The 108th Congress proposed and debated a variety of bills addressing pollution control at electric power plants but did not pass any of them into law. In addition, the EPA currently is preparing two regulations—a proposed Clean Air Interstate Rule (pCAIR) and a Clean Air Mercury Rule (CAMR)—to address emissions from coal-fired power plants. Several States also have taken legislative actions to limit pollutants from power plants in their jurisdictions. This section discusses three Congressional air pollution bills and the EPA’s pCAIR and CAMR regulations. 

Clear Skies Act of 2003, Clean Air Planning Act of 2003, and Clean Power Act of 2003 

Several bills introduced in the 108th Congress proposed to regulate emissions of NO_x, sulfur dioxide (SO₂), mercury, and CO₂ from electric power plants. EIA received a request from Senator James M. Inhofe to conduct an analysis of S. 843, the Clean Air Planning Act of 2003, introduced by Senator Thomas Carper; S. 366, the Clean Power Act of 2003, introduced by Senator James Jeffords; and S. 1844, the Clear Skies Act of 2003, introduced by Senator Inhofe. The emissions targets and implementation timetables proposed in the bills are summarized in Table 12. 

A report on the results of EIA’s analysis [55] was released in May 2004. The analysis in the report was based on the assumptions used in AEO2004, which differed from those used in AEO2005. One of the most significant differences for the electricity sector is in projected natural gas prices. In AEO2005, the reference case projection for wellhead natural gas prices in 2025 is more than 30 cents higher than the AEO2004 projection, primarily as a result of lower assumed finding rates (reserve additions per well) for onshore resources. The following summary of EIA’s Inhofe-Carper-Jeffords analysis is based on the AEO2004 projections. 

To comply with the provisions of S. 1844, the Clear Skies Act (Inhofe), electricity producers would be expected to rely primarily on adding emissions control equipment to existing generators. Switching fuels from coal to natural gas and renewables would be expected to play a relatively small role. Producers would be expected to begin reducing mercury emissions before 2010 in order to take advantage of the early credit program included in S. 1844; however, emissions of mercury would remain above the 15-ton target in 2018, because the bill also specifies an “allowance price safety valve.” Among the three bills analyzed by EIA, total costs to the electric power industry and projected impacts on electricity prices are lowest for S. 1844. 

S. 843, the Clean Air Planning Act (Carper) would impose more stringent limits on emissions of SO₂, NO_x, and mercury than those proposed in S. 1844. In addition, S. 843 proposes a cap on CO₂ emissions. Emissions control equipment added to existing generators would also be expected to play an important role in compliance strategies under S. 843, but fuel switching from coal to natural gas and renewables would play a more important role. In addition, the impacts would be sensitive to the availability and cost of greenhouse gas offsets. Because of this uncertainty, two separate cases were included in EIA’s analysis of S. 843—one (Carper domestic) assuming that only domestic offset programs would be approved and another (Carper international) assuming that both domestic and international offsets would be available. Overall, the resource costs and electricity price impacts under S. 843 were projected to be larger than those under S. 1844. 

S. 366, the Clean Power Act (Jeffords), includes a more stringent cap on CO₂ emissions, which would be expected to make switching from coal to natural gas, renewables, and nuclear especially important in compliance strategies. S. 366 would require all older power plants to be retrofitted with emissions control equipment, even if emissions of SO₂, NO_x, and mercury fell below the respective aggregate reduction targets as a result of fuel switching. The early timing and stringency of the emissions limits, among other factors, would lead to the largest resource cost and electricity price impacts among the three bills. Because of the higher projected electricity prices under S. 366, consumers would also be expected to reduce their use of electricity. 

Table 13 shows a summary of EIA’s analysis results. Significantly, power plant emissions of NO_x in 2025 were projected to remain at about the levels of the respective phase 2 targets under S. 843 (1.7 million tons) and S. 1844 (1.79 million tons) shown in Table 12, because neither bill would be expected to provide significant opportunity for economical banking of NO_x allowances. Only under S. 366, which requires emissions controls at all plants over 40 years old, were NO_x emissions in 2025 projected to fall below the bill’s emission target of 1.51 million tons shown in Table 12. 

SO₂ emissions from electric power plants were projected to be reduced under the provisions of each of the three bills, as well as in the AEO2004 reference case. Under S. 843 and S. 1844, however, SO₂ emissions in 2025 were projected to remain above the bills’ target levels because of allowances banked from the existing SO₂ reduction program. Under S. 366, SO₂ emissions in 2025, like NO_x emissions, were projected to fall below the bill’s target level. 

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Average retail electricity prices in 2025 were projected to be 3.2 percent higher under S. 1844 than in the AEO2004 reference case forecast, and they were projected to be as much as 7.8 percent higher under S. 843 (Figure 9). Much larger price impacts were projected under S. 366—47 percent above reference case prices in 2010 and 27 percent above reference case prices in 2025—primarily because the proposed limit on CO₂ emissions at 1990 levels in 2009 would require rapid transformation of the Nation’s power plant capacity from coal to natural gas, renewables, and nuclear fuel. 

Proposed Clean Air Interstate Rule 

The EPA’s proposed CAIR [56] was published in the Federal Register [57] in January 2004 and in a supplemental notice [58] in June 2004. pCAIR is intended to reduce the atmospheric interstate transport of fine particulate matter (PM_2.5) and ozone. SO₂ and NO_x are precursors of PM_2.5. NO_x is also a precursor to the formation of ground-level ozone. pCAIR would require 29 States and the District of Columbia to develop plans to reduce SO₂ and/or NO_x emissions. The proposed rules would apply to all fossil-fuel-fired boilers and turbines serving electrical generators with capacity greater than 25 megawatts that provide electricity for sale. The proposed rules also would apply to combined heat and power (CHP) units that are larger than 25 megawatts, that sell at least one-third of their potential electrical output, and that meet certain operating and efficiency criteria. Table 14 shows the pCAIR emissions caps and timetables for meeting the caps. 

Under pCAIR, the States would be responsible for allocating NO_x emissions allowances and taking the lead in pursuing enforcement actions, and they would have flexibility in choosing the sources to be controlled. They could meet the emissions reduction requirements either by joining the EPA-managed cap and trade programs for power plants, or by achieving reductions through emissions control measures on sources in other sectors (industrial, transportation, residential, or commercial), or on a combination of electricity generating units and sources in other sectors. 

To participate in the cap and trade program, the States would be required to regulate power plant emissions within their boundaries. The EPA would be responsible for assigning State emissions budgets, reviewing and approving State plans, and administering the emissions and allowance tracking systems. State rules could allow sources currently subject to the CAAA90 Title IV rules and to the NO_x State Implementation Plan (SIP) Call trading program to use allowances banked from those programs before 2010 for compliance with pCAIR. pCAIR also would require additional reductions in NO_x emissions for States affected by the NO_x SIP Call. 

The EPA plans to meet the SO₂ emission reduction requirements by implementing a progressively more stringent retirement ratio on SO₂ allowances for electricity generating units of different vintages under the CAAA90 Title IV acid rain program. New SO₂ allowances would not be issued under pCAIR; power plants would instead use the current pool of SO₂ allowances issued under Title IV. Allowances issued for vintage years 2004 through 2009 could be retired on a 1-to-1 basis, but allowances issued for vintage years 2010 through 2014 would have to be retired on a 2-to-1 basis, requiring 2 Title IV allowances to be retired for each ton of SO₂ emissions. Allowances issued for vintage years 2015 and later would be retired on a basis of approximately 2.9 to 1. This retirement procedure is proposed in order to integrate the pCAIR rules with the existing Title IV SO₂ emissions reduction program.  NO_x emissions would be treated differently, with State emissions caps to be based on each State’s share of region-wide heat input. In addition, new NO_x allowances would be issued, and banked SIP Call allowances could be traded under pCAIR. 

pCAIR Analysis 

Although the AEO2005 reference case does not assume enactment of pCAIR, an alternative case has been developed to analyze its potential impacts. The pCAIR sensitivity case assumes the adoption of pCAIR emissions caps on SO₂ and NO_x and the proposed SO₂ allowance vintaging methodology. The caps are assumed to be imposed on all electricity generators and CHP units that sell electricity to the grid, and it is assumed that electricity producers would opt to participate in the EPA cap and trade program rather than relying on State emission reduction programs. Other than those assumptions, the pCAIR case uses the AEO2005 reference case assumptions. 

Table 15 compares the key results of the pCAIR case and the AEO2005 reference case. In 2025, the pCAIR case results in a 46-percent reduction in national NO_x emissions from their 2003 level and a 63-percent reduction in SO₂ emissions from the 2003 level. 

NO_x allowance prices are projected to increase in the pCAIR case. In the reference case, the NO_x SIP Call affects States primarily in the Northeast with a summer season NO_x cap. In the pCAIR case, the SIP Call caps are replaced by the pCAIR NO_x caps, which affect a different combination of States and are annual limits. Because the NO_x allowance prices under the two inherently different programs cannot be compared, Table 15 shows only the allowance prices under pCAIR. 

SO₂ allowance prices are projected to be significantly higher in the pCAIR case than in the reference case, which assumes continuation of the currently enacted CAAA90 allowance program. The higher SO₂ allowance prices in the pCAIR case reflect the need for utilities to reduce emissions to lower levels than currently required under CAAA90. 

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One of the key results of the pCAIR case is that electric power producers would be required to install significantly more pollution control equipment than in the reference case. To comply with the pCAIR limits in SO₂ emissions, electricity producers are projected to install flue gas desulfurization (FGD) scrubbers on nearly 100 gigawatts more coal-fired capacity than in the reference case through 2025. Similarly, to meet the pCAIR NO_x limits, SCR equipment is projected to be installed on about 60 gigawatts more coal-fired capacity than in the reference case. In the reference case, total coal-fired capacity in the United States is projected to grow from 314 gigawatts in 2003 to 398 gigawatts in 2025. Thus, in the pCAIR case, roughly one-third of all coal-fired power plants would be retrofitted with FGD and SCR equipment by 2025. The pCAIR case does not project a significant change in the fuel mix for electricity generation in 2025 relative to that in the reference case, showing only a slight reduction in coal use, a small increase in natural gas use, and a small increase in renewable fuel use (Figure 10). 

Only modest changes in regional coal production are projected in the pCAIR case (Figure 11). In both the reference and pCAIR cases, coal production increases from 2003 to 2025. Relative to the reference case, the pCAIR case projects a decrease in Appalachian coal production of about 2 percent in 2025, a decrease in Interior coal production of about 13 percent (24 million tons), and an increase in Western coal production of about 1.1 percent, based on the generally lower sulfur content of Western than Appalachian and Interior coal resources. 

After the first phase of the pCAIR emissions caps begins to take effect in 2010, average U.S. retail electricity prices are projected to be higher by a maximum of 2.3 percent in the pCAIR case than in the reference case, with a similar difference in projected resource costs for the electric power sector (the amount that power companies spend on fuel, capital, and operations and maintenance). Projected resource costs from 2010 through 2025 are higher by a maximum of $3.5 billion per year (about 2.5 percent) in the pCAIR case than in the AEO2005 reference case. 

Proposed Clean Air Mercury Rule 

The EPA’s CAMR (proposed as the Utility Mercury Reductions Rule) [59] for controlling mercury emissions from new and existing coal-fired power plants was published in the Federal Register [60] in January 2004 and in a supplemental notice [61] in March 2004. Nickel emissions from new and existing oil-fired power plants would also be capped under the proposed rule; however, as of 2002 only 2.3 percent of the electricity generated in the United States was from oil-fired units, and 50.2 percent was from coal-fired units [62]. Therefore, the focus in this section is on the proposed regulations applicable to coal-fired units. Power plants with capacity greater than 25 megawatts and CHP units that are larger than 25 megawatts and sell at least one-third of their electricity would be subject to CAMR. 

The EPA estimates that CAMR, using a cap and trade approach, would reduce mercury emissions by nearly 70 percent when fully implemented. Two alternative approaches were proposed for reducing mercury emissions. The first, which would require the installation of MACT under CAAA90 Section 112, would reduce annual emissions from the electricity generation sector by about 29 percent, from 48 tons in 2002 to 34 tons in 2008. The second approach would modify Section 112 to allow regulation of mercury emissions under a cap and trade program. The program would be implemented in two phases, with a banking provision that would allow for reductions as early as 2010 and a second phase that would set a cap of 15 tons in 2018. 

Under the cap and trade approach, States would submit plans to the EPA to demonstrate that they would meet their assigned State-wide mercury emissions budgets. With EPA approval, the States could then participate in the cap and trade program. Allowances would be allocated by the States to power companies, which could either sell or bank any excess allowances. The EPA proposed a safety valve price of $2,187.50 per ounce of mercury ($35,000 per pound), adjusted annually for inflation. The price of allowances would effectively be capped at that level, and power plant operators could buy allowances at any time at the safety valve price, reducing the State’s budget in the future. Public comments on CAMR have been received, and the EPA expects to issue the final rules in March 2005.

Notes and Sources

Contact: Robert Smith
Phone: 202-586-9413
E-mail: robert.smith@eia.doe.gov