126.96.36.199 Renewable energy
Fossil fuels can be partly replaced by renewable energy sources to provide heat (from biomass, geothermal or solar) or electricity (from wind, solar, hydro, geothermal and bioenergy generation) or by CHP plants. Ocean energy is immature and assumed unlikely to make a significant contribution to overall power needs by 2030. Net GHG emissions avoided are used in the analysis since most renewable energy systems emit small amounts of GHG from the fossil fuels used for manufacturing, transport, installation and from any cement or steel used in their construction. Overall, net GHG emissions are generally low for renewable energy systems (Figure 4.19) with the possible exception of some biofuels for transport, where fossil fuels are used to grow the crop and process the biofuel.
The ETP (IEA, 2006a) stated the technical potential of hydropower to be 14,000 TWh/yr, of which around 6000 TWh/yr (56 EJ) could be realistic to develop (IHA, 2006). The WEO Alternative scenario (IEA, 2006b) assumed an increased share for hydro generation above baseline, reaching 4903 TWh/yr by 2030. IEA (2006a) suggested hydropower (both small and large) could offset fossil-fuel power plants to give a mitigation potential between 0.3–1.0 GtCO2/yr by 2030. Here it is assumed that enough existing and new sites will be available to contribute around 5500 TWh/yr (17% of total electricity generation) by 2030 as a result of displacing coal, gas and oil plants based on their current share of the base load (Table 4.12). Future costs range from 30–70 US$/MWh for good sites with high hydrostatic heads, close proximity to load demand, and with good all-year-round flow rates. Smaller plants and those installed in less-favourable terrain at a distance from load could cost more. GHG emissions from construction of hydro dams and possible release of methane from resulting reservoirs (Section 188.8.131.52) are uncertain and not included here.
Table 4.12: Potential GHG emission reduction and cost ranges in 2030 as a result of hydro power displacing fossil-fuel thermal power plants.
| ||Potential contribution to electricity mix (%) ||Additional generation above baseline (TWh/yr) ||Net emissions avoided (GtCO2-eq/yr) ||Cost ranges (US$/tCO2-eq) |
|Lowest ||Highest |
|OECD ||15 ||608 ||0.39 ||-16 ||3 |
|EIT ||15 ||0 ||0.0 ||0 ||0 |
|Non-OECD ||20 ||643 ||0.48 ||-14 ||41 |
|World ||17 ||1251 ||0.87 || || |
The 2006 WEO Reference scenario baseline (IEA, 2006b) assumed 1132 TWh/yr (3.3% of total global electricity) of wind generation in 2030 rising to a 4.8% share in the Alternative Policy scenario. However, wind industry ‘advanced’ scenarios are more optimistic, forecasting up to a 29.1% share for wind by 2030 with a mitigation potential of 3.1 GtCO2/yr (GWEC, 2006). The ETP mitigation potential assessment (IEA, 2006a) for on- and offshore wind power by 2030 ranged between 0.3 and 1.0 GtCO2/yr. In this analysis on- and offshore wind power is assumed to reach a 7% share by 2030, mainly in OECD countries, and to displace new and existing fossil-fuel power plants according to the relevant shares of coal, oil and gas in the baseline for each region (Table 4.13). Intermittency issues on most grids would not be limiting at these low levels given suitable control and back-up systems in place. The costs are very site specific and range from 30 US$/MWh on good sites to 80 US$/MWh on poorer sites that would also need to be developed if this 7% share of the total mix is to be met.
Table 4.13: Potential GHG emission reduction and costs in 2030 from wind power displacing fossil-fuel thermal power plants.
| ||Potential contribution to electricity mix (%) ||Additional generation above baseline (TWh/yr) ||Net extra emissions reductions (GtCO2-eq/yr) ||Cost ranges (US$/tCO2-eq) |
|Lowest ||Highest |
|OECD ||10 ||687 ||0.45 ||-16 ||33 |
|EIT ||5 ||99 ||0.06 ||-16 ||30 |
|Non-OECD ||5 ||572 ||0.42 ||-14 ||27 |
|World ||7 ||1358 ||0.93 || || |
Bioenergy (excluding biofuels for transport)
Large global resources of biomass could exist by 2030 (Chapters 8, 9 and 10), but confidence in estimating the bioenergy heat and power potential is low since there will be competition for these feedstocks for biomaterials, chemicals and biofuels. Bioenergy in its various forms (landfill gas, combined heat and power, biogas, direct combustion for heat etc.) presently contributes 2.6% to the OECD power mix, 0.4% to EIT and 1.5% to non-OECD. The WEO 2006 (IEA, 2006b) assumed 805 TWh of biomass power generation in 2030 rising 22% to 983 TWh under the Alternative scenario to then give 3% of total electricity generation. The ETP gave a bioenergy potential ranging between 0.1 and 0.3 GtCO2 /yr by 2030. The baseline (IEA, 2004a) assumed biomass and waste for heat and power generation will rise from 2% of primary fuel use (3.2 EJ) in 2002 to 4% (10.8 EJ) by 2030.
Heat and CHP estimates are wide ranging so cannot be included in this analysis, even though the bioenergy potential could be significant. However, any heat previously utilized from displaced coal and gas CHP plants could easily be supplied from biomass, with more biomass available for use in stand-alone heat plants (Chapter 11). In this analysis, a 5% share in OECD regions is assumed feasible, relying on co-firing in existing and new coal plants and with 7–8% of the total replacement capacity built being bioenergy plants. In EIT regions, the available forest biomass could be utilized to gain 5% share and in non-OECD regions, where there are less stock turnover issues than in the OECD, 10% of power could come from new bioenergy plants (Table 4.14). A total potential by 2030 of 5% is assumed based on costs of 30–100 US$/MWh. The biomass feedstock required to meet these potentials, assuming thermal-conversion efficiencies of 20–30%, would be around 9–13 EJ in OECD, 1–3 EJ in EIT, and 18–27 EJ in non-OECD regions. Little additional bioenergy capacity above that already assumed in the baseline is anticipated in EIT regions where only a small contribution is expected compared with developing countries. Small inputs of fossil fuels are often used to produce, transport and convert the biomass (IEA, 2006h), but the same is true when using the fossil fuels it replaces. Since both are of a similar order of magnitude, and these emissions are already accounted for in the overall total for fossil fuels, bioenergy is credited with zero emissions (in compliance with IPCC guidelines).
Table 4.14: Potential emissions reduction and cost ranges in 2030 from bioenergy displacing fossil-fuel thermal power plants.
| ||Potential contribution to electricity mix (%) ||Additional generation above baseline (TWh/yr) ||Net emissions reductions (GtCO2-eq/yr) ||Cost ranges (US$/tCO2-eq) |
|Lowest ||Highest |
|OECD ||5 ||307 ||0.20 ||-16 ||63 |
|EIT ||5 ||112 ||0.07 ||-16 ||60 |
|Non-OECD ||10 ||1283 ||0.95 ||-14 ||54 |
|World ||7 ||2415 ||1.22 || || |
The installed geothermal-generation capacity of over 8.9 GWe in 24 countries produced 56.8 TWh (0.3%) of global electricity in 2004 and is growing at around 20%/yr (Bertani, 2005) with the baseline giving 0.05% of total generation by 2030. IEA WEO 2006 (IEA, 2006b) assumed 174 TWh/yr by 2030 rising 6% to 185 TWh under the Alternative scenario. The ETP (IEA, 2006a) gave a potential of 0.1–0.3 GtCO2-eq/yr by 2030.
In this analysis, generation costs of 30–80 US$/MWh are assumed to provide a 2% share of the total 2030 energy mix. Direct heat applications are not included. Although CO2 emissions are assumed to be zero, as for other renewables, this may not always be the case depending on underground CO2 released during the heat extraction.
Concentrating solar power (CSP) and photovoltaics (PV) can theoretically gain a maximum 1–2% share of the global electricity mix by 2030 even at high costs. The 2006 WEO Reference scenario (IEA, 2006b) estimated 142 TWh/yr of PV generation in 2030 rising to 237 TWh in the Alternative scenario but still at <1% of total generation. EPRI (2003) assessed total PV capacity to be 205 GW by 2020 generating 282 TWh/yr or about 1% of global electricity demand. Other analyses range from over 20% of global electricity generation by 2040 (Jäger-Waldau, 2003) to 0.008% by 2030 with mitigation potential for both PV and CSP likely to be <0.1 GtCO2 in 2030 (IEA, 2006a) The calculated minimum costs for even the best sites resulted in relatively high costs per tonne CO2 avoided (Table 4.16). The baseline (IEA, 2004a) gave the total solar potential as 466 TWh or 1.4% of total generation in 2030.
In this analysis, generating costs from CSP plants could fall sufficiently to compete at around 50–180 US$/MWh by 2030 (Trieb, 2005; IEA, 2006a). PV installed costs could decline to around 60–250 US$/MWh, the wide range being due to the various technologies being installed on buildings at numerous sites, some with lower solar irradiation levels. Penetration into OECD and EIT markets is assumed to remain small with more support for developing country electrification.
Table 4.15: Potential emissions reduction and cost ranges in 2030 from geothermal displacing fossil-fuel thermal power plants.
| ||Potential contribution in electricity mix (%) ||Additional geothermal (TWh/yr) ||Net emissions avoided (GtCO2-eq/yr) ||Cost ranges (US$/tCO2-eq) |
|Lowest ||Highest |
|OECD ||2 ||137 ||0.09 ||-16 ||33 |
|EIT ||2 ||44 ||0.03 ||-16 ||30 |
|Non-OECD ||3 ||413 ||0.31 ||-14 ||27 |
|World ||2 ||594 ||0.43 || || |
Table 4.16: Potential emission reduction and cost ranges in 2030 from solar PV and CSP displacing fossil-fuel thermal power plants.
| ||Potential contribution to electricity mix (%) ||Additional generation above baseline (TWh/yr) ||Emissions reductions (GtCO2-eq/yr) ||Cost ranges (US$/tCO2-eq) |
|Lowest ||Highest |
|OECD ||1 ||44 ||0.03 ||61 ||294 |
|EIT ||1 ||21 ||0.01 ||60 ||288 |
|Non-OECD ||2 ||275 ||0.21 ||53 ||257 |
|World ||2 ||340 ||0.25 || || |