1. Background and Methodology

Introduction

Over the next decade, U.S. electric power plant operators may face significant requirements to reduce emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) beyond the levels called for in the Clean Air Act Amendments of 1990 (CAAA90). They could also face requirements to reduce carbon dioxide (CO2) and mercury (Hg) emissions. At present neither the future reduction requirement nor the timetable is known for any of these airborne emissions; thus, compliance planning is difficult.

Currently, different environmental issues are being addressed through separate regulatory programs, many of which are undergoing modification. To control acidification, the CAAA90 required operators of electric power plants to reduce emissions of SO2 and NOx. Phase II of the SO2 reduction program—reducing allowable SO2 emissions to an annual national cap of 8.95 million tons—became effective on January 1, 2000.

More stringent NOx emissions reductions are required under various Federal and State laws taking effect from 1997 through 2004. States are also beginning efforts to address visibility problems (regional haze) in national parks and wilderness areas throughout the country. Because electric power plant emissions of SO2 and NOx contribute to the formation of regional haze, States could require that these emissions be reduced to improve visibility in some areas.

In the near future, it is expected that new national ambient air quality standards for ground-level ozone and fine particulates may necessitate additional reductions in NOx and SO2. To reduce ozone formation, the U.S. Environmental Protection Agency (EPA) has promulgated a multi-State summer season cap on power plant NOx emissions that will take effect in 2004. Emissions that lead to fine particles (less than 2.5 microns in diameter), their impacts on health, and the level of reductions that might be required are currently being studied. Fine particles are emitted directly from electric power plants and are also associated with power plant emissions of NOx and SO2. Thus, further reductions in NOx and SO2 emissions could be required by as early as 2007 in order to reduce emissions of fine particles.

In addition, the EPA decided in December 2000 that Hg emissions must be reduced; proposed regulations are to be finalized by 2004. Further, if the United States decides to reduce its emissions of greenhouse gases, energy-related CO2 emissions may have to be reduced as part of that program.

Analysis Request

In both the previous and current Congresses, legislation has been proposed that would require simultaneous reductions of multiple emissions.¹ This analysis responds to a request from Senators Smith, Voinovich, and Brownback to examine the costs of specific multi-emission reduction strategies (see Appendix A for the requesting letter). In their request, Senators Smith, Voinovich, and Brownback asked the Energy Information Administration (EIA) to analyze the impacts of three scenarios with alternative power sector emission caps on NOx, SO2 and Hg. They also asked for an analysis of the potential costs of requiring power suppliers to acquire offsets for any increase in CO2 emissions that occur beyond the level expected in 2008.

Specifically, EIA was asked to analyze the following three scenarios for reducing power sector emissions:

• Scenario 1: Reduce NOx emissions by 75 percent below 1997 levels, SO2 emissions by 75 percent below full implementation of Title IV of the CAAA90, and Hg emissions by 75 percent below 1999 levels by 2012, with half the reductions for each of the emissions occurring by 2007.

• Scenario 2: Reduce NOx emissions by 65 percent below 1997 levels, SO2 emissions 65 percent below full implementation of Title IV of the CAAA90, and Hg emissions by 65 percent below 1999 levels by 2012, with half the reductions occurring by 2007.

• Scenario 3: Reduce NOx emissions by 50 percent below 1997 levels, SO2 emissions by 50 percent below full implementation of Title IV of the CAAA90, and Hg emissions by 50 percent below 1999 levels by 2012, with half the reductions occurring by 2007.

The emission reduction programs are assumed to cover all electricity generators other than industrial cogenerators,² and to operate as cap and trade programs patterned after the SO2 control program created in the CAAA90. It was requested that the analysis should assume that the programs would begin in 2002, achieving half the required reductions by 2007 and full compliance by 2012. At the request of the Senators the existing summer season NOx cap and trade program is assumed to be replaced by the annual programs established in each of the cases.

For Hg, half of the required reductions were to come from actual reductions at each unit; the rest could be achieved through allowance trading among units. In all cases, power suppliers would be able to bank emissions for future use. In other words, power suppliers could choose to reduce their emissions below the number of allowances they have in some years and hold (bank) them for use in other years. Typically a power supplier would be expected to do this in the early phase of the emission reduction programs, when relatively inexpensive compliance options are available, so that they could minimize the amount of reduction they might have to make or the number of allowances they might have to buy in the later phases, when compliance might be more expensive.

This analysis examines the steps that power suppliers might take to meet the specified caps on NOx, SO2, and Hg emissions with and without CO2 emissions capped at the 2008 reference case level. The potential benefits of reduced emissions—such as might be associated with reduced health care costs—are not addressed, because EIA does not have expertise in this area.³ The specific design of the cases—timing, emission cap levels, policy instruments used—is important and should be kept in mind when the results are reviewed.

This study is not intended to be an analysis of any of the specific congressional bills that have been proposed in this area, and the impacts estimated here should not be considered as representing the consequences of specific legislative proposals. All the congressional proposals include provisions other than the emission caps studied in this analysis, and several would use different policy instruments to meet the emission targets. Moreover, some of the actions projected to be taken to meet the emission caps in this analysis may eventually be required as a result of ongoing environmental programs whose requirements currently are not fully specified.

Representation in the National Energy Modeling System

Each of the cases analyzed was prepared using EIA’s National Energy Modeling System (NEMS). NEMS is a computer-based, energy-economic model of the U.S. energy system for the mid-term forecast horizon, through 2020. NEMS projects production, imports, conversion, consumption, and prices of energy, subject to assumptions about macroeconomic and financial factors, world energy markets, resource availability and costs, behavioral and technological choice criteria, cost and performance characteristics of energy technologies, and demographics. Using econometric, heuristic, and linear programming techniques, NEMS consists of 13 submodules that represent the demand (residential, commercial, industrial, and transportation sectors), supply (coal, renewables, domestic oil and natural gas supply, natural gas transmission and distribution, and international oil), and conversion (refinery and electricity sectors) of energy, together with a macroeconomic module that links energy prices to economic activity. An integrating module controls the flow of information among the submodules, from which it receives the supply, price, and quantity demanded for each fuel until convergence is achieved.

Domestic energy markets are modeled by representing the economic decisionmaking involved in the production, conversion, and consumption of energy products. For most sectors, NEMS includes explicit representation of energy technologies and their characteristics (Table 1). In each sector of NEMS, economic agents—for example, representative households in the residential demand sector and producers in the industrial sector— are assumed to evaluate the cost and performance of various energy-consuming technologies when making their investment and utilization decisions. The costs of making capital and operating changes to comply with laws and regulations governing power plant and other emissions are included in the decisionmaking process.

The rich detail in NEMS makes it useful for evaluating various energy policy options. Policies aimed at a particular sector of the energy market often have collateral effects on other areas that can be important, and the detail of NEMS makes the analysis of such impacts possible. For example, a policy that leads to higher prices for a particular fuel would be expected to cause residential, commercial, industrial, and transportation customers to reduce their consumption of that fuel by shifting to other fuels and/or investing in more efficient energy-using equipment. NEMS explicitly represents these choices by consumers.⁴

NEMS represents numerous options for reducing power sector emissions of NOx, SO2, and Hg. Technological options include installing combustion controls, selective noncatalytic reduction equipment (SNCR), or selective catalytic reduction equipment (SCR) to reduce NOx; flue gas desulfurization equipment to reduce SO2; and activated carbon injection equipment with or without a supplemental fabric filter or spray cooler to reduce Hg. With respect to Hg and, to a lesser extent, NOx there is some uncertainty about the cost and performance of these technologies (see discussion on Reducing NOx and Hg Emissions"). NEMS can also choose to switch fuels or retire plants and replace them with new plants using different technologies or fuels. Finally, NEMS allows consumers to choose to reduce their electricity consumption if electricity prices rise when emission caps are imposed.

Reference Case

The reference case for this analysis is based on the reference case for EIA’s Annual Energy Outlook 2001 (AEO2001). As a result, it incorporates the laws and regulations that were in place as of the end of July 2000. It includes the CAAA90 SO2 emission cap and NOx boiler standards. It also includes the 19-State summer season NOx emission cap program—referred to as the “State Implementation Plan (SIP) Call.”⁵ The settlement agreement between the Tampa Electric Company and the U.S. Department of Justice (acting for the EPA) requiring the addition of emissions control equipment at the Big Bend power plant and the conversion of the F.J. Gannon plant to natural gas was also incorporated in the AEO2001 reference case. Rules and regulations that have not been fully promulgated are not included in the reference case (see discussion on "Respresentation of New Environmental Rules and Regulations").

Because of the recent agreements between the EPA and Cinergy and Virginia Power with respect to the New Source Review (NSR) compliance action, the AEO2001 reference case has been modified for this study to incorporate the emissions control equipment that those companies have announced they will add. However, these actions could change as a result of the remaining NSR cases. The historical data used for this analysis were also updated to reflect more recent information on natural gas prices, electricity sales, and generating capability additions in 2000 that were not available when the AEO2001 reference case was prepared. In addition, natural gas prices and electricity demands have been recalibrated to EIA’s July 2001 Short-Term Energy Outlook (STEO). This recalibration resulted in higher gas prices and electricity demand than those used in the AEO2001.

Analysis Cases

As requested by the Senators, the emission reduction programs are assumed to be patterned after the SO2 emissions trading program created in the CAAA90. In other words, emissions allowances totaling to the specified limit for each emission are assumed to be allocated at no cost to power suppliers. Power suppliers are free to reduce their emissions to the level of allowances they hold or to purchase additional allowances from others who take action to reduce their emissions below the number of allowances they have. Power suppliers are assumed to behave competitively, incorporating the costs⁶ of holding allowances in the operating costs of plants that produce the targeted emissions. Assuming that efficient competitive allowance markets develop, the market price of allowances that evolves should provide both power producers and consumers with the information needed to minimize the costs of reducing the targeted emissions.

It is important to note that there are numerous policy instruments available for reducing emissions. They include technology standards, percentage reduction requirements, emission taxes, no-cost emission allowance allocation with cap and trade, emission allowance auction with cap and trade, and annual generation performance standard emission allowance allocation with cap and trade. Each of these approaches has different implications for the resource cost, price, and economic impacts of the emission reduction program. In general an efficient cap and trade program is expected to lead to the lowest resource costs of compliance.⁷ In competitive markets, electricity prices will reflect the change in variable operating costs of plants setting market prices brought about by emission reduction efforts. On the other hand, in cost-of-service markets, all generation costs—including the total costs of reducing emissions—will be reflected in the prices that consumers pay for electricity.

Table 2 and Figures 1, 2, and 3 show the emission targets in each of the three cases prepared—50-Percent, 65-Percent and 75-Percent Reduction cases. In each case it is assumed that half the required reduction must occur by 2007, and that full compliance is required by 2012. Thus, the emission limits in 2007 are set to the mid-point between the base level and the emission target level shown for each case in Table 2. In 2012 and beyond, the emission caps are set to the levels shown in Table 2.

At the request of the Senators, an additional requirement is imposed for Hg: one-half of the required reductions in each case must come from reductions at each facility, and the other half can be accomplished through trading with other facilities that have allowances to sell. To represent this requirement an estimate was made of the minimum percentage Hg removal (from the amount of Hg in the coal used) required from all units to achieve half the overall required reduction by 2007. For example, in the 65-Percent Reduction case, 28 tons of reduction (43 - 15) is required. It was estimated that if all units were required to add equipment that allowed them to achieve a minimum 55 percent removal rate (units that already removed more than 55 percent were not required to make any additional investment), approximately half the 28 tons of total reductions required would be achieved. The same procedures were used in the 50- and 75-Percent Reduction cases, but the minimum removal rates were 50 percent and 60 percent, respectively.

Power sector banking decisions were simulated by setting the emissions caps slightly below those called for in the early years of the programs and slightly higher in the later years. In all cases, it is assumed that emissions will reach the final target caps by 2020.⁸

In addition, for each of the three analysis cases an estimate is provided of the cost of purchasing carbon offsets for increases in CO2 emissions beyond the 2008 level projected in the reference case. NEMS represents only U.S. energy markets and can only provide cost estimates for reducing emissions in the U.S. energy sector. Lower cost carbon reduction opportunities that might be available in other countries and/or outside the energy sector (inside and outside the United States) are not represented in NEMS.

To estimate the potential price that U.S. power suppliers might be willing to pay for carbon offsets, each of the three analysis cases was rerun with CO2 emissions capped at the reference case 2008 level. The resulting CO2 allowance price, which represents the projected maximum price U.S. power suppliers would be willing to pay, was then compared with an estimate of the international price for carbon offsets from world energy markets. This estimate was developed using carbon reduction (abatement) curves from the Pacific Northwest Laboratory Second Generation Model (SGM), matched against the quantity of offsets projected to be needed in each of the analysis cases,⁹ to provide a rough estimate of the costs power suppliers would incur to purchase the offsets they would require in each case. No explicit reductions in U.S. power sector CO2 emissions were modeled. It is likely that the U.S. power sector would have some relatively inexpensive options available.

Notes