4.4.2 Cost analyses
This section places emphasis on the costs and mitigation potentials of the electricity-supply sector. Heat and CHP potentials are more difficult to determine due to lack of available data, and transport potentials are analysed in Chapter 5.
Cost estimates are sensitive to assumptions used and inherent data inconsistencies. They vary over time and with location and chosen technology. There is a tendency for some countries, particularly where regulations are lax, to select the cheapest technology option (at times using second-hand plant) regardless of total emission or environmental impact (Royal Academy of Engineering, 2004; Sims et al, 2003a). Here, based upon full life-cycle analyses in the literature, only broad cost comparisons are possible due to the wide variations in specific site costs and variations in labour charges, currency exchange rates, discount rates used, and plant capacity factors. Cost uncertainties in the electricity sector also exist due to the rate of market liberalization and the debate over the maximum level of intermittent renewable energy sources acceptable to the grid without leading to reliability issues and needing costly back-up.
One analysis compared the levelized investment, operations and maintenance (O&M), fuel and total generation costs from 27 coal-fired, 23 gas-fired, 13 nuclear, 19 wind- and 8 hydro-power plants, either operational or planned in several countries (IEA/NEA, 2005). The technologies and plant types included several units under construction or due to be commissioned before 2015, but for which cost estimates had been developed through paper studies or project bids (Figure 4.27). The economic competitiveness of selected electricity-generation systems depends upon plant-specific features. The projected total levelized generation cost ranges tend to overlap (Figure 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.
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%.
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).
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).
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).
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 |