclear plants is 21.6 years. Because this is about half a plant design lifetime of 40 years, it may mean that the effect of increasing unreliability with age may correspond to the Knox CF value of 78%. However, MIT (2003) uses 85% CF, and this paper will use this figure in anticipating of improved technology. Technical advantages of the nuclear option are:

1. Nuclear plants can be installed anywhere. Performance is independent of location. 2. Nuclear output is independent of season and time of day, and is not driven by variations in the

resource. 3. A few countries, notably Australia, have such large uranium reserves that there would be

enough to power the electricity system for hundreds of years if it were not exported. 4. Nuclear does not emit greenhouse gas during operation, although there are emissions due to

plant construction and fuel production. Technical disadvantages are:

5. Nuclear usually delivers only base load, constant generation at a fixed level. However, the electricity grid requires a strongly increased output during daytime periods when people are active. Nuclear plants could meet total grid requirement by reducing the nuclear core output at night, but this would increase their per kWh cost because the plant would not be used at full capacity for as many hours a day.

6. Unlike solar and wind, for which costs are largely upfront, nuclear energy is characterised by large ‘back-end’ costs associated with waste disposal and decommissioning. Waste disposal must be secure for hundreds or thousands of years. Decommissioning has a time frame from about 20 years to 50 years (France) and even 130 years (UK). No large nuclear plant has been decommissioned, but the decommissioning costs of some small research reactors have so far greatly exceeded expectations. An International Atomic Energy Agency report (IAEA, 2006) states “Additionally, where funds have been dedicated to decommissioning, costs are often severely underestimated. There is a common trend to only compare the available funds with the actual funding needed at the beginning of the decommissioning process.…..Cost estimates should take into account all immediate and discounted costs throughout the lifetime of the decommissioning project. ”

7. A strong historical relationship with nuclear weapons proliferation is undeniable. Currently we are seeing this global effects of this enacted in the cases of North Korea and Iran. Shared fuel enrichment with weapons is common.

8. The nuclear fuel cycle is vulnerable to catastrophic terrorist acts through attacks on plant facilities, creation of primitive nuclear weapons, and spread of toxic plutonium. Significant security demands and restrictions of freedom must be accepted by the public to allow both the transport of fuels and waste and the operation of plants.

9. There has been a long history of leakages and accidents including the Chernobyl catastrophe.



3. POTENTIAL CONTRIBUTION TO THE AUSTRALIAN GRID LOAD

3.1. Grid Demand Patterns

Figure 4 Diurnal variation in demand on peak days, showing a minimum at between 6000 and 7500 MW. The peak output was 12883 MW.

New South Wales (NSW) has a intermediate climate in the Australian mainland geography, and constitutes 1/3 of the Australian grid load. Because data for NSW is readily available, it will be used as a typical example for a future mainland Australian energy economy. Away from the mainland, the State of Tasmania is already well served by renewable hydroelectricity and wind. However, the absolute value of the grid load is less of a practical issue than the seasonal and diurnal variation. There is considerable uncertainty about what the Australian grid load pattern might be by mid-century. It could be profoundly influenced by energy efficiency measures, including important ones of seasonal influence such as more effective thermal insulation of buildings and the continued introduction of air conditioning in summer. Future restrictions on gas supply may return building heating to the electricity sector using reverse cycle technology, and the introduction of plug-in hybrid vehicles may increase electricity requirements. Although most envisaged changes seem to favour a relative increase in summer load by mid-century, an assumption than the seasonal grid load is unchanged will be used, even though this constitutes a worst case scenario for a solar-powered grid. To further avoid the suggestion of bias, this paper will use the NSW grid load pattern supplied by NEMMCO for the year 2005 (NEMMCO, 2006) as a basis for discussion, but it should be emphasised that current demand management off-peak measures, created expressly to favour night loads to support coal base load, could be significantly altered to better favour solar daytime operation as the preferred off-peak rate period.



The NSW grid monthly outputs presented in figures 4 and 5 suggest that without deviation from pure base load operation, one could put a maximum of 5400 MW of pure base load capacity into the NSW grid. The NSW grid itself had a capacity factor in 2005 of 66% based on a peak generation of 12883 MW in that year, so an ideal base load generator at 5400 MW could deliver 5400/(12883*0.66) or 63.4% of the State’s electricity. However, as we will see in the next section, not only are base load generators not ideal, but what we need is output that follows the load.

Figure 5. Diurnal variation on lowest demand days in each month, showing a minimum between 5400 and 6500 MW. The maximum base load level would be set at 5400 MW.

3.2. Contribution of Wind to Grid Electricity

Fig 6 shows the calculated output of wind, solar and nuclear plants in NSW. It is necessary to model wind as a ‘niche’ system, which for grid stability and other reasons is pegged by government recommendation at the maximum value of about 50% of minimum grid load in Fig. 5, or 2700 MW (Outhred, 2006). Further, it is assumed that the CF for wind is 30% in this paper inclusive of mechanical reliability. The upper bound of wind electricity supply to the grid in this scenario is (2700 x 0.3)/(12883 x 0.634) = 0.099 or about 10%. This may appear small, but it is about 15 times the current NSW wind capacity identified by the Australian Wind Energy Association. To achieve a higher contribution, the provision of storage is necessary for two reasons. First, it is necessary to improve the stability of output so as to allow greater grid market share. Second, about 12 hours storage would allow reliable production throughout the year at a level similar to that of solar. If these improvements could be achieved in the future, at reasonable cost, then much larger amounts of wind could be imbedded in the grid system. This study did not uncover a means of such low cost storage, except in a few parts of the world where pumped storage was available near hydroelectric schemes, and that has a typical turn around efficiency of 70%.



When combined with solar, the lower cost per peak watt of wind (having no storage and a lower CF than solar with storage) may be beneficial because the flexible storage of solar can back up a modest amount of variable wind and it can be treated as firm capacity. It is possible larger amount of wind could be used than the 10% of grid load shown in Fig. 6, but this would need a more detailed minute by minute model for a specific site or group of sites to accurately optimise.

3.3. Contribution of Solar to Grid Electricity

In Fig, 6, both solar and nuclear plants are assumed to have similar turbines with peak output equal to total grid system maximum load. Current CLFR solar plants have a deeper winter drop than the ALFR shown, but they will be replaced by the ALFR before any such large plants are constructed in NSW. Other types of solar collector, such as an EW parabolic trough or a tracking dish collector would also yield similar seasonal variations. Solar plant availability is conservatively assumed to be 94%, lower than the 98% achieved by parabolic trough plants in the USA in recent years but in line with NREL assumptions (NREL, 2003). The figure is higher than nuclear because the modular nature of the solar technology reduces the frequency of whole plant shut-downs, and because there is no need for periodic refuelling operations. The gross annual CF of the ALFR solar plant is 72%, from which must be subtracted dumped as unusable excess, resulting in a useful CF of 64% compared to 56% for nuclear, the latter having to wind down each night. An important point is that the calculations show that solar can supply up to 97.5% of the annual grid load, using a similar turbine capacity to that used by nuclear. Solar and wind together can supply 97.9% with a composition 90% solar and 10% wind, almost the same, but an analysis on a minute by minute basis may be necessary to confirm that there is a any advantage. The combination of solar + wind could to be cheaper than solar alone; the peak watt cost of wind is lower as is the capacity factor, but if solar provides storage backing wind, a good part of the wind output can be used as valuable firm capacity. Whether or not this is a good idea depends upon the site output characteristics.

3.4. Contribution of Nuclear to Grid Electricity

Nuclear plants are almost always run in a base load condition to lower their cost; this means having the same output year round. If this is strictly done, the NSW plants would have to be sized at the minimum grid load of 5400 MW. However, the assumption of a base load capacity factor of 85% leads to a net system CF of 54% of the State’s electricity. This clearly implies that not only is another technology needed, but that whatever that technology is, it must carry the whole peaking supply burden at great cost if nuclear occupies base load. It might be more cost effective for solar plant, as an example, to carry the whole load and not just the highly variable portion over a nuclear base load. In order to be a bigger player than this, nuclear would have to carry its share of the costs of flexibility and abandon the pure base load market. Let us imagine nominal nuclear plant with the same peak turbine capacity as the grid load: a fully nuclear economy. To meet the peak load in the NSW model, the plants must be numerous enough to supply 12900 MW at peak. Because the grid load is variable, an ideal base load plant with 100% availability would only be able to supply energy when the grid needed it, and could only achieve a CF of 66%. (France uses some partial load following, which drops nuclear CF to 75%). Because nuclear plants almost always operate at full capacity, a lifetime CF of 85% is the same as a lifetime availability of 85%. Breakdowns would be expected to happen randomly, not just in quiet night periods, so we should thus expect the 85% lifetime plant to deliver power with a CF of 0.85 x 0.66 or 56%, and supply 85% of the electricity required by NSW. The cost of nuclear must be raised by the ratios of the capacity factors for the load-following to base load regimes. The cost of nuclear will therefore rise as its contribution rises above pure base load. This means that the cost of nuclear has been significantly underestimated for large scale implementation in the economy to replace coal or displace solar. Nuclear plants can operate at higher



outputs if there is a reliable external market for excess electricity, but on the premise that the NSW figures are representative of Australia, Australia would have no such opportunity. The annual output of such a nuclear plant is modelled in Fig. 5, which also shows the output from modelled solar, wind and nuclear plants relative to seasonal grid load. This issue also would apply to deep geothermal, which is also intended to run as base load. The price of load following geothermal will be significantly higher than for base load. However, deep geothermal availability is unknown.

Fig. 6. Solar and nuclear outputs to the grid for load-following plants where the peak system capacity is equal to the peak annual grid load of 12883 MW, except for wind which is sized to 10% of peak. The nuclear option can supply 85% of grid requirements. The solar scenario is based upon northern NSW Typical Mean Year climate data, and can supply 97.5% of grid requirements after excess is dumped. Wind can supply 15% of grid supply on its own, based on the long term seasonal pattern measured at Canberra airport. If wind is combined with solar plant downsized by 10% to keep the peak combined capacity at 12883 MW, the two can supply 97.9% at lower cost than pure solar.

4. NET ENERGY YIELD ANALYSIS

An initial estimate of the nuclear fuel embodied energy and CO2 burden was calculated during the initial preparation of this paper, but then a more recent website calculator was located for this (WISE, 2004) was found for nuclear using up-to-date burn up rates. The WISE calculator with inputs for uranium ore 50% from Ranger and 50% for Olympic Dam, and using a low temperature turbine with 33% efficiency (also used for the solar plant). While the WISE site is clearly not one likely to be allied to the nuclear industry, the site appears to be reliable in its calculations, and the energy investment results agreed closely with the author’s own estimate for a PWR, although about 2/3 of a full chain analysis by Proops et al (1996). Fig. 7 shows the calculated relative energy inputs for the solar and nuclear cases. The large energy requirement in nuclear fuel manufacture would have strong upward pressure on Australian emissions if fossil fuel were used for the export of fuel.



Fig. 7. Relative primary energy input into 1000 MW solar and nuclear systems calculated by the author. It can be seen that by far the dominating input for nuclear is fuel manufacture; for solar it is the steel and glass used in the array construction. Nuclear would have a better primary energy balance than solar were it not for the intensive use of energy in fuel manufacture. Categories with low input are not visible.

The Energy Yield Ratio (EYR) may be defined as lifetime energy delivered by the system divided by the energy invested to construct and maintain the system over its lifetime (Richards and Watt, 2004). In this paper, the primary thermal energy was used as the basis of the EYR rather than dividing thermal kWh by electrical kWh, because in most technologies the energy inputs are a mix of electrical and thermal. This can be seen in Appendix 2 for the nuclear case. The electrical energy inputs are accounted for by equating 1 kWh (thermal) = 0.35 kWh (electrical). Table 1. EYR Ratios

Technology Energy Yield Ratio

Solar (SHP, storage) 77 Nuclear (LWR) 30

Wind Vestas 90 (onshore) 105 These primary energy figures can be used to develop energy yield ratios. Table 1 shows the energy and emissions figures for the three calculated 1000 MW plants. To put these in perspective against small systems, Richards and Watt (2004) describe EYR figures for solar PV which range from 2.8 for a small European system with a lifetime of 20 years, to 11.7 for a large system in Australia lasting 30 years.



5. DYNAMICS OF TECHNOLOGY INTRODUCTION

Once it is decided that there are available technologies which have sufficiently low pollution, an important issue arises as to how much clean energy once can introduce into the economy over the next 45 year for a given amount of money. This depends upon several factors, including the plant lifetime, the net energy balance during operation. However, when constructing a system of many generators, the dynamic effects of construction time, staged introduction and system lifetime assume some importance. A dynamic analysis is presented in Fig. 8. In this artificial scenario, a 1000 MW of nuclear plant or solar plant with storage is built every three years until 13000 MW of capacity is reached in 2039 for solar and 2040 for nuclear. In the early years, wind is allowed expand at 1000 MW every three years, but the wind capacity is limited by grid stability issues to 2400 MW peak in the NSW market, and after the first 9 years, further increases are curtailed. Even were grid stability solved, the short lifetime of 20 years would allow only replacement of old plants after 20 years. Although this situation does not emerge in the traditional 20 year spreadsheet, it most definitely affects the amount of investment as a steady state supply required in later years. This graph suggests that the wind industry not only needs storage technology, but attention to extended plant lifetime. Both Solar and Nuclear have longer lifetimes and can ultimately use this to create more clean energy for a given societal investment. Fig. 8 compares the cumulative energy obtained out to 2070. This includes both the grid load CF the technology availability. As initial plants are shut down after 2054, the rate of cumulative generation decreases because of the continued energy investment in new plant. Interestingly, a solar plant, could become a ‘thousand year old axe’, kept useful almost indefinitely by replacement of components. This could decrease new plant costs substantially over decades.

Fig. 8. Calculated annual net output from the three options. The high frequency fluctuations are reductions in net energy output from the system due to the energy required for building 1000 MW new plants. The broader dips in the wind plot are due to the energy required for the replacement of plant every 23 years (including 3 years construction). The large dips in solar and nuclear between 2050 and 2060 are due to replacement of plant also, but this occurs every 40 years. After initial plant replacement, each option settles down to a sustainable characteristic which is indefinitely repeated. In practice, Nuclear gradually feels the effects of



dropping plant availability with age, leading to curvature in the upward output segment, but availability was assumed constant at 85% in this simple model.

Fig. 8. Comparison of useful Solar (after dumping excess) with storage, wind, and an LWR with a lifetime 85% availability, installing 1000 MW of each every three years. Wind is stopped after 2700 MW, and output levels off earlier because the shorter lifetime of 20 years affects net output.

6. GREENHOUSE EMISSIONS FROM SOLAR, WIND AND NUCLEAR

Because Solar, Wind and Nuclear do not combust conventional fossil fuel, the predominant emissions are from energy invested in components or nuclear fuel preparation. This makes it highly important to use a figure which includes long chain process analyses of emissions. Fortuitously, Dey and Lenzen (1999) have performed this long chain work for the Australian economy, and this paper uses their emission factors for various materials and processes such as construction and mining. This report uses an analysis including both materials and process inputs, including fuel preparation, construction, O&M and decommissioning. Practically all of the emissions inputs are related to energy usage in the manufacture of materials and the execution of services. For wind, a comprehensive full chain analysis has been performed by Vestas for a modern 3 MW wind generator (Vestas, 2004), using Australian energy system emissions values (see Table 2), and these results are adopted as integrated figures; the details can be obtained from the original reference. For nuclear and solar, a detailed analysis was performed for the entire system as shown. For the most part, the emissions per kWh produced derived for this paper are lower than in Dey and Lenzen (1999), but the technologies now are more modern. The SHP solar collector systems have very low material usage and low labour usage, while the Vestas wind generator is current state of the art. This paper uses the comparatively high Australian invested emissions figures of Lenzen, and includes estimates of the emissions construction, O&M, decommissioning service areas, so as to make a more accurate relative estimate of net energy supplied to the economy (see next section). The Vestas machines use Australian emissions factors in this paper rather than Danish, and if imported might be even lower. These calculations are for a current nuclear plant; a less materials intensive advanced reactor may do better.



Table 2. Emissions per kWh for various technologies

Technology g CO2-e per kWhel Reference

Solar thermal electricity (SHP, storage) 9.7 This work

Nuclear (LWR) 30.7 This work

Wind (Vestas 90, onshore) 11.7 This work

Supercritical black coal 997 Proops et al, 1996.

Natural Gas Combined Cycle 490 Proops et al, 1996.

Entire Australian Generation System 1224 Lenzen, 1999.

The results suggest that both solar and wind are comparable to each other and lower than nuclear, primarily because of the fuel cycle in nuclear. In practical terms, however, the three technologies in this paper deliver greenhouse savings between 96% - 99% over the current generation system in Australia and thus are similar in their effect on the global warming aspect of environment. The emissions content will decrease further for all of these technologies, as there is more clean generation for construction or fuel. Nuclear would gain greatly from having clean generators to supply energy for its fuel enrichment, while solar and wind would benefit from increased use of more recycled steel and the use of clean electricity in the recycling process. A major issue with enrichment is that enriched fuel processing would require a new reactor in Australia for every 30 - 50 reactors served overseas, and the industry would initially depend upon coal for this power, increasing local emissions.

7. RELATIVE COST

The intention in this section is simply to show that it is time to take solar and wind seriously as replacements for the nuclear market in countries with a sufficient solar resource. Recently the Board of Electricité de France announced it had approved construction of the second advanced European Reactor (EPR) of 1630 MW at Flamanville, Normandy (the first is under construction in Finland) with an estimated cost of EUR 3.3 billion, or A$3442 per peak kW. According the MIT (2003), their base case for a modern reactor assumes that lifetime operating expenses of all types including waste disposal and decommissioning charges are 23% of the kWh cost including administrative costs. Using a financial analysis spreadsheet identical to those being used on current commercial projects, SHP has modelled a future SHP 1000 MW solar plant with pressurised storage in northern NSW. This is currently modelled at A$4060 per peak watt, 18% higher than the Flamanville plant. There is no fuel cost but the percentage of kWh cost associated with total solar operating expenses is estimated at 11.3% of total kWh price. This figure is likely to be higher in some other types of solar plant because of higher cleaning and maintenance requirements. As we have seen in section 2, the effective capacity factor of an ALFR with turbine capacity equal to the peak annual grid load should be 64% or 14.3% better than nuclear at 56%. The ratio of lifetime kWh costs of solar to nuclear would therefore be (4060)*(1.113) / (3442*1.23*1.143) or 0.93 to a first approximation. However, to cover the entire load, nuclear would have to increase capacity to cover the remaining 15% of peak load, so that the capacity factor would now be 0.66/1.15 = 0.57. If fixed costs are assumed to be 75% of total costs, this would increase cost to 1.36 of a base load nuclear operating at 85% capacity factor. The equivalent solar cost is calculated at 1.30 times nuclear if the cost of backup for the 2.5% deficit of energy in winter is assumed to be the obtained at the same cost as solar and 1.33 times if an



additional 2,5% is used for occasional extended cloud periods. Thus the costs of these two technologies should be about the same if no differential subsidies intervene. While it is possible that even newer nuclear designs like the Westinghouse AP1000 and the EPR may be cheaper in large scale production (no AP1000s have been built), there is also strong potential for a similar reduction in solar costs through automation of solar plant reflector and storage manufacture. Projections of solar trough and solar tower costs into the 2025 time frame also shows similar anticipated cost reductions (NREL, 2003).

8. MEETING THE CLIMATE CHALLENGE

We face a range of emissions targets between 400 and 450 ppm to avoid severe climate risk. In this section the allowable technologies in the two cases are discussed.

8.1. CASE 1. 400 ppm by 2050.

This case gives higher climate security and may just be feasible in terns of time frame. For the 400 ppm case, natural gas generation is rationed to 10% but would possibly be more valuable used as a less efficiently used but flexible supplementary fuel at 5% of generation, or as a supplement to solar plant in continuous cloud periods. The simplest modeled case is that of solar alone, which could carry 97.5 % of the load itself at a cost of about 1.33 times advanced EPR nuclear base load generation operating at 85% CF. Solar thermal electricity with storage is a flexible and comprehensive option, but it is at its lowest cost when supplying the largest amount of grid load, which is calculated to be 97.5% when the peak load is sized to the peak turbine capacity. Solar has the capability to supply both base load and peaking functions to the grid so that it can take advantage of both base load and peaking tariffs. For the solar sites modelled, there are small shortfalls in the annual pattern where there are several days of cloud which are beyond the modelled storage capacity. These would be only a few % of annual load, and would be best addressed by an auxiliary biomass or gas fuel boiler attached to the storage system, as would the 2.5 % of shortfall in winter. Thus, the whole electricity system can be supplied by solar with an approximate 5% total backup component consistent with the 400 ppm scenario if backed up by fossil fuel, and at a zero operational emissions level if the backup is biofuel. Solar storage can also help to back up wind generation, which may have capital cost advantages which can be explored by a detailed short time-step model. In general, the solar option is one with decreased climate risk and zero fuel risk. Nuclear, and (like other inherently base load sources such as deep geothermal), is at lowest cost when supplying the underlying base load, which in NSW would allow 56% of the annual load to be supplied at best by nuclear. Supplying in excess of base load is possible, but increases the electricity cost as the CF decreases, to 1.36 times current cost if supplying 100% of the load. If solar and nuclear were to coexist, an open market system would be best to determine system lowest cost, but it would be close to these prices unless there were differential subsidies. In this worst climate case, the excess generation cost over present current base load nuclear is thus likely to be no more than 36%.

8.2. CASE 2: 450 ppm target

This case retains significant climate risk which could easily exceed the cost of the electricity system



For the 450 ppm case we are allowed 35% generation as high efficiency gas. It should be remembered that this gas is used by Hoehne as base load natural gas combined cycle (NGCC) or combined heat and power (CHP) to reduce emissions, not as peaking power. Natural gas is already used predominantly as a base load fuel in Australia in NGCC plants. As peaking power, it would be much lower in contribution because of the poorer efficiency of gas turbines, and probably limited to 20% of grid generation. Nuclear and solar can both take up the remaining base load and peaking role on their own, or in combination with each other, or in combination with other technologies. The reduced market and more variable remaining grid load will reduce nuclear and solar CF and raise the cost of any combination of both solar and nuclear compared to the 400 ppm case, but this will be more than counterbalanced by the lower cost of NCGG generation, so that overall grid generation cost will likely be below that for the 400 ppm case. In the 450 PPM scenario, high efficiency gas (NGCC) baseload at 35% (as recommended by Hoehne) and solar 65% as the variable generation becomes an interesting prospect, acting similarly to a nuclear/solar system, but with less societal risk and an easy upgrade path to an unending solar resource when the gas runs out. If the NGCC could be varied seasonally, and adapt to solar output without compromising efficiency, then the solar plant size can be reduced significantly, saving capital cost. The NCGG would be more efficiently used as separate plants at high efficiency than as direct backup to solar plant at lower efficiency.

9. DISCUSSION

This work addresses the relative suitability of nuclear, wind and solar in Australia as the primary future electricity option. There is not enough uranium fuel, under ten times current reserves, to power the expected global electricity requirement beyond 2056, although there is enough to support a nuclear industry in Australia due to a local uranium fuel abundance. The Australian solar resource is almost unlimited in size and duration. The nuclear industry thus underestimates its own cost significantly in how nuclear might address likely requirements for emissions reduction. For the 400 and 450 scenarios shown, it becomes evident that fossil fuel would not be used as peaking fuel in large amounts and that solar or nuclear would have to take on that role. To cover the complete load, nuclear must be load-following and will be more costly than an 85% CF nuclear base load plant by about 36%. Solar would be about the same cost for the same task, but would have about 5% gas or biofuel backup included in that cost. The cost of a coal plant in NSW including lifetime present value fuel cost (fuel price escalation is assumed to rise with inflation) is estimated at A$3414 (neglecting O&M) for a fleet of plants supplying the entire grid load annually with the NSW grid capacity factor of 66% (TES, 2005). The estimated cost of a solar plant doing the same job in this paper (neglecting O&M) is A$4060, about 19% more, and the nuclear plant almost the same. Of course the O&M and other costs will differ, but recent petrol rises have clearly far outstripped any likely added cost of a solar or nuclear generation response to global warming. We can clearly absorb the costs of a transition to low emissions generation, and this extra cost is not a significant percentage of GDP. The costs assumed for nuclear ignore the many subsidies which are often added to assist nuclear programmes. Investment in nuclear creates and infrastructure with global fuel restrictions which would raise fuel cost greatly by mid-century. Nuclear cost usually assumes considerable government support for important areas such as risk insurance against Chernobyl-like disasters, fuel enrichment, decommissioning and waste disposal. Realistic nuclear pathways, not the once through, entail cost uncertainties and potential dangers to the public not shared by solar. The fact that these risks are uninsurable suggests that insurers think the risk is real, and that the public should be careful about assuming it. These are not the type of costs which should be borne by governments.



Solar thermal electricity with storage is a flexible and comprehensive option, but it is at its lowest cost when supplying a large amount of grid load, which is calculated to be 97.5% when the peak load is sized to the peak turbine capacity. Effectively this means that solar has the capability to supply both base load and peaking functions to the grid, and can therefore be allocated the income for both of these, which is higher than the pure base load rate. Wind without storage could contribute up to 10% of total generation and could be backed up to some degree by solar and hydroelectricity. But wind suffers in total impact due to a short plant lifetime and lack of storage options but may have synergies with solar in some locations.

10. CONCLUSION

The Federal Government is being lobbied to adopt an Australian nuclear future as an approach to reduce global warming. It would seem a peculiar choice for Australia’s energy market to ignore an almost infinite resource and completely safe, locally developed solar technology, so that it can adopt a foreign-designed nuclear alternative which must be globally abandoned for lack of fuel just as global emissions stabilization is achieved. One can expect exposure to fuel price rises if one is a user of nuclear power, but if uranium fuel continues to be exported but not used, then Australia will reap the benefit of any such fuel escalations. If solar displaces uranium from the local market, the maximum balance of payments will be gained, and the maximum number of jobs in the construction of solar plant will also be gained. Solar power has a resource sufficient to supply not only current electricity markets but any in the future, such as those of future electric transport and the supply heat to industrial markets where nuclear is inappropriate. For solar to become the ‘new coal’, storage must be used, and further growth in plant size must take place. The author recognizes that these new technical developments represent a perceived risk to those who provide legislative leadership, but solar is heavily modular easily scalable to drive large turbines. Business overseas has already understood this solar capability and is investing heavily in STE. Nuclear has much more difficult and risky problems, among them back-end costs like waste storage and decommissioning, new more critical plant designs, fuel shortages and price escalation risks. The avoidance of the social downsides of nuclear power - vulnerabilities to terrorism, and involvement in potential proliferation - are difficult to cost, but are immediate in impact and the opportunity to avoid these issues is compelling. It would be a mistake for legislation or large scale subsidy to be promulgated which favours any particular technology over another. As the eminent MIT scholars have pointed out in their criticism of previous nuclear support: “The insulation of investors from many of these risks ….. reduced the cost of capital and led investors to give less weight to regulatory (e.g. construction and operating licenses) and construction cost uncertainty, operating performance uncertainties and uncertainties associated with future oil, gas and coal prices than if they had to bear these cost and performance risks.” The correct task now for governments to create a technology independent environment so that each technology can perform competitively without the government accidentally - or deliberately - advantaging its competitors. It is clear that advanced nuclear and advanced renewable energy may require a significant environmental compensation subsidy (in the form of feed-in laws or carbon trading) in order to compete in a market dominated by coal plant which has been amortised long ago and is simply offsetting fuel cost. As such plants are retired, subsidies can be reduced or eliminated, but what is most important is that one technology does not receive special financial attention, and through this, unfairly dominate the market. A standard subsidy per clean kWh is needed which not only allows competition with new coal, but with old coal. Our company would be pleased to compete against other clean energy manufacturers in such a market environment.



Beyond that, let each technology pay its own costs for meeting radiological and environmental standards, dispatchability, security charges, insurance, fully insured waste disposal, fuel enrichment, and fully insured decommissioning according to the highest community expectations. In this way the relative costs of different technologies will be ascertained in the market. The present size of the aggregated electricity, gas and water sector is 2.5% of Australian GDP. The difference between a conventional new coal plant fleet and a completely clean generation solar or nuclear system suitable for the 400ppm scenario is about 20%, which is a small fraction of 1% of GDP.

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