|Working Group III: Mitigation|
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3.8.6 Technological and Economic Potential
Several studies have attempted to express the costs of power generation technologies on a comparable basis (US DOE/EIA, 2000; Audus, 2000; Freund, 2000; Davison, 2000; Goldemberg, 2000; OECD, 1998b). The OECD data are for power stations that are mainly due for completion in 2000 to 2005 in a wide cross section of countries, and these show that costs can vary considerably between projects, because of national and regional differences and other circumstances. These include the need for additional infrastructure, the trade-off between capital costs and efficiency, the ability to run on baseload, and the cost and availability of fuels. The costs of reducing greenhouse gas emissions will similarly vary both because of variability in the costs of the alternative technology and because of the variability in the costs of the baseline technology. Because of this large variation in local circumstances, the generating costs of studies can rarely be generalized even within the boundaries of one country. Consequently, costs (and mitigation potentials) are highly location dependent. The analysis in this section uses two principle sources of data, the OECD (1998b) data and the US DOE/EIA (2000) data. The latter data are for a single country and may reduce some of the variability in costs seen in multi-country studies.
Tables 3.35a-d are derived from the OECD (1998b) survey which gives data on actual power station projects due to come on stream in 2000 to 2005 from 19 countries including Brazil, China, India, and Russia, together with a few projects for 2006 to 2010 based on more advanced technologies. Data from other sources have been added where necessary and these are identified in the footnote to the tables. The tables present typical costs per kWh and CO2 emissions of alternative types of generation expected for 2010. Tables 3.35a and 3.35b use a baseline pulverized coal technology for comparative purposes. Table 3.35a contains data for Annex I countries (as defined in the UN Framework Convention on Climate Change) in the OECD dataset, and Table 3.35b contains data for non-Annex I countries. In addition to coal, the table gives projected costs for gas, nuclear, CO2 capture and storage, PV and solar thermal, hydro, wind, and biomass. In the baseline, costs and carbon emissions are an average of the coal-fired projects in the OECD database for Annex I/non-Annex I countries respectively, with flue gas desulphurization (FGD) included in all Annex I cases and in around 20% of the non-Annex I cases. Other technologies are then compared to the coal baseline using cost data from the OECD database and other sources. In Tables 3.35c and 3.35d, the baseline technology is assumed to be CCGT burning natural gas, and costs and emissions are similarly calculated for Annex I and non-Annex I countries.
In the tables, the first column of data gives the generation costs in USc/kWh and the emissions of CO2 in grams of carbon per kWh (gC/kWh) for the baseline technology and fuel, coal, and gas, respectively. The subsequent columns give a range of possible generation options, and the costs and emissions for alternative technologies that could be used to reduce C emissions over the next 20 years and beyond. Additionally, it might be noted that the non-Annex I baseline coal technology is cheaper than that for Annex I countries (both based on the costs of power stations under construction) and that CO2 emissions (expressed as gC/kWh) are higher. This reflects the lower efficiencies of power stations currently being built in non-Annex I countries. The costs of reducing greenhouse gas emissions in the mitigation options varies both because of variability in the costs of the alternative technology and because of the variability in the costs of the baseline technology.
Tables 3.35a-d also present estimates of the CO2 reduction potential in 2010 and 2020 for the alternative mitigation options. Baseline emissions of CO2 are used, derived from projections of world electricity generation from different energy sources (IEA, 1998b). The IEA projections essentially are enveloped by the range of SRES marker scenarios for the period up to 2020. The IEA projections were used as the baseline because of their shorter time horizon and higher technology resolution. In the tables, it is assumed that a maximum of 20% of new coal baseline capacity could be replaced by either gas or nuclear technologies during 2006 to 2010 and 50% during 2011 to 2020. Similarly, it is assumed that a maximum of 20% of new gas capacity in 2006 to 2010 and 50% in 2011 to 2020 could be displaced by mitigation options. These assumptions would allow a five-year lead-time (from the publication of this report) for decisions on the alternatives to be made and construction to be undertaken. It is assumed that the programme would build up over several years and hence the maximum capacity that could be replaced to 2010 is limited. After 2010 it is assumed that there will be practical reasons why half the new coal capacity could not be displaced. The rate of building gas or nuclear power stations that would be required using these assumptions should not present problems. For nuclear power, the rate of building between 2011 and 2020 would be less than that seen at the peak for constructing new nuclear plants. For gas, the gas turbines are factory made, so no problems should arise from increasing capacity, and less would be required in terms of boilers, steam turbines, and cooling towers than the coal capacity being replaced. For renewables such as wind, photovoltaics (PV) and biomass, maximum penetration rates were derived from the Shell sustainable growth scenario (Shell, 1996) and applied to replace new coal or gas capacities. For wind and PV, these penetration rates imply substantial growth, but are less than what could be achieved if the industries continued to expand at the current rate of 25% per year until 2020. For biomass, most of the fuel would be wood process or forest waste. Some non-food crops would also be used. The introduction of CO2 capture and storage technology would require similar construction processes as for a conventional power plant. The CO2 separation facilities would need additional equipment but, in terms of physical construction, involve no more effort than, say, the establishment of a similar scale of biomass gasification plant. CO2 storage facilities would be constructed using available oil/gas industry technology and this is not seen to be a limiting factor. Storage would be in saline aquifers of depleted oil and gas fields. For CO2 capture and storage, it is assumed that pilot plants could be operational before 2010, and the mitigation potential is put at 210MtC each for coal and gas technologies. It is assumed, arbitrarily, that these would be in Annex I countries. For 2020, the total mitigation potential is put at 40200MtC, split equally between coal and gas, and between Annex I and non-Annex I countries. Again, this is somewhat arbitrary, but reflects, on the one hand, the potential to move forward with the technology if no major problems are encountered, and, on the other, the potential for more extended pilot schemes. It is assumed, for simplicity, that fuel switching, from coal to gas or vice versa, would not occur in addition to CO2 capture and storage, although this would be an extra option.
The tables show that the reduction potential in 2020 is substantially higher than in 2010, which follows from the assumptions used and reflects the time taken to take decisions and, especially in the case of renewables and CO2 capture and storage, to build up manufacturing capacity, to learn from experience, and to reduce costs. The tables show that each of the mitigation technologies can contribute to reducing emissions, with nuclear, if socio-politically desirable, having the greatest potential. Replacement of coal by gas can make a substantial contribution as can CO2 capture and storage. Each of the renewables can contribute significantly, although the potential contribution of solar power is more limited. The potential reductions within each table are not addable. The alternative mitigation technologies will be competing with each other to displace new coal and gas power stations. On the assumption about the maximum displacement of new coal and gas power stations (20% for 2006 to 2010, 50% for 2011 to 2020), the maximum mitigation that could be achieved would be around 140MtC in 2010 and 660MtC in 2020. These can be compared with estimated and projected global CO2 emissions from power stations of around 2400MtC in 2000, 3150MtC in 2010 and 4000MtC in 2020 (IEA, 1998b).
In practice, a combination of technologies could be used to displace coal and natural gas fired generation and the choice will often depend on local circumstances. In addition to the description in the tables, oil-fired generation could also be displaced and, on similar assumptions, there is a further mitigation potential of 10MtC by 2010 and 40MtC by 2020. Furthermore, in practice not all of the mitigation options are likely to achieve their potential for a variety of reasons unforeseen technical difficulties, cost limitations, and socio-political barriers in some countries. The total mitigation potential for all three fossil fuels from power generation, allowing for potential problems, is therefore estimated at about 50-150MtC by 2010 and 350-700MtC by 2020.
In contrast to the OECD data which span a wide range reflecting local circumstances, Table 3.35e presents costs for the USA, mainly based on data used in the Annual Energy Outlook of the US Energy Information Agency (US DOE/EIA, 2000). By and large, the mitigation costs fall in the range of costs given in Tables 3.35a-d. The electricity generating costs are based on national projections of utility prices for coal and natural gas, while capital costs and generating efficiencies are dynamically improving depending on their respective rates of market penetration. The table indicates that once sufficient capacities have been adopted in the market place, coal-fired integrated gasification combined cycle power stations would have similar costs but lower emissions than the pulverized fuel (pf) power station (because of its higher efficiency). In many places, gas-fired CCGT power stations offer lower cost generation than coal at current gas prices and produce around only half the emissions of CO2. Data on CO2 capture and storage have been taken from IEA Greenhouse Gas R & D Programme studies (Audus, 2000; Freund, 2000; Davison, 2000). This could reduce emissions by about 80% with additional costs of around 1.5c/kWh for gas and 3c/kWh for coal pf and 2.5c/kWh for coal IGCC. In the EIA study, nuclear power is more expensive than coal-fired generation, but generally less than coal with carbon capture and storage. Wind turbines can be competitive with conventional coal and gas power generation at wind farm sites with high mean annual speeds. Biomass can also contribute to GHG mitigation, especially where forestry residues are available at very low costs (municipal solid waste even at negative costs). Where biofuel is more costly, either because the in-forest residue material used requires collection and is more expensive or because purpose grown crops are used, or where wind conditions are poorer, the technologies may still be competitive for reducing emissions. Photovoltaics and solar thermal technologies appear expensive against large-scale power generation, but will be increasingly attractive in niche markets or for off-grid generation as costs fall.
Table 3.35e also gives estimated CO2 emissions and mitigation costs compared to either a coal-fired pf power station or a gas-fired CCGT. For the coal base-case, it is projected that in 2010 under assumptions of improved fossil fuel technologies, an IGCC would offer a small reduction in emissions at positive or negative cost. A gas-fired CCGT has generally negative mitigation costs against a coal-fired pf baseline, reflecting the lower costs of CCGT in the example used. CO2 capture and storage would enable deep reductions in emissions from coal-fired generation but the cost would be about US$100-150/tC depending on the technology used. Gas-fired CCGT with CO2 capture and storage appears attractive, but this is principally because switching to CCGT is attractive in itself. Nuclear power mitigation costs are in the range US$50-100/tC when coal is used as the base for comparison. It is uncertain whether there would be sufficient capacity available for wind or biomass to deliver as much electricity as could be produced by fossil fuel-fired plants, but certainly not at the low costs shown in Table 3.35e.
If a gas-fired baseline is assumed, most of the mitigation options are found to be more expensive. CO2 capture and storage appears relatively attractive, achieving deep reductions in emissions at around US$150/tC avoided. Wind, biomass, and nuclear could be attractive options in some circumstances. Other options show higher costs. PV and solar thermal are again expensive mitigation options, and, as noted above, are more suited to niche markets and off-grid generation.
The section on energy sources indicates that there are many alternative technological ways to reduce GHG emissions, including more efficient power generation from fossil fuels, greater use of renewables or nuclear power, and the capture and disposal of CO2. There are also opportunities to reduce emissions of methane and other non-CO2 gases associated with energy supply. In general, this new review reinforces the conclusions reached in the SAR, as discussed in Section 3.8.2.
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