Report Contents
Report#:SR/OIAF/2000-05

Preface

Executive Summary

Analysis of Strategies for Reducing Multiple Emissions from Power Plants:
Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide

2. Analysis Cases and Methodology

Analysis Cases

The House Subcommittee on National Economic Growth, Natural Resources, and Regulatory Affairs requested that EIA prepare an analysis to evaluate the impacts of potential caps on power sector emissions of NO_x, SO₂, CO₂, and Hg, combined with a renewable portfolio standard (RPS) requirement. The specific assumptions and cases requested by the Subcommittee are summarized in Table 2. To respond to the Subcommittee’s request in a timely manner, the analysis has been divided into two volumes. This report addresses scenarios with NO_x, SO₂, and CO₂ emission caps, as well as scenarios analyzing the potential impacts of ongoing litigation that could require many existing coal plants to add state-of-the-art emissions control equipment. The latter cases, referred to as new source review (NSR) cases, are discussed in Chapter 5.

Table 2.  Analysis Cases

The reference case for this analysis incorporates the laws and regulations that were in place as of July 1, 2000, as EIA’s Annual Energy Outlook 2001 (AEO2001) was being prepared. It includes the CAAA90 SO₂ emission cap and NO_x boiler standards. It also includes the 19-State summer season NO_x emission cap program—referred to as the “State Implementation Plan (SIP) Call.” The settlement agreement between the Tampa Electric Company and the Department of Justice (acting for the U.S. Environmental Protection Agency) 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 is incorporated in the analysis.

Table 2 summarizes the emission targets, timetables, and RPS requirements for each case requested by the Subcommittee. The emission caps (Table 3 and Figure 1) are applied only to the electricity generation sector and are assumed to cover emissions from both utility-owned and independent power plants, excluding cogenerators. If economical, cogenerators are allowed to compete against other power plants to meet the demand for electricity. Because no requirements to reduce emissions in the residential, commercial, industrial, and transportation sectors are assumed, the results of this analysis should not be compared with the results of studies that have examined the impacts of complying with the Kyoto Protocol across all sectors of the economy.

Table 3.  1990 and 1997 Emissions Levels and Assumed Emission Caps for Electricity Generators

Figure 1.  1997 Emissions, Reference Case Projections for 2010 and 2020, and Target Caps for Electricity Generators

In addition to the cases requested by the Subcommittee, this report includes three cases that assume less stringent emission caps for SO₂ and CO₂ only, and a combined integrated case that uses the less stringent targets (Table 4). These cases were analyzed to examine the sensitivity of the results to the emission targets requested by the Subcommittee for analysis. The emission caps in the SO₂ sensitivity case were set roughly halfway between the estimated emissions for 2000 and the caps requested by the Subcommittee—roughly a 50-percent reduction from 1997 levels, rather than the 75-percent reduction specified by the Subcommittee. For CO₂ a similar approach was used. The CO₂ cap in 2005 in the CO₂ sensitivity case was set to halfway between the estimated emissions in 2000 and the 1990 level. The cap was then lowered further over the 2008 to 2012 time period to halfway between the estimated 2000 emissions and 7 percent below the 1990 level. Using this approach, the CO₂ cap in 2005 in the CO₂ sensitivity case was assumed to be 10 percent above 1990 levels, before declining to 7 percent above 1990 levels over the 2008 to 2012 time period.

Table 4.  Assumed Emission Caps for Electricity Generators in Sensitivity Cases

Using data that recently have become available, the National Energy Modeling System (NEMS) is currently being modified to represent power sector Hg emissions. The expected impacts of the other provisions in each case on Hg emissions are mentioned in Chapter 3, but the proposed Hg emission caps will be analyzed more thoroughly in the subsequent report.

In all cases it is assumed that emission caps would be phased in beginning in 2002. For the cases that require that CO₂ emissions average 7 percent below the 1990 level over the 2008 to 2012 time period, the cap is constructed so that emissions can be slightly above the 1990-7% level in the first year or two of the period and slightly below it in the later years. After 2012, the cap is held at 7 percent below the 1990 level through the remainder of the projections.⁴ In addition, it is assumed that the emission reduction programs will be operated as market-based emission cap or fee programs, and the emission allowance prices or emission fees are included in the operating costs of plants that produce one or more of the emissions.

Because there is an existing national SO₂ allowance program, it is assumed that power plant operators will be able to use any SO₂ allowances they have already accumulated. In other words, they can use allowances they have banked. They are not allowed to bank additional allowances after 2000. As a result, the power sector can exceed the SO₂ emission cap beyond the compliance date until their banked allowances are exhausted.

For this analysis, it is assumed that the power sector must explicitly reduce its emissions to meet the CO₂ cap and cannot rely on other mechanisms, such as the flexibility measures included in the Kyoto Protocol that allow countries several options for meeting their emission reduction targets, including direct emissions reductions, land use changes, and forestry changes. For example, a country could get credit for a project to plant trees (reforestation) that absorb CO₂ during their growth. Emissions trading among countries with emission caps is also permitted by the Protocol. The Protocol also covers six greenhouse gases—carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride—and reductions in any one of them count toward meeting a country’s emissions cap. At this time, rules about what type of land use and forestry projects could be implemented and how emissions trading programs might work have not been finalized. If similar provisions were included in a program to reduce power sector CO₂ emissions, the costs of meeting the target most likely would be lower.

After its initial request, the Subcommittee asked that EIA also examine the potential impacts of requiring older coal-fired power plants either to be brought into compliance with current new source performance standards or to be retired. The EPA has taken action against the owners of 32 older coal plants accusing them of making modifications without adding the emissions control equipment required by CAAA90. The first of the four cases—referred to as the New Source Review (NSR) cases—assumes that the owners of each of the 32 plants will be required to add state-of-the-art emissions control equipment by 2005 or retire the plant. The second case assumes that all coal-fired plants that currently do not have such control equipment must make the same decision by 2010. The third and fourth cases combine the assumptions of the first two  with more stringent caps on NO_x, SO₂, and CO₂ emissions.

Methodology

AEO2001 Assumptions

The analysis in this report is based on the data and NEMS algorithms used for the AEO2001.⁵ Because the AEO2001 forecasts are based on data available at the end of August 2000, the results of this analysis should be evaluated in terms of the relative differences between cases rather than the absolute values.

NEMS Representation

NEMS is a computer-based, energy-economic model of the U.S. energy system for the mid-term period, through 2020.⁶ 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. Domestic energy markets are modeled by explicitly 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 5). In each sector of NEMS, economic agents—for example, representative households in the residential demand 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.

Table 5.  National Energy Modeling System Energy Activities

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 spillover effects on other areas that can be important, and the detail of NEMS makes the analysis of such impacts possible. The remainder of this chapter describes how the cases for this analysis were implemented in the key NEMS submodules for electricity, coal, and renewables. Changes in assumptions and modeling approach for this analysis are also explained.

Representation of NO_x, SO₂, and CO₂ Emission Reduction Programs

In this analysis, it is assumed that the programs set up to reduce NO_x, SO₂, and CO₂ emissions from power plants will operate like the existing SO₂ program established in Title IV of CAAA90, and that marketable emission allowances or permits will be allocated to power plant operators at no cost (no revenue will be collected by the government). No assumption is made about the specific allocation methodology to be used, other than that it will be a fixed allocation (does not change from year to year) and the total amounts allocated will equal the national emission targets for NO_x, SO₂, and CO₂. Holders of allowances are assumed to be free to use them to cover emissions from their own power plants or sell them to others who need them.

As allowances are bought and sold, market prices will develop for them and will become part of the operating costs of plants producing the targeted emissions. For example, the total operating costs of a plant that produced one ton of a targeted emission per unit of output would be increased by the price of the allowance. Revenues associated with the sale of allowances go to the seller of the allowances. In all cases it is assumed that the allowance markets will operate as near perfect markets, with low transaction costs and without information asymmetries. In other words, there will be many buyers and sellers of allowances and information needed to evaluate their worth will be readily available. It should be pointed out that there are numerous policy instruments (taxes, emissions standards, tradable permits, etc.) that could be used to reach the proposed emission targets (see discussion on "Implementing Emission Caps:  Cost and Price Impacts"). The choice of policy instrument will have an impact on the costs of complying with the emission targets and the electricity price and income impacts seen by consumers. The analysis does not employ a generation performance standard as is proposed in several bills (see discussion on "Generation Performance Standards").

Electricity Market Module

The representation of laws and regulations governing power plant emissions is particularly important in the NEMS electricity market module (EMM). The EMM is able to simulate emission caps on SO₂, NO_x, and CO₂. In the reference case for this analysis, the CAAA90 SO₂ emission cap, both Phase I and Phase II,  is included. The  summer season NO_x emission cap (SIP Call) promulgated by the EPA is also included for 19 States, as discussed above. The EMM simulates the capacity planning and retirement, operating, and pricing decisions that occur in U.S. electricity markets. It operates at a 13-region level based on the North American Electric

Reliability Council (NERC) regions and subregions. Based on the cost and performance of various generating technologies, the costs of fuels, and constraints on emissions, the EMM chooses the most economical approach for meeting consumer demand for electricity.

During each year of the analysis period, the EMM evaluates the need for new generating capacity to meet consumer needs reliably or to replace existing power plants that are no longer economical. The cost of building new capacity is weighed against the costs of continuing to operate existing plants and consumers’ willingness to pay for reliable service.⁷ For nuclear facilities the maintenance versus retirement decisions are made for each plant when it reaches 30, 40, and 50 years of age. At the request of the Subcommittee, the option of constructing new nuclear plants is not considered in this analysis.

The EMM does represent improvements in the cost and performance of new generating technologies as they enter the market. Economic research has shown that successful new technologies tend to show declining costs as they penetrate the market. In the EMM it is assumed that the costs for new technologies decline with each doubling of capacity. As a result, if a policy stimulates the development of a particular technology the EMM will endogenously reduce the cost of that technology as it enters the market in greater quantities. The rate of decline depends on the level of penetration.

During each time period plants are brought on line (dispatched), starting with the unit with the lowest operating costs, until consumers’ demand is met. When faced with an SO₂ or NO_x emission cap on electricity producers, the least expensive reduction options available are chosen until the cap is met. The goal of the model is to minimize the costs of producing electricity while complying with emissions constraints. For example, to reduce SO₂ emissions, the options include switching to a lower sulfur fuel, reducing the utilization of relatively high SO₂ emitting plants, adding a flue gas desulfurization (FGD) system to an existing plant to remove SO₂, or retiring a relatively high emitting plant and replacing it with a cleaner plant or, through higher prices, encouraging consumers to reduce their electricity use. This approach allows for SO₂ allowance trading and banking for later use. The marginal cost of reducing emissions sets the allowance price, which is included in the operating costs of plants producing the capped emissions.⁸ In NEMS, SO₂ allowance banking decisions can be specified exogenously, or the model can solve for them endogenously. In this analysis, because of stability problems caused by the relationships among the emission caps, banking patterns were specified exogenously for each case. The bank of 11.6 million tons of SO₂ allowances accumulated through 1999 was assumed to be used between 2000 and 2015 in each case.

To reduce NO_x emissions, the options include decreasing the utilization of relatively high emitting plants, adding combustion controls that remove NO_x from the exhaust gases of a plant (i.e., low-NO_x burners) and/or post-combustion controls (i.e., selective noncatalytic reduction [SNCR] or selective catalytic reduction [SCR] equipment), retiring high emitting plants, or, through higher prices, encouraging consumers to reduce their electricity use. For this analysis the emission caps on SO₂ and NO_x specified by the Subcommittee are treated as annual national caps, and allowance trading is allowed among plants throughout the country. It is assumed that the NO_x program would operate like the existing SO₂ allowance program. As with the SO₂ program, the marginal cost of reducing NO_x emissions sets the allowance price.

To reach the power sector CO₂ emissions target, the model chooses among investments in lower emitting technologies (mainly natural gas and renewables), changes in operations of existing and new power plants (using lower emitting resources more intensively than higher emitting resources), and conservation activities by consumers (induced by higher prices). The model solves for the allowance price that encourages power suppliers and consumers to make changes in investment, operations, and conservation activities.⁹ In this analysis the CO₂ cap is applied only to the power sector, because emissions in other sectors of the economy are not restricted in the cases specified by the Subcommittee. When multiple emissions caps are imposed, the model solves for the most economical way to meet all of them simultaneously.

The steps taken to reduce NO_x, SO₂, and CO₂ emissions affect the price of electricity. The EMM has the option to price power (the generation component of the energy business) in either a regulated cost-of-service environment or a competitive market environment. Generally, in regions in which the majority of the electricity sales are in States that have passed legislation or enacted regulations to open their retail markets, generation prices are assumed to be derived competitively. The fully competitive regions include California, New York, New England, the Mid-Atlantic Area Council (consisting of Pennsylvania, Delaware, New Jersey, and Maryland), and Texas.

In regions where only a portion of the States have opened their retail markets, the regulated and competitive generation prices are weighted (by the share of sales in the respective states) to derive an average regional price. These regions include the East Central Area, the Rocky Mountain-Arizona regions, the Mid-America Interconnected Network, and the Southwest Power Pool. In all the other regions power prices are assumed to continue to be regulated; however, because wholesale generation markets throughout the country are moving toward competition, all new generators are assumed to be built as merchant power plants that will sell their power at market-based rates. For this reason, this analysis treats the allowance prices that arise when emission caps are imposed as if they were imposed on competitive markets. The allowance prices become part of the operating costs of power plants that produce the targeted emissions.¹⁰

In competitive regions, generation prices are based primarily on the operating costs of the power plant setting the market-clearing price at any given time. In other words, the plant producing power with the highest operating costs sets the price of generation during each time period. An additional adjustment is made to reflect consumers’ willingness to pay for reliable service, especially during high usage periods. When emission caps are imposed, the allowance costs or fees associated with them become part of the operating costs for power plants that produce the affected emissions. As a result, in competitively priced regions, the fees or allowance costs for SO₂, NO_x, and CO₂ become part of the operating costs for power plants that burn fossil fuels. When a plant needing emission permits sets the market price for power, the per-kilowatthour cost of holding the permits is reflected in the retail electricity price. This can lead to increased profits for companies owning plants for which emission reduction costs are below the marginal reduction costs. Equally important is the assumption that when the costs fall on plants that do not set the market price, their owners will not be able to pass any of them on to consumers. In regulated regions, the total costs associated with adding emissions control equipment, using higher cost fuels, and retiring or replacing plants to reduce SO₂, NO_x, and CO₂ emissions are recovered along with the costs of holding allowances and other costs.

To represent the RPS (to be analyzed in the forthcoming volume), the EMM has the ability to require that generation from nonhydroelectric renewable facilities (including cogenerators) be greater than or equal to a specified amount. In this analysis the required amount is determined by multiplying the specified share in a given year by the total projected sales of electricity in that year. The most economical nonhydroelectric renewable options are constructed to meet the RPS requirement. As with the emission cap programs described above, the RPS program is operated as a market credit system. It is not required that each power seller produce or purchase the required renewable share. As an alternative, they must hold renewable “credits” equal to the required share. Credits are issued to those generating power from qualifying renewable facilities and, as in the case of SO₂ allowances, may be sold to others. The projected price of the credits becomes part of the operating costs of nonqualifying facilities. In each of the RPS cases it is assumed that the program continues through 2020 and that there is no legislated limit on the credit price.¹¹

Coal Market Module

The Coal Market Module (CMM) provides annual forecasts of prices, production, and distribution of coal to the various consumption and energy transformation sectors of NEMS. It simulates production from 11 coal supply regions that meets demands for steam and metallurgical coal from 13 U.S. demand regions and incorporates an international coal trade component that projects world coal trade, including U.S. coal exports and imports.

The CMM uses a linear programming algorithm to determine the least-cost (minemouth price plus transportation cost) supplies of coal by supply region for a given set of coal demands in each demand sector in each demand region. Separate supply curves are developed in the CMM for each of 11 supply regions and 12 coal types (unique combinations of thermal grade, sulfur content, and mine type). The modeling approach used to construct the 35 regional coal supply curves represented in the CMM addresses the relationship between the minemouth price of coal and corresponding levels of coal production, labor productivity, and the cost of factor inputs (mining equipment, mine labor, and fuel requirements).

More than 90 percent of U.S. coal production is consumed domestically, and electric utilities and independent power producers account for approximately 90 percent of U.S. consumption. Steam coal is also consumed in the industrial sector to produce process heat, steam, and synthetic gas and to cogenerate electricity. Metallurgical coal is used to make coke for the iron and steel industry. Approximately 6 million tons of steam coal are consumed in the combined residential and commercial sector annually.

Coal is heterogeneous in terms of its energy, sulfur, nitrogen, carbon, and mercury content. Thus, the geographic source of coal can be a significant factor in the physical quantity of coal necessary to provide a given quantity of energy and the resultant level of emissions. Coal prices also vary significantly based on the heat content, quality, and regional source of the coal. For example, low-sulfur, low-Btu coal from the Powder River Basin in Wyoming and Montana has a minemouth price that is only about 20 percent that of some coal types mined in the Appalachian region. The variation in regional coal prices, coupled with shifts in the amount of coal originating from each region, can lead to changes in U.S. average minemouth prices across cases that are more related to altered distribution patterns than to the level of aggregate coal demand.

During each year of the forecast period, the CMM receives a set of coal demands, expressed in terms of British thermal units (Btu), required by the different sectors in each region. The demands from the electricity generation sector are further disaggregated into seven categories within each demand region that depend on boiler age, maximum allowable sulfur, and scrubber availability. The EMM also provides the sulfur cap (expressed in tons of SO₂) that represents the maximum emission level for that year. Based on these requirements, and subject to given coal contracts, a linear program within the CMM solves for a supply pattern that meets all demands at minimum cost, subject to the sulfur cap. The allowance price is calculated from this methodology; it is essentially the cost of reducing the last ton of SO₂ under the cap. This allowance price, in turn, is used by the EMM to evaluate the economics of adding FGD equipment to coal-fired generators.

For the most part, the CMM configuration used for the reference case of this study is the same as was used for the AEO2001. Certain sections of the linear program layout were restructured to provide a simplified format and improved maintenance and reporting. Other sections of the linear programming code were redesigned to accept case-specific factors to permit a generally smooth drawdown of sulfur allowance banks from current levels (as of 2000) to zero in 2010 for all cases except the sulfur cap cases, which reach zero in 2015. The latter change results in different levels and timing for scrubber retrofits relative to AEO2001.

All the analysis cases, with the exception of the NO_x cap cases (which have relatively minor impacts on U.S. coal demand), incorporate two additional changes to the CMM assumptions used for the reference case. All coal contracts (between shippers and utilities) were modified to be phased out no later than 2003. In addition, the set of model constraints that gradually increases the fraction of coal-burning capacity that can be converted to burn low-sulfur, low-Btu subbituminous coal in a given year was changed from the AEO2001 version to eliminate the constraint by 2003. The two changes were made because accelerated and more stringent emission restrictions are assumed to be likely to constitute sufficient justification to end contracts under force majeure provisions. The changes also provide the necessary economic incentive to install, on short notice, modifications to many power plants that will permit the burning of coal blends containing substantial fractions of cheaper subbituminous coal.

Renewable Fuels Module

The Renewable Fuels Module (RFM) consists of five submodules that represent the major nonhydroelectric renewable energy resources—biomass, landfill gas, solar (thermal and photovoltaic), wind, and geothermal energy. The RFM defines technology construction and operating costs, fuel resource volumes and prices (biomass, landfill gas, and geothermal), and resource limitations for each renewable generating technology. These characteristics are provided to the EMM for grid-connected central station electricity capacity planning decisions.

Other renewable energy sources modeled elsewhere in NEMS include conventional hydroelectric (in the EMM), industrial and residential sector biomass, ethanol (in the Petroleum Market Module), geothermal heat pumps, solar hot water heating, and distributed (grid-connected) commercial and residential photovoltaics. In addition to building new biomass plants, the EMM also allows coal-fired power plants to use biomass (wood and waste products) along with coal, a process referred to as “co-firing.” The amount of biomass allowed in co-firing varies from 0 to 5 percent on a heat input basis, depending on the region in which the coal plant is located. The share of biomass allowed is calculated on the basis of its availability in a particular region. Biomass co-firing gives coal-fired power plants the ability to meet environmental regulations by using an alternative low-emission fuel. It is assumed that the coal plants will incur no additional capital or maintenance costs to consume up to 5 percent of their fuel as biomass. In addition, because the trees and plants that become biomass consume CO₂ during their growth, their net emissions are assumed to be zero.

The price-quantity relationship for obtaining biomass fuel is derived from aggregated biomass supply curves that rely on data and modeling done by Oak Ridge National Laboratory to project the quantities of four types of biomass: agricultural residues, energy crops, forestry residues, and urban wood waste/mill residues. Because of recent legislative changes, this analysis (as in AEO2001)  assumes an extension of the production tax credit under the Energy Policy Act of 1992 from December 31, 1999, through December 31, 2001, granting tax-paying entities that build new wind or closed-loop biomass facilities a tax credit of 1.7 cents per kilowatthour for the first 10 years of electricity generation from qualifying facilities.