4.4.4 Electricity-supply sector mitigation potential and cost of GHG emission avoidance

To provide a more realistic indication of the total mitigation potential for the global electricity sector, further analysis is conducted based on the literature, and assuming that no additional energy-efficiency measures in the building and industry sectors will occur beyond those already in the baseline. (Section 11.3.1 accounts for the impacts of energy efficiency on the heat and power-supply sector). The WEO 2004 baseline (IEA, 2004a) is used, based on data from Price and de la Rue du Can, (2006). The fuel-to-electricity conversion efficiencies were derived from the correction of the heat share in the WEO 2004 data, by assuming the share of heat in the total primary energy supply was constant from 2002 onwards.

The baseline

By 2010 total power demand is 20,185 TWh with 13,306 TWh generation coming from fossil fuels (65.9% share of the total generation mix), 3894 TWh from all renewables (19.3%), and 2985 TWh from nuclear (14.8%). Resulting emissions are 11.4 GtCO₂-eq. By 2030 the increased electricity demand of 31,656 TWh is met by 22,602 TWh generated from fossil fuels, 6,126 TWh from renewables, and 2,929 TWh from nuclear power. The fossil-fuel primary energy consumed for electricity generation in 2030 produces 15.77 GtCO₂-eq of emissions (IEA, 2004a; Table 4.8).

New electricity generation plants to be built between 2010 and 2030 are to provide additional generating capacity to meet the projected increase in power demand, and to replace capacity of old, existing plants being retired during the same period. Additional capacity built after 2010, consumes an additional 82.5 EJ/yr of primary energy in order to generate 11,471 TWh/yr more electricity by 2030. Replacement capacity built during the period consumes 72 EJ/yr in 2030 and generates 8074 TWh/yr. Therefore, the total generation from new plants in the baseline is 19,545 TWh/yr by 2030, of which 14,618 TWh/yr comes from fossil-fuel plants (75%), 3787 TWh/yr from other renewables (19%), and 1140 TWh/yr from nuclear power (6%) (IEA, 2004a).

Sector analysis from 2010 to 2030

The potential for the global electricity sector to reduce baseline GHG emissions as a result of the greater uptake of low- and zero-carbon-emitting technologies is assessed. The method employed is outlined below. Fossil-fuel switching from coal to gas; substitution of coal, gas and oil plants with nuclear, hydro, bioenergy and other renewables (wind, geothermal, solar PV and solar CSP), and the uptake of CCS are all included.

• For each major world country-grouping (OECD Pacific, US and Canada, OECD Europe, EIT, East Asia, South Asia, China, Latin America, Mexico, Middle East and Africa), WEO 2004 baseline data (Price and de la Rue du Can, 2006; IEA, 2004a) are used to show the capacity of fossil-fuel thermal electricity generation per year that could be substituted after 2010, assuming a linear replacement rate and a 50-year life for existing coal, gas and oil plants. The results are then aggregated into OECD, EIT and non-OECD/EIT regional groupings.
• New generation plants built by 2030 to meet the increasing power demand are shared between fossil fuel, renewables, nuclear and, after 2015, coal and gas-fired plants with CCS. The shares of total power generation assumed for each of these technologies by 2030 are based on the literature (Section 4.4.3), but also depend partly on their relative costs (Table 4.19). The relatively high shares assumed for nuclear and renewable energy, particularly in OECD countries, are debatable, but supported to some extent by European Commission projections (EC, 2007).
• No early retirements of plant or stranded assets are contemplated (although in reality a faster replacement rate of existing fossil-fuel capacity could be possible given more stringent policies in future to reduce GHG emissions). The assumed replacement rates of old fossil-fuel plant capacity by nuclear, and renewable electricity, and the uptake of CCS technologies, are each based on the regional power mix shares of coal, gas and oil plants operating in the baseline.
• In reality, the future value of carbon will likely affect the actual generation shares for each technology, as will any mitigation policies in place before 2030 that encourage reductions of GHG emissions from specific components of the energy-supply sector.
• It is assumed that after 2010 only power plants with higher conversion efficiencies (Table 4.20) are built.
• As fuel switching from coal to natural gas supply is assessed to be an option with relatively low costs, this is implemented first with 20% of new proposed coal-fired power plants substituted by gas-fired technologies in all regions (based on Section 4.4.3.1).
• It is assumed that, where cost-effective, some of the new fossil-fuel plants required according to the baseline (after adjustments for the previous step) are displaced by low- and zero-carbon-intensive technologies (wind, geothermal, hydro, bioenergy, solar, nuclear and CCS) in proportion to their relative costs and potential deployment rates. The resulting GHG emissions avoided are assessed.
• It is assumed that by 2030, wind, solar CSP and solar PV plants that displace new and replacement fossil-fuel generation are partly constrained by related environmental impact issues, the relatively high costs for some renewable plants compared to coal, gas and nuclear, and intermittency issues in power grids. However, developments in energy-storage technologies, supportive policy trends and recognition of co-benefits are assumed to partly offset these constraints. Priority grid access for renewables is also assumed. Thus, reasonably high shares in the mix become feasible (Table 4.20).
• The share of electricity generation from each technology assumes that the maximum resource available is not exceeded. The available energy resources are evaluated on a regional basis to ensure all assumptions can be met in principle.

• − Any volumes of biomass needed above those available from agricultural and forest residues (Chapters 8 and 9) will need to be purpose-grown, so could be constrained by land and water availability. While there is some uncertainty in this respect, there should be sufficient production possible in all regions to meet the generation from bioenergy as projected in this analysis.
• − Uranium fuel supplies for nuclear plants should meet the assumed growth in demand, especially given the anticipation of ‘Gen III’ plant designs with fuel recycling coming on stream before 2030.
• − There is sufficient storage capacity for sequestering the estimated capture of CO₂ volumes in all regions given the anticipated rate of growth of CCS over the next few decades (Hendricks et al., 2004).

• CCS projects for both coal- and gas-fired power plants are deployed only after 2015, assuming commercial developments are unavailable until then.

Table 4.19: Potential GHG emissions avoided by 2030 for selected, electricity generation mitigation technologies (in excess of the World Energy Outlook 2004 Reference baseline, IEA, 2004a) if developed in isolation and with the estimated mitigation potential shares spread across each cost range (2006 US$/tCO₂-eq) for each region.