1 

MEMORANDUM 

From: Office of Air Quality Planning and Standards 

 U.S. Environmental Protection Agency 

To: EGU NSPS Docket (EPA-HQ-OAR-2011-0044) 

Date: March, 2011 

Subject: Incremental Control Cost, Energy, and Environmental Impacts of Revisions to Electric 

Utility Steam Generating Unit NSPS under 40 CFR Part 60 subpart Da 

Introduction 

The New Source Performance Standards (NSPS) under 40 CFR 60 subpart Da presently regulate the 

emissions of total filterable particulate matter (PM), sulfur dioxide (SO2), and nitrogen oxides (NOX) 

from new, modified, and reconstructed electric utility steam generating units (EGUs), as defined in the 

rule. The Clean Air Act (CAA) section 111(b)(1)(B) requires the U.S. Environmental Protection 

Agency (EPA) to periodically review and, if appropriate, revise NSPS to reflect improvements in 

emissions reduction methods. The EPA’s review of the NSPS for EGUs determined that revision of 

the existing NSPS for PM, SO2, and NOX emissions are appropriate to reflect the performance 

achievable by the best demonstrated technologies for controlling these pollutants. We have also 

concluded it is appropriate to cover petroleum coke-fired EGUs under subpart Da since the control 

costs would be similar as for coal-fired EGUs. 

NSPS are required under CAA section 111 to reflect the application of the best system of emissions 

reductions that EPA has determined to be adequately demonstrated (taking into account the cost of 

achieving such reductions, any non-air quality health and environmental impacts and energy 

requirements). The purpose of this memorandum is to describe the methods used for and present the 

results of EPA’s analysis to estimate the cost, non-air quality environmental, and energy impacts of 

achieving the emissions reductions that could be required under revisions to the PM, SO2, and NOX

emission standards in the existing EGU NSPS. 

Pollutants Emitted 

Emissions from EGUs contain, among other things, substantial amounts of PM, SO2, NOX, and carbon 

monoxide (CO). PM is associated with premature mortality and a number of serious adverse 

respiratory and cardiovascular effects, especially in children, the elderly, and people with existing heart 

or lung disease. PM also reduces visibility and damages building materials. SO2 is a criteria pollutant 

and is considered harmful to public health and the environment. It contributes to respiratory illness, 

particularly in children and the elderly, and aggravates existing heart and lung diseases. It also 

contributes to acid deposition and damage to forests, aquatic ecosystems, crops, and building materials. 

SO2 undergoes chemical reactions in the atmosphere to form sulfate PM. NO2 (measured collectively 

along with other nitrogen oxide compounds as the surrogate compound NOX) is a criteria pollutant and 

is regulated due to its contribution to ozone formation. Exposure to ozone has been linked to negative 

health and welfare impacts and includes impaired respiratory function, eye irritation, deterioration of 

materials such as rubber, and necrosis of plant tissue. NOX is also a major precursor for nitrate PM. 

NOX can cause irritation of the lungs and can also reduce resistance to respiratory infection. Because 

of its contribution to tropospheric ozone, NOX is also an indirect greenhouse gas (GHG). However, 

like tropospheric ozone, NOX increases hydroxyl (OH) abundance, which in turn decreases the 
2 

atmospheric lifetime of potent GHGs like methane. CO is a criteria pollutant and is considered 

harmful to public health and the environment. It has been linked to increased risk to heart disease, 

reduced visual perception, cognitive functions and aerobic capacity, and possible fetal effects. CO is a 

weak GHG on its own. However, CO reacts with atmospheric OH to function as an indirect GHG, 

because decreased concentrations of OH in the atmosphere increase the atmospheric lifetime of 

stronger GHGs like methane. 

Impacts Estimate General Approach 

Control technologies for steam generating units are based on pre-combustion controls, combustion 

controls, post-combustion controls, or a combination of approaches. Pre-combustion controls remove 

contaminants from the fuel before it is burned, and combustion controls reduce the amount of 

pollutants formed during combustion. Post-combustion controls remove pollutants from the flue gases 

before the gases are released to the atmosphere. To comply with the existing EGU NSPS, affected 

owners/operators of new coal-fired EGUs need to install air pollution controls to meet the emission 

standards for filterable PM, SO2, and NOX. The specific control configurations used for an individual 

EGU will depend on site-specific factors including type and characteristics of the coal burned and the 

type of boiler used to burn the coal. The costs to install and operate these controls will be incurred 

regardless of any revisions to the emission standards. Consequently, the control configuration used for 

a new coal-fired EGU to meet the existing EGU NSPS represents the reference point or “regulatory 

baseline” from which the additional control costs and associated non-air quality and energy impacts of 

complying with any alternative emission standards are determined. Revisions to the existing EGU 

NSPS would require further reductions in the amounts of total PM, SO2, and NOX emitted from coalfired EGUs subject to rule that begin construction, modification, or reconstruction. 

Cost, non-air quality environmental, and energy impacts estimates were prepared for hypothetical 

“model plants” representative of the coal-fired EGUs and associated control system configurations that 

may build in the United States in the foreseeable future. The basis for the control system cost 

estimates (with one exception described later in this memorandum) 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 the all 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. 

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 plant EGUs selected for 

this impact analysis do not represent specific actual coal-fired electric utility power plant 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 electric utility power 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 revisions to the existing EGU NSPS. 

Model Plant EGU Descriptions 
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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 plant 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 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). 

The model plant EGU configurations defined for the impact analysis are described in Table 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%. 

Table 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) 

Annual 

Capacity 

Factor 

A PC Low sulfur Subbituminous 100 9,478 0.90 85% 

B PC Low sulfur Subbituminous 500 8,979 0.90 85%

C PC Medium sulfur Bituminous 500 8,979 3.44 85%

D PC High sulfur Bituminous 500 8,979 6.89 85%

E PC Lignite (Gulf Coast) 500 8,979 2.07 85%

F FB Lignite (North Dakota) 400 8,979 2.50 85%

G FB Coal refuse 100 10,035 5.46 85%

The regulatory baseline defined for each model plant used for the incremental impact analysis is 

presented in Table 2. The regulatory baseline PM emissions rate is the controlled emissions rate 

assuming the use of a fabric filter for PM control for all units. The regulatory baseline SO2 emissions 

rate depends upon the potential SO2 emissions rate based on assuming all of the sulfur in the coal is 

converted to SO2 when burned. In all cases flue gas desulfurization (FGD) is assumed. The regulatory 

baseline NOX emission rate for PC-fired boilers assumes that new PC-fired boilers are installed with 

low NOX burners as standard equipment plus selective catalytic reduction (SCR). The regulatory 

baseline NOX emission rate for FBC boilers assumes good combustion plus selective non-catalytic 

reduction (SNCR). 
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Table 2. Coal-fired EGU “Model Plant” Regulatory Baseline Emissions Levels

Model 

Plant

Particulate Matter Sulfur Dioxide (SO2) Nitrogen Oxides (NOX) 

Emissions 

Rate 

(lb/MMBtu) 

PM Controls 

Assumption 

Emissions Rate 

(lb/MWh) 

SO2 Controls 

Assumption 

Emissions 

Rate 

(lb/MWh) 

NOX Controls 

Assumption 

A 0.034 Fabric Filter 1.4 FGD 1.0 LNB + SCR 

B 0.034 Fabric Filter 1.4 FGD 1.0 LNB + SCR

C 0.034 Fabric Filter 1.5 FGD 1.0 LNB + SCR

D 0.034 Fabric Filter 3.1 FGD 1.0 LNB + SCR

E 0.034 Fabric Filter 1.4 FGD 1.0 LNB + SCR

F 0.034 Fabric Filter 1.4 FGD 1.0 SNCR 

G 0.034 Fabric Filter 2.7 FGD 1.0 SNCR 

PM Emissions Control Impacts 

Controls for filterable PM are well established, and the PM control that would be used by any new 

coal-fired EGU would be use of a fabric filter (i.e., baghouse) or an electrostatic precipitator (ESP). 

Either of control devices can achieve the high control efficiencies need to meet the existing limit and 

control both coarse and fine filterable PM. For the impact analysis, the PM emissions regulatory 

baseline is assumed to be 0.034 lb/MMBtu and is defined to be installation of fabric filters on all units. 

It is assumed that to meet any revised PM emissions limit, this fabric filter would be used in 

combination with additional PM control devices. 

The revised PM emissions limit would be a total PM emissions limit that includes both filterable PM 

and condensable PM. To meet this total PM emissions limit, it is assumed that the addition of dry 

sorbent injection (DSI) upstream of the fabric filter and a wet electrostatic precipitator (WESP) 

downstream of the fabric filter would be necessary to achieve the higher performance level needed to 

achieve the limit. The DSI system would reduce the sulfuric acid mist portion of the condensable PM. 

The WESP would further reduce condensable PM and additional filterable PM that is not collected by 

the fabric filter. The controlled total PM emissions rate for this PM control system configuration 

(addition of DSI and a WESP to the baseline fabric filter) as applied to all of the model plants is set at 

0.055 lb/MWh. 

The DSI costs are estimated by adapting the cost algorithms developed for the IPM (available at: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/append5_4.pdf) for control of SO2 emissions 

to control of sulfur trioxide (SO3) emissions. The algorithms estimate total project capital costs, fixed 

operating and maintenance (fixed O&M) costs, and variable operating and maintenance (variable 

O&M). The DSI cost algorithms require the user inputs: EGU unit size, EGU gross heat rate, 

particulate control device type, sorbent characteristics, SO2 rate, and coal type. To estimate the DSI 

costs, the following assumptions were made: 

 Sorbent reacts with and removes acid gas emissions from the flue gas stream preferentially in 

the following order: SO3, HCl, and SO2. 

 1.5% of potential SO2 emissions are converted to SO3 in the PC-fired EGUs and 1.0% in the 

CFB EGUs. This is based on assuming 1.0% conversion in the boiler and 0.5% in the SCR. The 
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CFB boilers install SNCR systems instead of SCR systems, so the additional 0.5% conversion 

is not associated with the CFB boilers. 

 Trona is the sorbent used. 

 Control system provides 90% removal of SO3. 

 IPM DSI cost algorithms are valid when substituting SO3 potential emissions rate for the SO2

potential emissions rate. 

 Reaction of each ton of trona with SO3 chemically generates 0.39 tons of carbon dioxide (CO2). 

The current version of the IPM does not include a costing model for WESPs. Therefore, the WESP 

costs are estimated using the results from an EPA sensitivity analysis for the Clean Air Interstate Rule 

(CAIR) (available at: http://www.epa.gov/cair/pdfs/0053-2263.pdf). The EPA estimated the cost 

impacts for CAIR using the IPM. The cost method provided capital, fixed O&M, and variable O&M 

costs as a function of EGU size. A scaling factor was provided, as the base unit of the method was a 

500 MW unit. Electricity use for the WESP is assumed to be 0.5 % of the EGU gross output. The 

WESP costs from the CAIR analysis were in 2002 dollars. To calculate 2009 dollars, the Chemical 

Engineering Price Costing Index (CEPCI) was used for the capital cost, and an inflation rate of 2.5% 

per year was used for the variable O&M and fixed O&M costs. 

For those coal-fired EGUs using wet scrubber systems for SO2 emissions control to meet the existing 

EGU NSPS, it is assumed that the wastewater from the WESP would be recycled to the wet scrubber. 

Coal-fired EGUs without an existing wastewater treatment system capable of handling the additional 

wastewater stream from the WESP would need to build and operate a suitable wastewater treatment 

system. Costs for such a system are not included in the analysis. 

The capital, variable operation and maintenance (O&M), and fixed O&M costs were estimated 

individually for each model plant for the DSI system and the WESP. All costs were summed to 

calculate total capital, total variable O&M, and total fixed O&M costs for both the DSI and WESP 

systems. Then, the annual costs for DSI and WESP systems were summed to provide total annual cost 

for the DSI and WESP system. The cost effectiveness is the total annual cost per ton of PM reduction. 

Table 3 presents the estimated incremental impacts of revising the EGU NSPS PM emissions limit for 

all of the model plant EGUs relative to impacts of using only a fabric filter to meet the existing PM 

emissions limit. The PM control system configuration (addition of both DSI and a WESP to the 

baseline fabric filter) used to estimate the impacts presented in Table 3 is a conservative assumption 

(i.e., likely overstates the control costs) with respect to estimating the total PM emissions reduction 

cost impacts for the model plant EGUs. Any new EGU using a spray dryer absorber for SO2 emissions 

control would not require the additional cost of DSI because the sorbent used for SO2 control would 

also control SO3 emissions. In addition, the cost impact analysis for all model plant EGUs does not 

account for the benefit of additional SO2 emissions reduction that would occur with the use of the 

WESP. 
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Table 3. DSI with WESP Control System Annual Incremental Impacts

Model 

Plant 

Annual Costs 

($1,000) 

PM 

Emission 

Reduction

(tons) 

Incremental 

Cost 

Effectiveness 

($/ton PM) 

Electricity 

Use 

(MWh) 

Trona 

Use 

(tons) 

Chemically 

Created 

CO2

DSI WESP Total (tons) 

A $767 $806 $1,573 99 $15,900 8,563 0.15 0.1 

B $2,314 $2,579 $4,893 475 $10,300 42,815 0.71 0.3 

C $3,319 $2,579 $5,898 475 $12,400 42,815 2.7 1.1 

D $4,335 $2,579 $6,914 475 $14,600 42,815 5.4 2.1 

E $2,744 $2,579 $5,323 475 $11,200 42,815 1.6 0.6 

F $2,178 $2,193 $4,371 380 $11,500 34,252 1.0 0.4 

G $1,094 $806 $1,900 106 $17,900 8,563 0.64 0.2 

SO2 Emissions Control Impacts 

For the incremental impact analysis it is assumed that in general the same type of FGD controls for 

SO2 would be installed on a given model plant EGU to comply with either the existing NSPS SO2 

emissions limit or the revised limit 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 

revised limit due to design modifications and operating changes to the controls. Because of the unique 

environmental benefits that coal refuse-fired power plants provide, EPA concluded it is appropriate to 

maintain the existing EGU NSPS SO2 emissions limits as applied to owners/operators of affected 

facilities burning 75% or more coal refuse on an annual basis. Therefore, there would no incremental 

SO2 emissions control impacts for model plant G from the NSPS SO2 emissions limit revisions under 

consideration. 

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 a FBC boiler firing 

lignite (Model plant F) is assumed to use limestone injection for primary control followed by lime 

injection into the ductwork prior to the fabric filter for additional control. To estimate costs for model 

plant F, 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. 

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. 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: 
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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 use 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 was concluded 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. 

Table 4 presents the estimated incremental impacts of revising the EGU NSPS SO2 emissions limit for 

the model plant EGUs representing PC–fired boilers firing either bituminous coal or lignite (Model 

plants C, D, E) based on the assumption that these facilities would use limestone-based wet scrubbers 

to meet the existing SO2 emissions limit. Table 5 presents the estimated incremental impacts of 

revising the EGU NSPS SO2 emissions limit for the model plant EGUs representing PC–fired boilers 

firing subbituminous coal (Model plants A, B) and FBC boiler firing lignite (Model plant F) based on 

the assumption that these facilities would use a lime-based SDA system to meet the existing SO2

emissions limit. 
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Table 4. Limestone-Based Wet FGD Annual Incremental Impacts 

Model 

Plant 

Annual 

Costs 

($1,000) 

SO2

Emissions 

Reduction 

(tons) 

Incremental 

Cost 

Effectiveness 

($/ton) 

Electricity 

Use 

(MWh) 

Water 

Use 

(1,000 gal)

Limestone 

Use 

(tons) 

Solid 

Waste 

Generated 

(tons) 

Chemically

Created 

CO2

(tons) 

C 875 1,006 870 7,050 6,374 344 1,799 691 

D 1,671 2,303 725 14,390 14,610 787 4,118 1,582 

E 341 744 456 990 4,597 272 1,330 511 

Table 5. 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) 

Water 

Use 

(1,000 gal) 

Lime 

Use 

(tons) 

Waste 

Generated 

(tons) 

A 105 149 703 2 21 473 1,077 

B 450 737 611 11 104 2,230 5,074 

F 229 595 385 9 83 1,073 2,464 

NOX Emissions Control Impacts 

For the incremental impact analysis it is assumed that in general the same type of post-combustion 

NOX emissions controls would be installed on a given model plant EGU to comply with either the 

existing NSPS NOX emissions limit or the revised limit under consideration. Therefore, there would 

be an incremental increase in the capital and annual costs for the applicable NOX reduction system to 

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

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

The NOX emissions regulatory baseline is 1.0 lb/MWh and is defined to be installation of SCR controls 

on the model plant EGUs using PC-fired boilers (Model plant EGUs A, B, D, E, F) and SNCR controls 

on the model plant with an inherently lower amount of NOX formed during combustions, specifically 

the EGUs using FBC boilers (Model plant EGUs F, G). Design modifications and operating changes 

to the SCR and SNCR systems would be required to achieve the higher performance level needed to 

comply with an emissions standard of 0.70 lb/MWh. 

The auxiliary electrical power requirement is the only variable in the IPM costing equations for SCR 

and SNCR that does not vary with either inlet NOX concentrations or percent removal. This value is 

generally not a significant factor in overall costs of either control technology. However, to account for 

the incremental impacts the auxiliary power requirements for SCR were adjusted by assuming a 5% 

change in auxiliary power from the baseline calculated using the IPM equation for doubling or halving 

either the percent reduction requirement or inlet concentration. The baseline used in IPM is 0.21 

lb/MMBtu and a 70% reduction. To account for improved design in a new EGU compared to a retrofit 

EGU the minimum urea utilization was increased from 25% to 30% for the SNCR used in a FBC 

boiler. The auxiliary power requirements were also scaled relative to the urea flow rates listed in the 

IPM’s example calculation. The example calculation auxiliary power requirement is 0.05% for a 300 

MW EGU with a urea flow rate of 245 lb/hr. 
9 

Table 6 presents the estimated incremental impacts of revising the EGU NSPS NOX emissions limit for 

the model plant EGUs using either FBC boilers and assumed to be using SNCR to meet the existing 

NOX emissions limit (Model plant EGUs F, G). Table 7 presents the estimated incremental impacts of 

revising the EGU NSPS NOX emissions limit for the model plant EGUs using PC-fired boilers and 

assumed to be using SCR to meet the existing NOX emissions limit (Model plant EGUs A, B, C, D, E). 

Table 6. Selective Non-Catalytic Reduction (SNCR) Annual Incremental Impacts 

Model 

Plant 

Annual 

Costs 

NOx 

Emissions 

Reduction 

(tons) 

Incremental 

Cost 

Effectiveness 

($/ton of NOx) 

Electricity 

Use 

(MWh) 

Urea 

Use 

(tons) 

Water 

Use 

(1,000 gal) 

F $644,900 443 1,460 1,200 2,100 960 

G $186,400 112 1,670 300 530 240 

Table 7. Selective Catalytic Reduction (SCR) Annual Incremental Impacts 

Model 

Plant 

Annual 

Costs 

NOx 

Emissions 

Reduction 

(tons) 

Incremental 

Cost 

Effectiveness 

($/ton of NOx) 

Electricity 

Use 

(MWh) 

Urea 

Use 

(tons) 

Steam 

Use 

(1,000 lb) 

A $141,600 110 1,290 37 77 170 

B $679,000 564 1,200 200 400 890 

C $489,800 544 900 130 380 860 

D $489,800 544 900 130 380 860 

E $693,200 564 1,230 200 400 890 

Secondary Air Pollutant Emissions Impacts

Secondary air pollutant emissions from the generation of the electricity required to operate that air 

pollution control equipment used to meet the revised emissions limits under consideration are 

estimated assuming that the electricity is generated at the facility site by a coal-fired EGU that is 

operated to achieve the following emission levels. 

PM = 0.055 lb/MWh 

SO2 = 1.0 lb/MWh 

NOX = 0.70 lb/MWh 

Carbon monoxide (CO) = 0.40 lb/MWh 

Mercury = 0.000010 lb/GWh (all coals except lignite); 0.040 lb/GWh (lignite) 

CO2 = 1,860 lb/MWh 

The estimated annual incremental secondary air pollutant emissions for each model plant are presented 

in Table 8. 
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Table 8. Secondary Air Emissions Annual Incremental Impacts 

Model 

Plant 

Total Control 

Equipment 

Electricity 

Use 

(MWh/yr) 

Annual Incremental Increase in Secondary Air Emissions from 

Control Equipment Operations 

PM 

(ton/yr) 

SO2 

(ton/yr) 

NOX 

(ton/yr) 

CO 

(ton/yr) 

Mercury 

(lb/yr) 

CO2 

(ton/yr) 

A 8,602 0.2 4.3 3.0 1.7 < 0.0001 8,000 

B 43,026 1.2 21.5 15.1 8.6 0.0004 40,000 

C 42,952 1.2 21.5 15.0 8.6 0.0004 40,000 

D 57,335 1.6 28.7 20.1 11.5 0.006 53,000 

E 44,005 1.2 22.0 15.4 8.8 1.8 41,000 

F 35,461 1.0 17.7 12.4 7.1 1.4 33,000 

G 8,863 0.2 4.4 3.1 1.8 < 0.0001 8,000