Climate Change 2001: Mitigation

9.2.4 Non-fossil Energy

This section covers the effects of mitigation on non-fossil-fuel-based energy production and use (electricity and biomass), and the ancillary benefits and costs associated with mitigation using non-fossil energy.

9.2.4.1 Electricity Use and Production Fuel Mix

World electricity demand in 1998 was 12.6bn MWh, about 60% of which (7.5bn MWh) was consumed in the industrialized countries (EIA, 2000a). Fossil fuels used for electricity generation account for about one third of the CO₂ emissions from the energy sector worldwide (EIA, 2000b). Globally, about 60% of all electricity is produced with fossil fuels. However, the fraction of electricity generated from fossil fuels varies across countries, from as little as 1% in Norway to 95% in the Middle East, and 97% in Poland (EIA, 2000a). Nuclear reactors are producing electricity with a global capacity of around 351GWe (IAEA, 1997), with each having an average of nearly 800MWe of installed capacity. Half of this total is concentrated in three countries: the USA with 25%, and France and Japan with 12.5% each (IAEA, 1997, pp. 10-11).

Recent projections show that electricity use will grow 37% to 16.8bn MWh by 2010, and 76% to 21.6bn MWh by 2020. About two thirds of this growth will occur outside the developed countries (EIA, 2000b). The IPCC Special Report on Emissions Scenarios (SRES) projections (Nakicenovic et al., 2000) are similar, with worldwide electricity demand projected to more than double between 1990 and 2020 in scenarios A1B, A1F1 and B1, and to double between 1990 and 2020 in scenarios A2 and B2. Beyond 2020, the growth in electricity demand projected in the scenarios diverges. A1B shows the highest growth, more than 20 times between 1990 and 2100, while B1 shows the lowest growth, slightly less than 6 times between 1990 and 2100.

Much of this new power will be generated with fossil fuels. Globally, use of gas for electricity generation is projected to more than double by 2020. Global use of coal for generation is projected to grow by more than 50%, with about 90% of the projected increase occurring in the developing countries. In Asia, nuclear power is still expected to increase to meet the increasing electric power demand mainly because of resource constraint issues (Aoyama, 1997; Matsuo, 1997). Table 9.6 shows estimates of nuclear electrical generating capacity by region to 2010.

Table 9.6: Projected nuclear energy capacity (MW)

Country	1997	2007	2010

Japan South Korea China Taiwan, China India Pakistan North Korea Total	45248 10316 2100 5148 1845 139 0 64796	49572 19716 9670 7848 3990 600 2000 93396	54672 22716 11670 7848 4320 600 2000 103826

Source: Hagan (1998)

Figure 9.2: Projection of world nuclear capacity to 2050 in TWh (Nakicenovic et al., 1998).

Uncertainty is reflected in the wide range in the long-term projections for nuclear energy capacity. The World Energy Council (Nakicenovic et al., 1998; http://www.iiasa.ac.at/cgi-bin/ecs/bookdyn/bookcnt.py) projects a range of 2,227 to 11,840 TWh in 2050 under six possible future energy scenarios as shown in Figure 9.2.

9.2.4.2 Impacts of Mitigation on the Electricity Sector

Given the extensive use of fossil fuel in the production of electricity, it is not surprising that a variety of proposals have been put forth to mitigate GHG emissions in this sector. Many countries have proposed renewable technologies as one solution for GHG mitigation (Comisión Nacional de Energía, 1993; SDPC et al., 1996; Piscitello and Bogach, 1997; European Commission, 1997). In some European countries such as Sweden and Austria, carbon taxes have been introduced. In Japan, nuclear power is planned to supply 480TWh in 2010, or 17.4% of total primary energy supply, to help meet the Kyoto target (Fujime, 1998). In contrast, in Sweden, a policy under debate to phase out nuclear power and restrict CO₂ emissions to 1990 levels by other means would result in significantly higher electricity prices (Anderson and Haden, 1997)

In general, mitigation policies work through two routes. First, they either mandate or directly provide incentives for increased use of zero-emitting technologies (such as nuclear, hydro, and other renewables) and lower-GHG-emitting generation technologies (such as combined cycle natural gas). Or, second, indirectly they drive their increased use by more flexible approaches that place a tax on or require a permit for emission of GHGs. Either way, the result will be a shift in the mix of fuels used to generate electricity towards increased use of the zero- and lower-emitting generation technologies, and away from the higher-emitting fossil fuels (Criqui et al., 2000).

Quantitative analyses of these impacts are somewhat limited. Table 9.1 presents published results from multisectoral models. Other multi-regional models used to assess the impacts of GHG reduction policies appear to have the capability to quantify these impacts on the electricity sector (Bernstein et al., 1999; Cooper et al., 1999; Kainuma et al., 1999a, b and c; Kurosawa et al., 1999; MacCracken et al., 1999; McKibbin et al., 1999; Tulpule et al., 1999). However, the focus of the studies conducted with these models has generally been on broader economy-wide impacts, and many do not report results for the electricity sector. McKibbin et al. (1999) reported the price and quantity impacts on electric utilities if the USA unilaterally implements its Kyoto commitments. Under this scenario, electricity prices in the USA increase 7.2% in 2010 and 12.6% in 2020, while demand drops 6.2% and 9.5% in those years, respectively. The Australian Bureau of Agricultural and Resource Economics (ABARE, 1995) reported shifts in fuel share for Annex B under a policy where this group of countries stabilizes emissions at 1990 levels by 2000. They show that the share of coal in the generation of electricity for most Annex B countries would drop by 10% to 50%, with the combined shares for nuclear and renewables increasing 14 to 46%⁸. (See Table 9.7 for detailed results.) They note that such a policy may require substantial structural changes in the industry and are likely to involve significant costs, but do not elaborate or quantify.

Table 9.7: Change in shares (percentage points) of alternative energy sources in electricity generation under stabilization relative to the baseline in 2010

	Coal	Oil	Gas	Nuclear^a	Renewables

United States European Union Japan Canada Australia New Zealand	-18.1 -21.2 -10.8 -12.4 -50.5 - 2.4	-0.6 -1.0 -8.0 -1.0 +2.2 -0.1	1.6 1.7 8.2 0.3 3.0 -14.0	+14.1 +16.3 +18.3 + 2.9 0.0 0.0	+ 6.3 + 4.2 + 8.6 +10.8 +45.4 +16.5

Source: ABARE, 1995 ^a These results do not take into account any barriers to the expansion of nuclear power in the USA, Canada, the EU, and Japan.

There are a number of analyses for the USA only that report detailed impacts on the electricity sector. Charles River Associates (CRA) and Data Resources International (DRI) (1994) assessed the potential impact of carbon taxes of US$50, $100, and $200 per tonne carbon, phased in to these levels over 1995 to 2000. By 2010, imposition of such taxes has increased prices of electricity by 13%, 27%, and 55% for the US$50, $100, and $200 tax, while sales dropped 8%, 14%, and 74%, respectively.

More recently, a group of studies assessing the impacts of the Kyoto Protocol on the US have reported electricity sector impacts (EIA, 1998; WEFA, 1998; DRI, 1998). These studies all use a flexible mechanism, such as tradable emissions permits, as the implementation policy. Taken together, the studies reflect a range of assumptions about the level of emissions reductions that would need to come from the domestic energy sector. The range of results for the EIA study for 2010 is summarized here, however, the results from all three studies are generally consistent. Key impacts in 2010, all of which increase as emissions reduction requirements increase, include the following.

Electricity prices were projected to increase 20% to 86% above baseline levels.
Electricity demand was projected to decrease 4% to 17% below baseline levels.
Prices of natural gas were projected to increase by 35% to 206% over the baseline levels. Prices of coal for electricity production were projected to increase to about 2.5 to 9 times the baseline levels. And, despite a 7% to 40% decrease in fossil generation, fossil fuel expenditures increase 81% to 238% over baseline levels.
About 9% to 43% of total generation will shift away from coal relative to the baseline. The large shift over this limited time period would reflect significant structural changes and potentially large stranded costs. Roughly half of this is replaced by natural gas generation, while most of the remainder is not replaced as a result of reduced demand. Renewable generation beyond baseline levels generally does not enter the mix until at least 2020.

None of the studies quantify the potential stranded costs associated with the premature retirement of existing generation.

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