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Date: March 27, 2013 

Subject: National Emission Standards for Hazardous Air Pollutants (NESHAP) Beyond the 

Maximum Achievable Control Technology (MACT) Floor (‘Beyond-the-Floor’) 

Analysis for Revised Emission Standards for New Source Coal-and Oil-fired Electric 

Utility Steam Generating Units 

From: Nick Hutson, U.S. EPA Office of Air and Radiation 

To: Docket No. EPA-HQ-OAR-2009-0234 

Introduction 

The purpose of this memorandum is to present the data, methodology and assumptions used to conduct a 

beyond-the-floor (BTF) analysis for the emission limits that the Agency is finalizing in the 

reconsideration of certain new source standards established in the final National Emission Standards for 

Hazardous Air Pollutants (NESHAP) for Coal- and Oil-fired Electric Utility Steam Generating Units 

(EGUs). This memorandum presents the estimates of the incremental pollutant emission reduction and 

cost that would be achieved by implementing a BTF option to control hazardous air pollutant (HAP) and 

HAP surrogate emissions from new and reconstructed sources and discusses any anticipated non-air 

quality health and environmental impacts and energy requirements. 

The MACT floor level of control for new EGUs is based on the emission control that is achieved in 

practice by the best controlled similar source for each HAP or HAP surrogate in the different categories 

or subcategories. After EPA establishes MACT floor levels, CAA section 112(d)(2) requires EPA to 

consider whether more stringent BTF standards should be established. Pursuant to that section of the 

CAA, the Agency must consider “the cost of achieving such emission reduction, and any non-air quality 

health and environmental impacts and energy requirements...” before it may establish a standard that is 

based on a BTF level of control. 

As mentioned, the new source MACT floor emission limits were set based on the performance of the 

best controlled similar source within that category or subcategory. In most of these cases, it is reasonable 

to expect that the very best performing source is achieving that level of control through the application 

of well-performing control technologies, by following a disciplined and routine maintenance schedule, 

and by operating in an efficient manner. For most of the new source standards addressed in the 

reconsideration proposal, we have not identified additional technologies or HAP emission reduction 

approaches that would achieve HAP reductions greater than the new source floors for the subcategories 

– other than multiple controls in series (e.g., multiple scrubbers in series or multiple particulate matter 

(PM) controls in series), which we consider to be unreasonable from a cost perspective. We are therefore 

finalizing the floor level of control in all but two instances. We are finalizing a BTF standard for 

hydrogen chloride (HCl) and sulfur dioxide (SO2) emissions from coal-fired EGUs. Details of the EPA’s 

BTF evaluations for the new source standards in the final reconsideration notice are provided below. 

Beyond-the-floor analysis for PM from coal-fired EGUs 

It is commonly accepted that a baghouse fabric filter (FF) is the technology that provides the best level 

of PM emission reduction for coal-fired EGUs. Newly constructed coal-fired EGUs will be expected to 

install a baghouse FF to meet the new source NESHAP PM limit and the applicable New Source 
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Performance Standard (NSPS). We have considered available options that would allow a new source to 

achieve greater emission reductions than those achieved in practice by the best controlled source. The 

EPA is aware that some EGUs have installed downstream secondary PM control devices to provide for 

incremental PM reductions beyond what is achieved by the primary PM control device. However, those 

secondary “polishing” PM control devices are most often installed for one of two purposes: (1) to 

augment the control of an underperforming or undersized primary control device, or (2) to allow for 

injection of activated carbon or other powdered sorbent so that the fly ash and the sorbent remain 

separated for eventual storage, disposal, or re-use. A wet ESP (WESP) may also be installed in a new 

coal-fired EGU (usually downstream of a wet-flue gas desulfurization (WFGD) scrubber). Although the 

primary purpose of the WESP would be to control emissions of condensible PM (especially sulfuric acid 

mist), it would be expected to also provide some small incremental reduction in filterable PM (fPM) 

emissions. We have conducted a BTF analysis on a hypothetical new 500 MW plant burning coal with 

an ash content of approximately 10% and operating at an 85% capacity factor. The calculation assumed 

that the primary PM control device is a fabric filter with an air-to-cloth ratio of 4.0, and that it is 

designed to meet a fPM emission level of 75% of the final emission limit of 0.09 lb/MWh.1 Although a 

relatively small percentage of the coal ash would be expected to partition to the bottom ash, we assumed 

all of the coal ash content would exit the system as fly ash. 

We then calculated the BTF incremental cost effectiveness for installation of a downstream “polishing” 

secondary PM control device. In this case, we assumed the downstream FF would have an air-to-cloth 

ratio of 6.0 and that it would provide incremental fPM control to achieve an emission that is 50% of the 

final emission limit of 0.09 lb/MWh. In this case the polishing PM device would remove a much smaller 

amount of fPM, but at a similar (though lower) overall cost than the primary PM control device. The 

incremental cost effectiveness was calculated to be greater than $75,000 per ton of fPM. We do not 

believe that this is a reasonable cost per ton removal and it does not justify the installation of the 

downstream secondary PM control device and, therefore, we are not finalizing a BTF fPM emission 

limit. We also considered non-air quality health and environmental impacts and energy requirements. 

We found no significant non-air quality health and environmental impacts; but we acknowledge a likely 

increase in energy requirements with the installation of a downstream polishing baghouse fabric filter 

(due to increased pressure drop across the filter). 

Beyond-the-floor analysis for Hg from EGUs firing non-low rank virgin coal 

The final new source mercury (Hg) emission limit for EGUs firing non-low rank virgin coal is based on 

the use of the three times the representative detection level (3xRDL) approach and, thus, a more 

stringent BTF limit would be impractical due to measurement frequency issues described in the 

preamble to the proposed rule. As explained in the preamble and in the associated technical support 

memo (“Determination of Representative Detection Level (RDL) and 3xRDL Values for Mercury 

Measured Using Sorbent Trap Technologies,” which is available in the rulemaking docket EPA-HQOAR-2009-0234), we do not have information available to determine at this time whether a lower Hg 

emission limit could be reliably measured with sufficient frequency to allow consistent and timely 

compliance. For this reason, we have determined that it is not reasonable to establish a BTF level of 

control for Hg from this subcategory. We also considered non-air quality health and environmental 

                                                           

1

 In petitions for reconsideration, petitioners stated that operators usually target emissions that are 50 – 

75% of the emission limitation to provide for margin of error.
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impacts and energy requirements. We found no significant non-air quality health and environmental 

impacts or significant energy requirements associated with a BTF level of control. 

Beyond-the-floor analysis for Hg from EGUs firing low rank virgin coal2

The final new source Hg emission limit for EGUs firing low rank virgin coal is based on the 

performance of an existing EGU that is equipped with advanced air pollution control technology, 

including injection of brominated activated carbon upstream of a FF for the control of Hg. Although it is 

reasonable to assume that an increase in the injection rate of the brominated activated carbon would 

result in better performance and, thus, lower emissions, we do not have enough information to determine 

whether or not the increase in sorbent would result in a reduction in emissions that is cost-effective. 

The sorbent performance curve (i.e., the percent of Hg reduction versus sorbent injection rate – see 

Figure 1 for an illustrative example) tends to have a steep area where small increases in sorbent result in 

large increases in Hg removal. However, as the sorbent injection approaches its performance limitation, 

the curve becomes flat and large increases in sorbent are required for only small incremental 

improvements in Hg control. 

The sorbent injection curve tends to be very site specific and we have no way to know exactly how the 

sorbent injection curve for a new low rank coal-burning source would look. We believe that it is likely 

that the performance needed to achieve a BTF level of control would require a considerable increase in 

activated sorbent injection. Such a significant increase would result in higher levels of sorbent mixed 

with the fly ash, which may affect the viability of the resulting fly ash-sorbent mixture to be recycled for 

beneficial use (e.g., in concrete manufacture or in road construction) and, thus, its salability. Fly ash that 

cannot be beneficially recycled must be land-filled at considerable cost. 

Figure 1. Example sorbent injection performance curve 

A BTF analysis was performed on a hypothetical new 500 MW plant burning low rank virgin coal and 

operating at an 85% capacity factor. It was assumed that the fuel used in the EGU has an average Hg 

                                                           

0

10

20

30

40

50

60

70

80

90

100

Mercury Control,

%

Increasing Sorbent Injection ‐‐‐‐‐‐>
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content of 26.2 lb/TBtu (which was the average Hg content of low rank virgin coal from the 2010 Utility 

information collection request (ICR)). Based on data from U.S. Department of Energy (DOE) National 

Energy Technology Laboratory (NETL) field tests, we estimate that such a facility should be able to 

achieve a targeted emission of 75% of the final emission limit of 0.03 lb/GWh (or 0.0225 lb/GWh, 

which is an approximately 92% reduction, coal-to-stack for the average coal) by injecting 2 lb/MMacf 

(pounds of sorbent per million actual cubic feet of flue gas) of brominated activated carbon sorbent 

upstream of a well-performing FF.3

 We have also assumed that the EGU would need to increase the 

sorbent injection – to 5 lb/MMacf – to achieve a BTF emission of 50% of the final emission limit (or 

0.015 lb/GWh, which is an approximately 95% reduction, coal-to-stack). 

The increase in sorbent injection needed to achieve the BTF emission may render the captured fly ash 

(or spray dryer absorber (SDA)/FF byproduct) unfit for beneficial reuse. If the fly ash cannot be sold (or 

given away in the case of SDA/FF byproduct) for beneficial reuse, then the operator must landfill the 

resulting byproduct-sorbent mixture at considerable cost. In the DOE/NETL study (cited earlier), this 

tended to increase incremental costs ($ per pound of Hg) by approximately three-fold for plants firing 

low rank coal. 

In the cost analysis for the hypothetical new plant, we calculated incremental BTF costs ranging from 

$61,000 per incremental pound of Hg (assuming no byproduct effects) to $183,500 per incremental 

pound of Hg (assuming the sorbent renders the byproducts unusable). We do not believe that this range 

of potential incremental cost effectiveness is reasonable, therefore, we are not finalizing a BTF Hg 

emission limit for new EGUs designed for and burning low rank virgin coal. 

Beyond-the-floor analysis for SO2 emissions from coal-fired EGUs 

The best performing source for SO2 emissions from a coal-fired EGU is a conventional tangential-fired 

pulverized coal-fired boiler with a dry flue gas desulfurization (FGD) spray dryer for SO2 control. This 

is expected to be a common and well-performing control configuration for new EGUs. Other generation 

technologies (i.e., circulating fluidized bed combustors, CFB) will be expected to utilize limestone 

injection and/or downstream circulating dry scrubbers (CDS) for SO2 control. Other PC EGUs may also 

be expected to install advanced FGD technology such as spray drier absorber (SDA) for lower sulfur 

coal or a wet-FGD scrubber (WFGD) for EGUs burning medium-to-high sulfur coals. In this final 

action, the EPA used the same statistical analyses used in the proposed rule (i.e., 99% upper predictive 

limit (UPL)), and the resulting MACT floor emission limit is 1.3 pounds per megawatt-hour (lb/MWh). 

An EGU burning high-sulfur coal (e.g., coal mined in the Illinois basin) would need to reduce potential 

emissions by greater than 97% in order to meet the MACT floor emissions limit. However, a state-ofthe-art wet FGD can reduce the potential SO2 emissions rate by 98%. This level of control would result 

in an emissions rate of 1.0 lb/MWh, and EPA determined this level of control is cost effective based on 

an evaluation of the potential costs for 7 model EGUs. See Appendix to this Memorandum. The only 

technology for a high-sulfur coal-fired EGU to reduce emission below this level would be to install a 

                                                           

3 Jones, A.P.; Hoffman, J.W.; Smith, D.N.; Feeley, J.; Murphy, J.T.; “DOE/NETL’s Phase II Mercury 

Control Technology Field Testing Program: Preliminary Economic Analysis of Activated Carbon 

Injection,” Environ. Sci. Technol., 41, 1365 (2007) (Docket ID EPA-HQ-OAR-2009-0234-20074); and 

Sjostrom, S.; Durham, M.; Bustard, C.J.; Martin, C.; “Activated Carbon Injection for Mercury Control: 

Overview,” Fuel, 89, 1320 (2010) (Docket ID EPA-HQ-OAR-2009-0234-20072). 
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downstream “polishing” scrubber. We have concluded that this incremental level of control is not cost 

effective. 

As part of the BTF analysis, the EPA evaluated a hypothetical new 500 MW plant burning high-sulfur 

coal. See Appendix to this Memorandum. The calculation first assumed that the primary wet FGD is 

capable of meeting an SO2 emission level of 1.0 lb/MWh from 1.3 lb/MWh. We determined that the 

incremental cost effectiveness for that BTF level of control is less than $1,100/ton of SO2 removed, 

which is reasonable cost for SO2 removal. The remaining model EGUs’ cost effectiveness numbers were 

less than the cost per ton of SO2 removal for the high-sulfur coal, and, thus, the costs are reasonable. Id. 

The EPA conducted a similar cost analysis for the revised Utility NSPS and established a 1.0 lb/MWh 

for coal-fired EGUs.4

 The Agency has also evaluated the non-air quality health and environmental 

impacts and energy requirements of complying with a BTF level of control of 1.0 lb/MWh for all coalfired EGUs. The most significant non-air quality impact is the increased waste that may be generated 

and the increased water requirements. Going BTF to 1.0 lb/MWh may increase the volume of coal 

combustion residuals (CCRs) and water requirements by up to 3% for facilities using a wet FGD and 

20% for facilities using a SDA. However, many facilities are able to sell (for approximately $20/ton) or 

give away their CCR for beneficial reuse. Facilities that do not sell their CCRs for beneficial reuse 

would have to dispose of the additional material in appropriately designed landfills. Disposal of regular 

CCR is generally less than $20/ton. However, the cost of disposal of contaminated CCR in a specially 

designed landfill (if necessary) can be as much as $100/ton. Whether sold or deposited in an 

appropriately landfill, the additional solid waste should have minimal health or environmental impacts if 

disposal is properly addressed. We also maintain that the incremental increase in water requirements are 

reasonable and unlikely to cause adverse health or environmental impacts. Concerning the energy 

requirements, because sources will use the same controls to comply with the BTF level as would have 

been utilized based on the MACT floor, the additional energy requirements to run the pollution controls 

will be less than 1% for facilities using a SDA and less than 10% for facilities using a wet FGD. For 

these reasons, we conclude that these impacts are minor compared to the baseline requirements. 

Therefore, since the costs of going beyond the floor to 1.0 lb/MWh are reasonable and the non-air 

quality health and environmental impacts and energy requirements are not significant, we find that 1.0 

lb/MWh is achievable for new coal-fired EGUs as a BTF level of control. 

We then calculated the BTF incremental cost effectiveness for installation of a downstream “polishing” 

secondary scrubber to achieve an additional level of control beyond 1.0 lb/MWh. See Appendix to this 

Memorandum. We assumed the downstream scrubber would provide incremental SO2 control to achieve 

an emission limit of 0.70 lb/MWh. The calculated incremental cost effectiveness is greater than $31,000 

per ton of SO2 removed. We have concluded that the cost of going to 0.70 lb/MWh is not reasonable. 

We also considered non-air quality health and environmental impacts and energy requirements of 

establishing an SO2 standard of 0.70 lb/MWh. Installation of a polishing scrubber would result in 

increased scrubber solids that would either be sold, given away, or be disposed of in a coal combustion 

residuals landfill. Operation of a polishing scrubber would also result in an increase in energy 

requirements for operation of the facility. While these impacts are not significant, the incremental cost 

                                                           

4 Arguably the cost of going to 1.0 lb/MWh is zero because the Utility NSPS requires compliance with 

that number. Nevertheless, the Agency conducted an independent cost analysis. Similarly, the non-air 

quality health and environmental impacts and energy requirements that result from achieving an SO2

emission level of 1.0 lb/MWh result from the NSPS.
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of establishing a MACT BTF standard of 0.70 lb/MWh is not reasonable; therefore, we are finalizing a 

MACT limit for SO2 emission at the BTF level of 1.0 lb/MWh. 

Beyond-the-floor analysis for PM from solid oil-derived fuel-fired EGUs 

This analysis is very similar to that which was presented earlier for PM emissions from coal-fired EGUs. 

We believe that the incremental costs would be very similar to those presented for coal-fired EGUs. As 

with the coal-fired source, such a device would add considerable costs to the project, and the 

incremental cost effectiveness (i.e., the $/ton for the incremental PM reduction – which was calculated at 

> $75,000 per ton of fPM for new coal EGUs) would not be reasonable. We also considered non-air 

quality health and environmental impacts and energy requirements. We found no significant non-air 

quality health and environmental impacts; but we acknowledge a likely increase in energy requirements 

with the installation of a downstream polishing baghouse fabric filter (due to increased pressure drop 

across the filter). 

Beyond-the-floor analysis for SO2 from solid oil-derived fuel-fired EGUs 

The best performing source for SO2 emissions from solid oil-derived fuel-fired EGUs is a CFB 

combustor with limestone injection for SO2 control. Solid oil-derived fuel is most often fired in CFB 

boilers; and, as mentioned earlier, this limestone injection control configuration will be the most 

commonly used for CFB boilers. The final new source emission limit for SO2 is the same as for the coalfired EGU subcategory (1.0 lb/MWh) and the same arguments present earlier for why we do not believe 

that installation of a downstream scrubber is cost effective can also be made here. For coal-fired EGUs, 

we calculated that the incremental cost effectiveness would be >$31,000 per ton of SO2 removed and we 

believe that the costs would be the same or very similar for solid oil-derived fuel EGUs. We do not 

believe that the cost of going BTF is reasonable, and, therefore, we are not finalizing a BTF SO2

emission limit. Non-air quality health and environmental impacts and energy requirements would be 

similar as for a coal-fired EGU. 

Beyond-the-floor analysis for PM from continental liquid oil fuel-fired EGUs 

The final new source fPM emission limit for continental liquid oil-fired EGUs is based on an EGU that 

uses an electrostatic precipitator (ESP). Distillate oil-fired facilities do not need add-on PM controls 

(their emissions are inherently low) and residual oil-fired EGUs cannot use FFs for PM control due to 

concerns about bag contamination and fire safety. Therefore ESPs are the best fPM control technology 

for liquid oil fuel-fired EGUs. The final new source emission limit is 0.4 lb/MWh. The performance of 

an ESP is based on the properties of the ash (particle size, particle resistivity, etc.). We do not have the 

necessary information to determine if a BTF level of performance can be obtained at liquid oil-fired 

EGUs and therefore, we are not finalizing a BTF emission limit. 

Beyond-the-floor analysis for all HAP emissions from IGCC EGUs 

We have no data upon which to assess whether any other technology would provide additional control, 

in a cost effective manner, beyond the final new source emission limits for HAP emissions from new 

IGCC EGUs. Accordingly, we are not finalizing BTF emission limitations for these pollutants for new 

IGCC EGUs. 
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Beyond-the-floor analysis for HCl emissions from coal-fired EGUs 

For HCl, the EPA’s revised floor analysis for coal EGUs resulted in a revised MACT floor of 0.020 

lb/MWh. We have estimated that a new coal-fired EGU would need to remove HCl in the range of 81.0 

to 96.6% (depending upon the initial chlorine (Cl) content of the fuel) in order to meet this revised 

MACT floor emission standard. We also note that it is reasonable to expect that in most, if not all, cases, 

advanced FGD control technology (such as a WFGD scrubber or a high efficiency SDA) would be 

required as a result of other federal requirements – specifically a prevention of significant deterioration 

(PSD) best available control technology (BACT) analysis. 

A high efficiency SDA is less costly than a WFGD, and we think it likely that some new sources will be 

able to comply with PSD/BACT requirements using that less expensive option. For this reason, we 

believe that it is reasonable to assume the minimum level of performance for HCl control from a new 

EGU will be equivalent to that of a well-performing SDA for purposes of the BTF analysis. We 

examined the level of HCl control achieved by those EGUs from the 2010 Utility ICR database that 

were equipped with SDA and we determined that those EGUs achieved HCl control in a range of 90 to 

98% (coal-to-stack, depending on the coal Cl content). 

In addition, because we have determined that no additional controls will be required to comply with a 

BTF level of control for HCl, we do not believe that there are any non-air quality health or 

environmental impacts or additional energy requirements associated with establishing a limit based on a 

BTF level of control. 

We therefore are finalizing a BTF HCl emission limit for new coal-fired EGUs at 0.010 lb/MWh. We 

believe that a new EGU firing lower Cl-content coal would need to achieve a minimum of 90% control 

to meet this final limit and that a new EGU firing a higher Cl-content coal would need to achieve a 

minimum of 98% control to meet the limit. We believe that this BTF emission limit is cost-effective 

because it does not involve additional cost as we expect that any new EGU will need to install at least a 

high efficiency SDA to comply with other CAA requirements. 

We also considered a BTF emission limit by assuming installation of a WFGD scrubber, which 

generally achieves greater HCl reductions, but at somewhat greater cost, than a high efficiency SDA. 

We understand that some new coal-fired EGUs will likely be required to install this type of advanced 

FGD technology for SO2 control. However, if the EGU is not required to install a WFGD scrubber as a 

result of the PSD BACT determination for SO2, then the additional costs beyond those for a high 

efficiency SDA would be attributable only to the achievement of additional HCl emission reductions. 

For cost assumptions, we used information in Table 5-4 (Illustrative Scrubber Costs (2007$) for 

Representative Sizes and Heat Rates under the Assumptions in EPA Base Case v.4.10) from Chapter 5 

(Emission Control Technologies) of the Integrated Planning Model (IPM) v 4.10 documentation. We 

calculated the incremental cost for the WFGD scrubber to be $11,404 per ton of HCl removed. We do 

not find this to be cost effective and, thus, we are finalizing a BTF value of 0.010 lb/MWh. 
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APPENDIX – Detailed BTF SO2 Cost Analysis 

Impacts Estimate General Approach 

Cost estimates of establishing MACT based on a beyond the floor (BTF) level of control were prepared 

for hypothetical “model plants” representative of the coal-fired EGUs and associated control system 

configurations that may be built in the United States in the foreseeable future. The basis for the control 

system cost estimates are control algorithms and procedures developed by the EPA Clean Air Markets 

Division (CAMD). The cost estimates were prepared applying the applicable control system costing 

models used for the EPA Base Case v4.10_PTox analysis using the EPA’s Integrated Planning Model 

(IPM (available at: http://www.epa.gov/airmarkt/progsregs/epa-ipm/toxics.html) to the model plant 

configurations selected for this analysis. The capital costs for all the control systems were annualized 

using a capital recovery factor that assumes an interest rate of 7% and a period of 20 years. All costs are 

expressed as 2009 dollars. In addition, since the IPM cost procedures are primarily intended to estimate 

costs of retrofitting controls to existing units, the costs estimated by the IPM are reduced a retrofit factor 

of 0.77 to account for the controls being installed at model plants representing new EGUs. For retrofit 

applications on reconstructed facilities, both the baseline and analyzed costs would be higher. Capital 

costs generally represent between 1/2 and 2/3 of the annual costs of a SO2 scrubber application. 

Therefore, the incremental cost effectiveness for reconstructed facilities would be between 10% and 

15% higher than for new facilities. Since the costs are similar, we determined the same conclusions are 

appropriate for both new and reconstructed facilities. 

The costing algorithms and procedures used for this impact analysis are intended to provide “study 

estimate” costs. Cost values obtained by this type of cost estimation method are on the order of ± 30% of 

the presumed actual costs for the control system being modeled. The model EGUs selected for this 

impact analysis do not represent specific actual coal-fired EGUs currently operating or under 

construction in the United States. Furthermore, the control costs estimated by this analysis are not 

intended to be directly applied to a specific coal-fired EGU plant location. Actual control costs for a 

given coal-fired EGU project will be determined by the detailed site-specific factors, and therefore can 

be higher or lower than the costs presented in this memorandum. However, the cost and impact values 

derived from a model plant analysis provide reasonable estimates for the purpose of evaluating the 

impacts of establishing a MACT standard based on a BTF level of control for SO2 emissions from 

EGUs. 

Model Plant EGU Descriptions 

Costs for installing and operating the air pollution controls were estimated by assigning specific air 

pollution control configurations to an array of seven model plants representing EGUs varying in 

characteristics of the coal burned, boiler types, and generating capacity. Five of the model EGUs 

represent pulverized coal-fired (PC-fired) boilers burning either bituminous coal, subbituminous coal, or 

lignite. The coal types were selected for these model plant EGUs to represent a typical low-sulfur, 

medium-sulfur, and high-sulfur content coal that would be burned in a new EGU. Two additional model 

plant EGUs represent boilers that use fluidized-bed combustion (FBC) technology and burn lignite or 

coal refuse. The boiler sizes were selected to approximately span the range of typical conventional coalfired EGUs expected to be built in the United States. Boiler sizes are expressed in terms of the model 

plant EGU’s gross electricity output in megawatts electric (MWe). 
- 9 - 

The model plant EGU configurations defined for the impact analysis are described in Figure 1. All of the 

model plant EGUs with the exception of the 100 MW size boilers are projected to have a gross 

efficiency of 38% (8,979 Btu/kWh) and assumed to be operated as base load units with an annual 

capacity factor of 85%. Supercritical steam turbines are not available below approximately 200 MW and 

coal refuse-fired EGUs tend to be less efficient that EGUs burning higher rank coals. To account for 

this, the 100 MW subbituminous and coal refuse-fired boiler were projected to have gross efficiencies of 

36% (9,478 Btu/kWh) and 34% (10,035 Btu/kWh) respectively and annual capacity factors of 85%. 

However, at these high levels of control the impact of the efficiency assumption is minimal. 

Figure 1. Coal-fired EGU “Model Plant” Configurations

Model 

Plant 

Boiler 

Type 

Coal 

Burned 

Gross 

Generating 

Capacity 

(MWe) 

Gross 

Heat Rate 

(Btu/kWh) 

Uncontrolled 

SO2 Emissions 

Rate 

(lb/MMBtu) 

Acid Gas 

Control 

A PC Low-sulfur Subbituminous 100 9,478 0.90 SDA 

B PC Low-sulfur Subbituminous 500 8,979 0.90 SDA

C PC Medium-sulfur Bituminous 500 8,979 3.44 WFGD

D PC High-sulfur Bituminous 500 8,979 6.89 WFGD

E PC Lignite (Gulf Coast) 500 8,979 2.07 WFGD

F FB Lignite (North Dakota) 400 8,979 2.50 CFB + SDA

G FB Coal refuse 100 10,035 5.46 CFB + SDA

The regulatory baseline acid gas emissions rate is the calculated MACT floor emissions rate of 1.3 lb 

SO2/MWh of gross output. 

SO2 Emissions Control Costs Impacts 

For the incremental impact analysis, it is assumed that in general when it has been demonstrated to be 

achievable the same type of FGD controls for SO2 would be installed on a given model plant EGU to 

comply with either the floor SO2 emissions limit or the BTF limits under consideration. Therefore, there 

would be an incremental increase in the capital and annual costs for the applicable FGD control system 

to achieve the higher performance levels (i.e., higher SO2 emissions control efficiency) needed to meet a 

more stringent BTF limit due to design modifications and operating changes to the controls. 

The SO2 control system configuration used for a given model plant EGU depends on the type of coal 

burned. The model plant EGUs representing PC-fired boilers firing either bituminous coal or lignite are 

assumed to use limestone-based wet scrubbers (Model plants C, D, E). The model plant EGUs 

representing PC-fired boilers firing subbituminous coal are assumed to use a lime-based spray dryer 

adsorber (SDA) system (Model plants A, B). The model plant EGUs representing FBC boilers firing 

lignite and coal refuse (Model plants F and G) are assumed to use limestone injection for primary 
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control followed by lime injection into the ductwork prior to the fabric filter for additional control. To 

estimate costs for model plants F and G, it is assumed that 80% SO2 control in the fluidized-bed 

followed by the post-combustion control to achieve the additional required SO2 removal. To be 

conservative, the incremental costs were modeled using the SDA costing assumptions. A circulating dry 

scrubber (CDS) has the potential to offer cost savings, but we do not have a cost model for this 

technology. 

The capital costs values for both the limestone-based wet FGD and the lime-based dry FGD systems are 

based on 98% and 95% control efficiency respectively. However, the capital and variable costs do not 

vary with changes in design control efficiency. As explained below, factors were added to account for 

these changes to more accurately reflect the incremental impacts of the revised limit under 

consideration. The capital cost values were adjusted using the relative capital cost values calculated 

from the Integrated Environmental Control Model (IECM) version 6.2.4 developed by Carnegie Mellon 

University with support from the National Energy Technology Laboratory (NETL) (available at: 

http://www.cmu.edu/epp/iecm/download_current.html). The IECM has significantly lower capital cost 

projections, but the default medium-sulfur Appalachian bituminous and Powder River Basin 

subbituminous IECM coals were used to develop relative cost curves for the wet scrubber and SDA at 

various design efficiencies. The adjustment factors used for wet scrubber and SDA systems are 

presented in Equations 1 and 2 respectively where %R represents the percentage of SO2 reduction. 

These factors were then applied to the IPM costs at different control efficiencies. 

7.622 כ ሺ%ܴሻଶ െ 14.011 כ ሺ%ܴሻ ൅ 7.4102 [Equation 1] 

0.2544 כ ሺ%ܴሻଶ െ 0.3314 כ ሺ%ܴሻ ൅ 1.0841 [Equation 2] 

The lime injection rate for model plant F and corresponding waste generation rate were adjusted using 

the reagent ratio developed for IECM and relative percent control, compared to the base of 95% control. 

The adjustment factor is shown in Equation 3. 

ሺሺ1.495 െ LNሺ1 െ %ܴሻሻ 4.4907 ⁄ ሻ*(%R/0.95) [Equation 3] 

The limestone addition rate and waste generation rate for the wet scrubbing system was scaled directly 

with the percent control relative to the 98% base control efficiency. 

The makeup water rates for both the SDA and wet scrubbing systems and the auxiliary power 

requirements for the SDA were scaled using the values calculated by the IPM equations at a zero sulfur 

inlet rate and the relative control efficiencies, compared to the base control efficiency. The wet scrubber 

auxiliary power requirements were scaled using factors developed from the IECM model similar to the 

capital costs. Equation 4 lists the factor that was applied to the auxiliary power requirements are varying 

percent removals. 

124.32 כ ሺ%ܴሻଶ െ 231.65 כ ሺ%ܴሻ ൅ 108.62 [Equation 4] 

The use of this factor can result in relatively low auxiliary power requirements, but since the purpose of 

this analysis is to estimate the incremental impacts of revised standards compared to existing standards it 
- 11 - 

was concluded that the results are sufficient to account for the increased pumping requirements due to 

the increased liquid to gas ratios at higher removal efficiencies. 

Using adjustment factors based on the EPA’s Coal Utility Environmental Cost (CUECost) model was 

considered (available at: http://www.epa.gov/nrmrl/pubs/600r09131/600r09131.pdf). However, the 

CUECost model does not vary auxiliary power requirements and it was concluded that it was therefore 

more appropriate to use IECM for the adjustment values. 

Figure 2 presents the estimated incremental impacts of going BTF acid gas emissions rate of 1.0 

lb/MWh to the limit of 1.0 lb SO2/MWh for model plants C, D, and E based on the assumption that these 

facilities would use improved limestone-based wet scrubbers to meet the lower SO2 emissions limit. 

Figure 3 presents the estimated incremental impacts of going BTF to 1.0 lb/MWh SO2 emissions limit 

for the model plants A and B and FBC boilers firing lignite and coal refuse (model plants F and G) 

based on the assumption that these facilities would use an improved lime-based SDA system to meet the 

lower SO2 emissions limit. A significant distinction between this analysis and the NSPS analysis is the 

baseline control technology for the coal refuse-fired EGU. The floor level of control requires the use of a 

secondary polishing scrubber and the costs are based on incremental improvement in that polishing 

scrubber. 

Figure 2. Limestone-Based Wet FGD Annual Incremental Impacts

Model 

Plant 

Annual 

Costs 

($1,000) 

SO2

Emissions 

Reduction 

(tons) 

Incremental 

Cost 

Effectiveness 

($/ton) 

Electricity 

Use (MWh)

Solid 

Waste 

Generated 

(tons) 

Water Use 

(1,000 gal) 

Limestone 

Use (tons) 

Chemically

Created 

CO2 (tons)

C 526 551 954 4,426 3,507 188 986 379 

D 620 576 1,077 6,326 3,734 197 1,029 396 

E 301 552 545 1,305 3,419 202 986 379 

Figure 3. Lime-base Dry FGD System Annual Incremental Impacts

Model 

Plant 

Annual 

Costs 

($1,000) 

SO2

Emissions 

Reduction 

(tons) 

Incremental 

Cost 

Effectiveness 

($/ton SO2) 

Electricity 

Use (MWh)

Waste 

Generated 

(tons) 

Water Use 

(1,000 gal) 

Lime Use 

(tons) 

A 82 112 726 2 838 16 368 

B 350 555 631 9 3,944 78 1,733 

F 181 445 408 7 1,906 62 830 

G 95 114 838 2 1,059 16 467 

We also evaluated the incremental cost of going from 1.0 lb/MWh to an emissions limit of 0.70 lb/MWh 

gross output. The model plant burning high-sulfur bituminous coal (model plant D) would be unable to 
- 12 - 

achieve an emissions rate of less than 1.0 lb/MWh with the emissions reductions that have been 

currently demonstrated for wet scrubbers. Therefore, the facility would have to install a polishing spray 

dryer in addition to a wet scrubber. To estimate these costs, we modeled a wet scrubber to achieve the 

initial 95% reduction in SO2 emissions. The flue gases would then enter a SDA for an additional 77% 

reduction for an overall reduction of 99%. Figure 4 shows the incremental impacts of adding a polishing 

scrubber to model plant D. 

Figure 4. Polishing SDA Annual Incremental Impacts

Model 

Plant 

Annual 

Costs 

($1,000) 

SO2

Emissions 

Reduction 

(tons) 

Incremental 

Cost 

Effectiveness 

($/ton) 

Electricity 

Use (MWh)

Solid 

Waste 

Generated 

(tons) 

Water Use 

(1,000 gal) 

Limestone 

& Lime 

Use (tons) 

Chemically

Created 

CO2 (tons)

D 17,087 540 31,669 13,018 (15,222) 183,460 (2,751) (2,692) 

We conclude that it is not reasonable to establish a MACT standard based on a BTF level of control 

below 1.0 lb/MWh due to the high incremental costs of achieving the additional reductions. .