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4. Outlook: Challenges and Opportunities
This section analyses five sectors that play central roles in energy-water-carbon intersections: stationary energy, transport energy, water systems, land systems and urban systems. The analysis provides the evidence base to support the recommendations described in Section 5, noting that all recommendations are trans-sectoral.
4.1 Stationary energy systems
Situation and outlook: By world standards, Australia has a low-cost stationary energy system. In 2007–08, 76 per cent of Australia’s electricity production (925 PJ or 257 TWh) was generated by the combustion of black and brown coal, with the remainder from gas (16 per cent) and renewable sources (hydro, wind, solar, biomass; 7 per cent) (ABARE, 2010a; Geoscience Australia and ABARE, 2010).
Because of its high reliance on coal, Australia has a relatively high GHG emission intensity in its domestic stationary energy sector compared to other industrialised economies, which have historically made use of greater available hydroelectric resources or deployed nuclear power on a significant scale (see Table 2.1). The stationary energy sector is also a significant water user, consuming about 4 per cent of non-agricultural water (ABS, 2006).
Australia is also a major exporter of fuel for stationary energy: around two-thirds of Australia’s primary energy production is exported, mainly as black coal and uranium (ABARE, 2010a). Since 1986 Australia has been the world’s largest coal exporter, and since 1989 has become one of the largest exporters of natural gas and uranium (ABARE, 2009a; International Energy Agency, 2009b; ABARE, 2010a). In 2008–09, the value of Australian coal and liquefied natural gas (LNG) exports amounted to around $55 billion and $10 billion, respectively (ABARE, 2010a). Both these exports are rising rapidly, largely from global demand spurred by growth in developing countries. Despite the high energy content of exported uranium, its monetary value was significantly lower at about $0.9 billion.
The energy sector is capital-intensive, accounting for around 13 per cent of Australia’s total capital stock. The sector generates 8 per cent of Australia’s Gross Domestic Product (GDP) and employs between 1 and 2 per cent of the Australian work force (ABARE, 2010a).
The future outlook for the Australian stationary energy sector involves a major energy-carbon tension, as reduction of its GHG emissions is critical. There is also an energy-water intersection, through the need to ensure that the significant water requirements for energy generation are met.
Box 4.1 briefly surveys the main technical options available to meet this challenge. Together, these technologies offer a wide choice of possible scenarios, but no single technology can fulfil all requirements alone. The future stationary energy mix will be shaped by wide range of factors including energy-water-carbon intersections and also other economic, environmental and social concerns.
Pathways to meet the energy-carbon challenge: Figure 4.1 illustrates a possible pathway for the Australian stationary energy sector to reduce its GHG emissions to an extent consistent with eventual stabilisation of global atmospheric GHG concentrations at 450 parts per million (ppm) CO2eq. This GHG mitigation scenario involves cuts in Australia’s emissions to 75 per cent of 2000 levels by 2020 and to 10 per cent of 2000 levels by 2050 (Garnaut, 2008). The scenario analysis by the CSIRO Energy Futures group (Paul Graham, pers. comm.; Wright, 2009) determines the minimum-cost pathway to meet the emissions constraint. The scenario shows strong growth in renewable energy technologies (such as wind, solar and geothermal), which make up around three-quarters of Australian stationary energy by 2050 in this scenario. No significant growth is foreseen in the contribution from hydroelectricity because potential Australian resources are essentially already committed. The scenario has a progressive increase in carbon capture and storage from coal and gas from 2020 onward, to make up most of the remaining quarter of stationary energy by 2050. Nuclear energy was not included in this scenario, but similar scenarios which do include nuclear indicate that it becomes cost-effective only after several decades, and even then contributes only a small fraction of total stationary energy. It should be noted that such scenario analysis depends on assumptions about the evolution of technology costs and input costs over time, and is not a prediction of what will actually happen.
Figure 4.1: Scenario to 2050 for a mix of stationary energy technologies consistent with stabilising GHG concentrations at 450 ppm CO2eq. Scenario analysis using the CSIRO Energy Sector Model by the CSIRO Energy Futures group (Paul Graham, pers. comm.). CCS is carbon capture and storage. TWh is terawatt-hours (1012 watt-hours; a unit of energy).
Changes like those indicated in Figure 4.1 will tend to increase power generation costs. For example, a cut in Australia’s GHG emissions to 25 per cent below 2000 levels by 2020 is projected to cost A$185 per household per year (ClimateWorks Australia, 2010), about 0.3 per cent of the average annual income in Australia for full-time employed adults (about $65 000 in 2010). Economic modelling suggests this strong mitigation scenario would have an overall cost to the Australian economy of around 0.1 per cent of annual economic growth to 2020 (Garnaut, 2008).
It is critical to note that cost increases to support emissions reduction are modest relative to growth rates in the economy and can be economically affordable with appropriate development pathways (McKinsey & Company, 2008; Daley and Edis, 2010). These increases in costs must also be seen in the context of two major benefits that they would bring: improved resilience through mitigation of climate change as Australia plays its part in a global effort, and positioning Australia at the leading edge of global changes in the stationary energy sector, with associated opportunities for export of technologies and knowledge.
The challenge in finding a pathway like that in Figure 4.1 will be to develop the appropriate mix of technologies, locations and demand management to maximise cost-effectiveness and minimise GHG emissions, against a background of rising demand for energy. Forecasts (Syed et al, 2007; Geoscience Australia and ABARE, 2010) suggest that total primary energy demand in Australia will increase by 35 per cent to 2030, and electricity demand by 50 per cent, at a growth rate of nearly 2 per cent per year, which is faster than population growth. This increasing demand, combined with the need to restrict carbon emissions, puts even more urgency on the need to rapidly decarbonise Australia’s stationary energy systems.
Energy-water intersections: An important consideration in the stationary energy sector is the water requirement for electric power generation. Lower water availability in southern Australia in coming decades (see Section 2.2) will increase the risk that there will be insufficient water for this purpose, particularly as energy demand increases. Currently, around 270 GL is consumed by the electricity and gas sector, mostly for steam make-up and cooling of coal and gas fired power stations (ABS, 2006; Smart and Aspinall, 2009). When evaporative cooling is employed, 90 per cent of the water consumption of a power station is used for that purpose, as occurs in 65 per cent of the power stations supplying the Australian electricity market. The consumption of 271 GL in 2004–05 is around one-eighth of the water consumed by Australian households (2108 GL) and constitutes 4 per cent of total non-agricultural water consumption (6523 GL; ABS, 2006), making the power generation sector a significant water consumer. Consequently, there are concerns about water availability, quality and location as the power generation industry grows to meet increased demand (Smart and Aspinall, 2009). A non-consumptive water use by the sector is for in-stream flow for hydroelectricity generation, but this flow is returned to the environment after use and is therefore not defined as consumption. In 2004–05 the hydroelectric industry used around 59900 GL of water for this purpose (ABS, 2006).
Major further growth in hydroelectricity in Australia is unlikely (Figure 4.1), so most growth in water demand will come from thermal power stations: coal, gas, solar and geothermal (plus nuclear, if adopted). Each of these technologies will have its own water requirements (Ikeda et al, 2007a; Ikeda et al, 2007b; Smart and Aspinall, 2009). In particular, new-generation, water-cooled, low-emission thermal plants incorporating carbon capture and storage (CCS) are likely to be up to one-third more water-intensive than current technology. Solar thermal and geothermal power plants are also likely to have significant water intensities.
There are many opportunities to address the energy-water challenge, including increasing water use efficiency, recycling plant waste water, dry cooling, use of purified recycled water, saline water cooling, desalination and regional water management schemes (Smart and Aspinall, 2009). The potential for increasing the water efficiency of electricity generation is shown by the fact that the industry has already implemented programs that have reduced water use by up to 15 per cent per MWh (Smart and Aspinall, 2009) without compromising the efficiency of electricity yield.
The available options present different opportunities and challenges. Recycling plant storm water and operational run-off water is a low-energy option (0.002 kWh of electricity per kL of recycled water) that has minimal effect on sent-out electricity efficiency. Greater use of dry cooling can reduce water consumption in thermal power plants by up to 90 per cent. However, dry cooling also reduces the sent-out electricity efficiency by around 2–3 per cent, leading to an increase in GHG emissions per MWh of up to 6 per cent. For a solar thermal power station, the effect of the efficiency penalty is seen in a higher cost of electricity. By their nature solar thermal stations are likely to be sited in high-sunshine areas, which often have low water availability. Use of saline water cooling does not affect sent-out power efficiency, but is usually only economically feasible near the coast. Use of water from coal seam methane extraction may be a future option. Use of purified recycled water as an alternative source of freshwater is becoming more prevalent in Australian power stations and the use of treated sewerage effluent has been studied. Use of desalinated water is an option, but carries with it an energy penalty (with associated GHG emissions) of between 3 and 4.5 kWh of electricity per kL of freshwater produced (GHD, 2003; Watson et al, 2003; Australia Institute, 2005). This means that if desalination were to be used to supply water to a large coal-fired power station, about 1 per cent of the electricity generated would be used by the desalination plant (Smart and Aspinall, 2009).
Where water is used for evaporative cooling, the implied monetary value for that water arising from the extra electricity generated is around $1500 per ML, or even higher for solar thermal systems. This is higher than either urban or irrigation water prices. Coupled with the relatively small fraction of total water consumption involved, this argues against simply phasing out evaporative cooling. Rather, appropriate decision-making methodologies are needed (see Section 5, Recommendation 1).
Given the predicted increase in power demand, the likely overall increase in water consumption of new, lower-GHG generation technologies and the likelihood that Australia will face evermore limited water supplies, research priorities need to include the development of low water-use
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