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

4.4.3 Evaluation of costs and potentials for low-carbon, energy-supply technologies

As there are several interactions between the mitigation options that have been described in Section 4.3, the following sections assess the aggregated mitigation potential of the energy sector in three steps based on the literature and using the World Energy Outlook 2004 ‘Reference’ scenario as the baseline (IEA, 2004a):

  • The mitigation potentials in excess of the baseline are quantified for a number of technologies individually (Sections
  • A mix of technologies to meet the projected electricity demand by 2030 is compiled for OECD, EIT and non-OECD/EIT country regions (Section 4.4.4) assuming competition between technologies, improved efficiency of conversion over time and that real-world constraints exist when building new (additional and replacement) plants and infrastructure.
  • The interaction of the energy supply sector with end-use power demands from the building and industry sectors is then analysed (Section 11.3). Any savings of electricity and heat resulting from the uptake of energy-efficiency measures will result in some reduction in total demand for energy, and hence lower the mitigation potential of the energy supply sector.

Mitigation in the electricity supply sector can be achieved by optimization of generation plant-conversion efficiencies, fossil-fuel switching, substitution by nuclear power (Section 4.3.2) and/or renewable energy (4.3.3) and by CCS (4.3.6). These low-carbon energy technologies and systems are unlikely to be widely deployed unless they become cheaper than traditional generation or if policies to support their uptake (such as carbon pricing or government subsidies and incentives) are adopted.

The costs (Table 4.7) and mitigation potentials for the major energy-supply technologies are compared and quantified out to 2030 based on assumptions taken from the literature, particularly the recent IEA Energy Technology Perspectives (ETP) report (IEA, 2006a). The assessment of the electricity-supply sector potentials are partly based on the TAR assessment[2] but use more recent data and revised assumptions. Heat and CHP potentials (Section 4.3.5) were difficult to assess as reliable data are unavailable. For this reason the IEA aggregates commercial heat with power (IEA, 2004a, 2005a, 2006b). An estimate of the potential mitigation from increased CHP uptake by industry by 2050 was 0.2–0.4 GtCO2 (IEA, 2006a), but is uncertain so heat is not included here.

Table 4.7: The technical potential energy resource and fluxes available, potential associated carbon and projected costs (US$ 2006) in 2030 for a range of energy resources and carriers.

Energy resources and carriers Technical potential EJa Approximate inherent carbon (GtC) Present energy costsc US$ (2005) Projected costs in 2030 Additional references 
Investment US$/Wed Generation US$/MWh 
Oil 10,000-35,000e 200-1300 ~9/GJ ~50/bbl ~48/MWh n/a 50-100 Wall Street Journal, daily commodity prices 
Natural gas 18,000-60,000 170-860 ~5-7/GJ ~37/MWh 0.2-0.8 40-60 +CCS 60-90 EIA/DOE, 2006 IPCC, 2005 
Coal 130,000 3500 ~3-4.5/GJ ~20/MWh 0.4-1.4 40-55 +CCS 60-85 EIA/DOE, 2006 IPCC, 2005 
Nuclear power 7400 (220,000)f *b 10-120 1.5-3.0 25-75 IAEA, 2006 Figures 4.27, 4.28 
Hydro > 10MW 1250 20-100/MWh 1.0-3.0 30-70   
Solar PV 40,000 250-1600/MWh 0.6-1.2 60-250   
Solar CSP 50 120-450/MWh 2.0-4.0 50-180   
Wind 15,000 40-90 MWh 0.4-1.2 30-80   
Geothermal 50 40-100/MWh 1.0-2.0 30-80   
Ocean large 80-400/MWh 70-200   
Biomass -  Modern 9 6000 30-120/MWh 0.4-1.2 30-100   
heat and power     8-12/GJ       
Biofuels 1.2 8-30/GJ 23-75 c/l Chapter 5, Figure 5.9 
Hydrogen carrier 0.1 50/GJ US NAE, 2004 


a From Table 4.2. Generalized potential for extractable energy: for fossil fuels the remaining extractable resources; for renewable energy likely cumulative by 2030

b * = small amount

c Prices volatile. Include old and new plants operating in 2006. Electricity costs for conversion efficiencies of 35% for fossil, nuclear and biomass

d Excluding carbon dioxide capture and storage

e Includes probable and unconventional oil and gas reserves

f At 130 US$/kg and assuming all remaining uranium, either used in once-through thermal reactors or recycled through light-water reactors and in fast reactors utilizing depleted uranium and the plutonium produced (in parentheses)

Source: Data from IEA, 2005a; IEA, 2006b; Johansson et al., 2004; IEA, 2004a; Fisher, 2006; IIASA/WEC, 1998; MIT, 2003.

The 2030 electricity sector baseline (Table 4.8; IEA, 2004a) was chosen because the SRES B2 scenario (Figure 4.26) provided insufficient detail and the latest WEO (IEA, 2006b) had not been published at the time. Estimates of the 2030 global demand for power are disaggregated for OECD, EIT, and non-OECD/EIT regions. The WEO 2004 baseline assumed that the 44% of coal in the power-generation primary fuel mix in 2002 would change to 42% by 2030; oil from 8% to 4%; gas 21% to 29%; nuclear 18% to 12%; hydro would remain the same at 6% (using the direct equivalent method); biomass 2% to 4%, and other renewables 1% to 3%.

Table 4.8: Baseline data from the World Energy Outlook 2004 Reference scenario.

 Primary-energy fuel consumed for heat and electricity production in 2030 (EJ/yr) Primary-energy fuel consumed for electricity in 2030a (EJ /yr) Final electricity demand in 2030 (TWh/yr) Increase in new power demand 2002 to 2030 (TWh) Total emissions from electricity in 2030 (GtCO2-eq/yr) 
OECD 118.6 115.4 14,244 4,488 5.98 
EIT 29.3 22.1 2,468 983 1.17 
Non-OECD 128.5 125.3 14,944 10,111 8.62 
World 276.4 262.8 31,656 15,582 15.77 

a Final electricity generation was based on the electrical efficiencies calculated from 2002 data (IEA, 2004a Appendix 1) including a correction for the share of final heat in the total final energy consumption (see Chapter 11).

Source: IEA, 2004a.


Figure 4.27: Projected power-generating levelized costs for actual and planned coal (C), gas (G) nuclear (N), wind (W) and hydro (H) power plants with assumed capital interest rates of 5 or 10%.

Source: IEA/NEA, 2005.

Notes: Bars depict 10 and 90 percentiles and lines extend to show minimum and maximum estimates. Other analyses provide different cost ranges (Table 4.7), exemplifying the uncertainties resulting from the discount rates and other underlying assumptions used.


Figure 4.28: External costs (€/MWh) of current and more advanced electricity systems associated with emissions from the operation of the power plant and the rest of the fuel-supply chain (EU, 2005). ‘Rest’ is the external cost related to the fuel cycle (1 € = 1.3 US$ approximately).

This analysis quantifies the mitigation potential at the high end of the range for each technology by 2030 above the baseline. It assumes each technology will be implemented as much as economically and technically possible, but is limited by the practical constraints of stock turnover, rate of increase of manufacturing capacity, training of specialist expertise, etc. The assumptions used are compared with other analyses reported in the literature. Since, in reality, each technology will be constrained by what will be happening elsewhere in the energy-supply sector, they could never reach this total ‘maximum’ potential collectively, so these individual potentials cannot be directly added together to obtain a projected ‘real’ potential. Further analysis based on a possible future mix of generation technologies is therefore provided in Section 4.4.4 and further in Chapter 11, accounting for energy savings reducing the total demand. Emission factors per GJ primary fuel for CO2, N2O and CH4 (IPCC, 1997) were used in the analysis but the non-CO2 gases accounted for less than 1% of emissions.

  1. ^  The TAR (IPCC, 2001) estimated potential emission reductions of 1.3–2.5 GtCO2 (0.35–0.7 GtC) by 2020 for less than 27 US$/tCO2 (100 US$/tC) based on fuel switching from coal to gas; deployment of nuclear, hydro, geothermal, wind, biomass and solar thermal; the early uptake of CCS; and co-firing of biomass with coal.