IPCC Fourth Assessment Report: Climate Change 2007
Climate Change 2007: Working Group III: Mitigation of Climate Change

4.4.1. Carbon dioxide emissions from energy supply by 2030

A few selected baseline (IEA 2006b, WEO Reference; SRES A1; SRES B2 (Table 4.1); ABARE Reference) and policy mitigation scenarios (IEA 2006b, WEO Alternative policy; ABARE Global Technology and ABARE Global Technology +CCS) out to 2030 illustrate the wide range of possible future energy-sector mixes (Figure 4.25). They give widely differing views of future energy-supply systems, the primary-energy mix and the related GHG emissions. Higher energy prices (as experienced in 2005/06), projections that they will remain high (Section 4.3.1) or current assessments of CCS deployment rates (Section 4.3.6) are not always included in the scenarios. Hence, more recent studies (for example IEA 2006b, IEA 2006d; Fisher, 2006) are perhaps more useful for evaluating future energy supply potentials, though they still vary markedly.


Figure 4.25: Indicative comparison of selected primary energy-supply baseline (reference) and policy scenarios from 2004 to 2030 and related total energy-related emissions in 2004 and 2030 (GtCO2-eq)

Source: Based on IEA, 2006b; IPCC, 2001; Price and de la Rue du Can, 2006; Fisher, 2006.Note: The IEA (2006b) Beyond Alternative Policy scenario (not shown) depicts that energy-related emissions could be reduced to 2004 levels.

The ABARE global model, based on an original version produced for the Asia Pacific Partnership (US, Australia, Japan, China, India, Korea) (Fisher, 2006), is useful for mitigation analysis as it accounts for both higher energy prices and CCS opportunities. However, it does not separate ‘modern biomass’ from ‘other renewables’, and the modellers had also assumed that CCS would play a more significant mitigation role after 2050, rather than by the 2030 timeframe discussed here. The reference case (‘Ref’ in Figure 4.25) is a projection of key economic, energy and technology variables assuming the continuation of current or already announced future government policies and no significant shifts in climate policy. The Global Technology scenario (ABARE ‘Tech’) assumed that development and transfer of advanced energy-efficient technologies will occur at an accelerated rate compared with the reference case. Collaborative action from 2006 was assumed to affect technology development and transfer between several leading developed countries and hence lead to more rapid uptake of advanced technologies in electricity, transport and key industry sectors. The ‘Tech+CCS’ scenario assumed similar technology developments and transfer rates for electricity, transport and key industry sectors, but in addition CCS was utilized in all new coal- and gas-fired electricity generation plant from 2015 in US, Australia and Annex I countries and from 2020 in China, India and Korea.

A 2030 energy supply and flow scenario (partly based on SRES B2) (Figure 4.26) illustrates the business-as-usual developments towards more renewable energy and fossil-fuel shifts already incorporated in the baseline by comparing the diagram with similar 2004 flows (Figure 4.4). Global energy resource flows and carriers to meet an assumed 2030 total primary energy demand of 660 EJ and final (consumer) energy demand of almost 500 EJ/yr are presented. Estimated CO2 emissions and remaining available reserves of coal, gas, oil and uranium by this time are also shown.


Figure 4.26: Predicted world energy sources to meet growing demand by 2030 based on updated SRES B2 scenario.

Source: IPCC, 2001; IIASA 1998

Note: Related CO2 emissions from coal, gas and oil are also shown, as well as resources in 2004 (see Figure 4.4) and their depletion between 2004 and 2030 (vertical bars to the left). The resource efficiency ratio by which fast-neutron technology increases the power-generation capability per tonne of natural uranium varies greatly from the OECD assessment of 30:1 (OECD, 2006b). In this diagram the ratio used is up to 240:1 (OECD, 2006c).

Based on the WEO 2004 Reference scenario (IEA 2004a), emissions data for 2030, as used in the baseline below in further analyses, were assumed to be just over 39 GtCO2 (10.6 GtC) (Table 4.6).

Table 4.6: Estimated carbon dioxide emissions from fossil-fuel use in the energy sector for 2002 and 2030 (MtCO2 /yr).

 2002 2030 
Transport (includes marine bunkers) 5999 10631 
Industry, of which:  9013 13400 
Electricity   4088 6667 
Heat: - coal 2086 2413 
- oil 1436  2098  
- gas 1403 2222 
Buildings, of which:  8967 14994 
Electricity   5012 9607 
Heat: - coal 495 356 
- oil 1841 2693 
- gas 1618 2338 
Total   23979a 39025 

a WEO, 2006 (IEA 2006b, unavailable at the time of the analysis) gives total CO2 emissions as 26,079 MtCO2 for 2004

Source: Price and de la Rue du Can, 2006.

4.27) showing that under favourable circumstances, and given possible future carbon charge additions, all technologies can be economically justified as a component in a diversified energy technology portfolio.

Construction cost assumptions ranged between 1000 and 1500 US$/kWe for coal plants; 400 and 800 US$/kW for CCGT; 1000 and 2000 US$/kW for wind; 1000 and 2000 US$/kW for nuclear and 1400 and 7000 US$/kW for hydro. Capacity factors of 85% were adopted for coal, gas and nuclear as baseload; 50% for hydro; 17 to 38% for onshore wind-power plants, and 40 to 45% for offshore wind. The costs of nuclear waste management and disposal, refurbishing and decommissioning were accounted for in all the studies reviewed, but remain uncertain. For example, decommissioning costs of a German pressurized water reactor were 155 €/kW, being 10% of the capital investment costs (IEA/NEA, 2005). A further study, however, calculated life-cycle costs of nuclear power to be far higher at between 47 and 70 US$/MWh by 2030 (MIT, 2003). Another cost comparison between coal, gas and nuclear options based upon five studies (WNA, 2005b) showed that nuclear was up to 40% more costly than coal or gas in two studies, but cheaper in the other three. Such projected costs depend on country- and project-specific conditions and variations in assumptions made, such as the economic lifetime of the plants and capacity factors. For example, nuclear and renewable energy plants could become more competitive if gas and coal prices rise and if the externality costs associated with CO2 emissions are included.

In this regard, a European study (EU, 2005) evaluated external costs for a number of power-generation options (Figure 4.28) emphasizing the zero- or low-carbon-emitting benefits of nuclear and renewables and reinforcing the benefits of CHP systems (Section 4.3.5) (even though only less efficient, small-scale CHP plants were included in the analysis). This comparison highlights the value from conducting full life-cycle analyses when comparing energy-supply systems and costs (Section 4.5.3).

A summary of cost-estimate ranges for the specific technologies as discussed in Section 4.3 is presented in Table 4.7. Costs and technical potentials out to 2030 show that abundant supplies of primary-energy resources will remain available. Despite uncertainty due to the wide range of assumptions, renewable energy fluxes and uranium resources are in sufficient supply to meet global primary-energy demands well past 2030 (Table 4.7). Proven and probable fossil-fuel reserves are also large, but concern over environmental impacts from combusting them could drive a transition to non-carbon energy sources. The speed of such a transition occurring depends, inter alia, on a number of things: how quickly investment costs can be driven down; confirmation that future life-cycle cost assessments for nuclear power, CCS and renewables are realistic; true valuation of external costs and their inclusion in energy prices; and what policies are established to improve energy security and reduce GHG emissions (University of Chicago, 2004).