Electricity Use Is Another Major Cause of Carbon Dioxide Emissions

Figure 126. Projected carbon dioxide emissions from electricity generation by fuel, 2000, 2010, and 2020 (million metric tons carbon equivalent)

Electricity generation is a major source of carbon dioxide emissions. Although electricity produces no emissions at the point of use, generation (excluding cogeneration) accounted for 37 percent of total carbon dioxide emissions in 1999, and its share is expected to increase to 38 percent in 2020. Coal is projected to account for 47 percent of electricity generation in 2020 (excluding cogeneration) and to produce 78 percent of electricity-related carbon dioxide emissions (Figure 126). In 2020, natural gas is projected to account for 33 percent of electricity generation (excluding cogeneration) but only 22 percent of electricity-related carbon dioxide emissions.

Between 1999 and 2020, 26 gigawatts of nuclear capacity is projected to be retired, resulting in a 21-percent decline in nuclear generation. To make up for the loss of nuclear capacity and meet rising demand, 385 gigawatts of new fossil-fueled capacity (excluding cogeneration) is projected to be needed. Increased generation from fossil fuels is expected to raise carbon dioxide emissions from electricity generation (excluding cogeneration) by 215 million metric tons carbon equivalent, or 39 percent, from 1999 levels. Generation from renewable technologies (excluding cogeneration) is projected to increase by 43 billion kilowatthours, or 12 percent, between 1999 and 2020 but is not expected to be sufficient to offset the projected increase in generation from fossil fuels.

The projections include announced activities under the Climate Challenge program, such as fuel switching, repowering, life extension, and demand-side management, but they do not include offset activities, such as reforestation.

Moderate Growth in Methane Emissions Is Expected

Figure 127. Projected methane emissions from energy use, 2005-2020 (million metric tons carbon equivalent)

Methane emissions from energy use are projected to increase at an average rate of 1.0 percent per year from 1999 to 2020, somewhat slower than the 1.4-percent projected growth rate for carbon dioxide emissions. Based on global warming potential, methane is the second largest component of U.S. man-made greenhouse gas emissions after carbon dioxide, and it is one of the six gases covered in the Kyoto Protocol. In 1999, methane accounted for 9 percent of total U.S. greenhouse gas emissions of 1,833 million metric tons carbon equivalent. About a third of U.S. methane emissions are related to energy activities, mostly from energy production and transportation and to a much smaller extent from fuel combustion. Other sources of methane emissions include waste management, agriculture, and industrial processes.

Much of the projected increase in energy-related methane emissions is tied to increases in oil and gas use (Figure 127). The fugitive methane emissions that occur during natural gas production, processing, and distribution are expected to increase, despite declines in the average rate of emissions per unit of production. Emissions related to oil production and, to a lesser extent, refining and transport are also expected to increase. Coal-related methane emissions are expected to decline, with coal production from methane-intensive underground mining projected to remain flat over the forecast period while progress in the recovery of vented gas continues. About 6 percent of methane emissions in 1999 resulted from wood and fossil fuel combustion. A 20-percent increase is projected by 2020, with residential use of wood as a fuel expected to remain at about its 1999 level.

Scrubber Retrofits Will Be Needed To Meet Sulfur Emissions Caps

Figure 128. Projected sulfur dioxide emissions from electricity generation, 2000-2020 (million tons)

CAAA90 called for annual emissions of sulfur dioxide (SO₂) by electricity generators to be reduced to approximately 12 million tons in 1996, 9.48 million tons between 2000 and 2009, and 8.95 million tons per year thereafter. Because companies can bank allowances for future use, however, the long-term cap of 8.95 million tons per year may not be reached until after 2010. About 97 percent of the SO₂ produced by generators results from coal combustion and the rest from residual oil.

CAAA90 called for the reductions to occur in two phases, with larger (more than 100 megawatts) and higher emitting (more than 2.5 pounds per million Btu) plants making reductions first. In Phase 1, 261 generating units at 110 plants were issued tradable emissions allowances permitting SO₂ emissions to reach a fixed amount per year—generally less than the plant’s historical emissions. Allowances may also be banked for use in future years. Switching to lower sulfur subbituminous coal was the option chosen by most generators, as only about 12 gigawatts of capacity had been retrofitted by 1995.

In Phase 2, beginning in 2000, emissions constraints on Phase 1 plants are tightened, and limits are set for the remaining 2,500 boilers at 1,000 plants. With allowance banking, emissions are projected to decline from 11.9 million tons in 1995 to 11.5 million in 2000 (Figure 128). With the SO₂ emissions cap tightened in 2000 and after, the price of allowances is projected to rise, reaching $215 per ton by 2005. As the price rises, 11 gigawatts of capacity—about 37 300-megawatt plants—is expected to be retrofitted with scrubbers to meet the Phase 2 goal.

A Significant Drop in Nitrogen Oxide Emissions Is Expected in 2000

Figure 129. Projected nitrogen oxide emissions from electricity generation, 2000-2020 (million tons)

Nitrogen oxide (NO_x) emissions from electricity generation in the United States are projected to fall significantly over the next 5 years as new legislation takes effect (Figure 129). The required reductions are intended to reduce the formation of ground-level ozone, for which NO_x emissions are a major precursor. Together with volatile organic compounds and hot weather, NO_x emissions contribute to unhealthy air quality in many areas during the summer months. The CAAA90 NO_x reduction program called for reductions at electric power plants in two phases, the first in 1995 and the second in 2000. The second phase of CAAA90 is expected to result in NO_x reductions of 0.8 million tons between 1999 and 2000.

Even after the CAAA90 regulations take effect, further effort may be needed in some areas. For several years the EPA and the States have studied the movement of ozone from State to State. The States in the Northeast have argued that emissions from coal plants in the Midwest make it difficult for them to meet national air quality standards for ground-level ozone, and they have petitioned the EPA to force the coal plant operators to reduce their emissions more than required under current rules.

The interpretation of ozone transport studies has been controversial. In September 1998 the EPA issued a rule, referred to as the Ozone Transport Rule (OTR), to address the problem. The OTR calls for capping NO_x emissions in 22 midwestern and eastern States during the 5-month summer season, beginning in 2003. After an initial court challenge the rules have been upheld, and emissions limits have been finalized for 19 States.