Technical Support Document 

for the 

Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone 

(Clean Air Interstate Rule): 

Reconsideration Notice of Proposed Rule 

 

Impact on CAIR Analyses of D.C. Circuit Decision in 

New York v. EPA

EPA Docket number: OAR-2003-0053 

December 2005 

U.S. Environmental Protection Agency 

Office of Air and Radiation 
Technical Support Document: Impact on CAIR Analyses of D.C. Circuit Decision in New York v. EPA

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Overview

This technical support document (TSD) supplements the discussion of the impact on Clean Air 

Interstate Rule (CAIR) analyses of the D.C. Circuit Decision in New York v. EPA in the Rule to 

Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule): 

Supplemental Notice of Reconsideration (“Supplemental Notice”). 

This TSD discusses the following analyses: 

• Potential for collateral increases in NSR-regulated air pollutants from use of nitrogen 

oxides (NOx) and sulfur dioxide (SO2) controls for CAIR 

• Costs of sulfur trioxide (SO3)/ sulfuric acid (H2SO4) mitigation 

• Boilermaker labor and installation timing analysis for SO3/H2SO4 controls 

The following additional materials have been placed in the docket: 

• Integrated Planning Model (IPM) runs for marginal cost analysis 

• Parsed files showing retrofits and coal choice information on a unit-specific basis 

• Parsed data for the CAIR-Clean Air Mercury Rule (CAMR)-Clean Air Visibility 

Rule (CAVR) regulatory scenario in 2007 

• Boilermaker calculations 

Analysis of Potential for Collateral Increases in Air Pollutants from Use of NOx and SO2 

Controls for CAIR

As discussed in the Supplemental Notice, the Agency examined the potential for collateral 

increases in New Source Review1 (NSR)-regulated air pollutants from the types of NOx and SO2 

controls on which EPA based its CAIR cost-effectiveness determination. The EPA considered 

each of the NOx and SO2 control measures that were included in the CAIR cost-effectiveness 

determination and found that the following technologies may have the potential to cause 

collateral increases in air pollutants regulated under NSR: combustion controls, selective 

catalytic reduction (SCR), flue gas desulfurization (FGD), and fuel switches to low sulfur coal. 

This TSD provides supplemental information to the discussion in the Supplemental Notice. 

Increases in Sulfuric Acid or Particulate Matter Emissions from Selective Catalytic Reduction 

(SCR) Retrofits

The Supplemental Notice discusses the potential for sulfuric acid emissions increases from SCR 

retrofits. This TSD provides additional information to support the Supplemental Notice. 

 

1

 Prevention of Significant Deterioration (PSD) is the part of the NSR program that applies to sources located in 

areas in attainment with the NAAQS. Unless otherwise noted, in this document, when we refer to the NSR program, 

NSR review, NSR permitting or other NSR requirements, we are referring to both the NSR and PSD programs and 

their respective requirements.
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The SCR technology involves injection of a reagent, ammonia, into boiler flue gas. A catalyst is 

used to promote reaction between ammonia and NOx present in flue gas, forming harmless 

nitrogen and water. There are two secondary effects associated with SCR that may result in the 

formation of additional sulfur trioxide (SO3) and particulate matter (PM). 

A small portion of ammonia in SCR remains unreacted and is present in flue gas at the catalyst 

reactor outlet as ammonia slip. In addition, the SCR catalyst oxidizes a portion of the SO2 

present in flue gas to SO3. The amount of SO3 increase depends on the coal sulfur content and 

the characteristics of the SCR catalyst. The total amount of SO3 present is generally greater than 

that of ammonia, since SO3 is also formed within the boiler via oxidation of fuel sulfur. This 

condition favors a reaction between SO3 and ammonia that produces ammonium bisulfate, 

which condenses to form solid PM.(1) 

Recent SCR technology developments have emphasized minimization of ammonia slip and SO2-

to-SO3 conversion levels. The new SCR installations are routinely being designed to maintain 

ammonia slip at two to three ppmv level.(1-7) Similarly, SO2-to-SO3 conversion rates for SCR 

have been kept at less than one percent (typically 0.5 percent or lower). In comparison, the SO2-

to-SO3 conversion rate that occurs in the boiler itself is about 1.0 percent. 

The EPA used the above ammonia slip and SO3 levels to determine the amount of PM that could 

potentially be formed as ammonium bisulfate. For a 500 MW unit, the 3 ppmv of ammonia slip 

and SO3 present in flue gas result in the formation of approximately 208 tons per year of PM as 

ammonium bisulfate. The majority of this PM will be captured in the particulate control device 

installed at this unit. For a unit equipped with a baghouse, minimal increase in the stack PM 

emission is expected, as virtually all of the increased PM should be captured in the baghouse. 

For a unit equipped with an electrostatic precipitator (ESP), it is estimated that the increase in the 

PM or PM10 emission will be approximately 3.1 tons per year, which is well below the level that 

would trigger a NSR review. This estimate uses a particulate collection efficiency of 98.5 

percent, which is the average efficiency of the ESP installed at the coal-fired units in the U.S.(8) 

The SCR operation results in an increase in the flue gas SO3 concentration. The majority of this 

SO3 is expected to react with the moisture in flue gas to form sulfuric acid (H2SO4). The 

amount of SO3/H2SO4 added to the flue gas stream by SCR will be directly proportional to the 

fuel sulfur content and will depend on the characteristics of the SCR catalyst. A unit that installs 

SCR-only (that is, does not also install a technology to mitigate SO3/H2SO4) could increase 

sulfuric acid emissions significantly enough to trigger the NSR threshold of 7 tons per year for 

sulfuric acid mist.2

 

However, if the unit switches to a low sulfur coal when installing SCR, the unit would not 

increase sulfuric acid emissions enough to trigger the threshold. Making the conservative 

assumption that a unit would choose a coal with only a 50 percent lower sulfur content when 

 

2 The Agency’s analysis for the Supplemental Notice of Reconsideration assumes that all sulfuric acid emitted will 

be counted as emission of sulfuric acid mist, which is an NSR-regulated pollutant. 
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installing SCR (in reality, sources might choose a reduction in coal sulfur content greater than 50 

percent), this reduction in coal sulfur content would be sufficient to reduce the amount of SO3 

generated in the boiler such that the net change in SO3 would be insufficient to trigger the 7 tons 

per year sulfuric acid mist NSR threshold. Assuming that 1.0 percent of SO2 is converted to 

SO3 in the boiler and an additional 0.5 percent is converted in the SCR, a total of about 1.5 

percent of SO2 present in the fuel is converted to SO3. If the fuel SO2 content is reduced by 50 

percent at the same time the SCR is installed, the net result would be that the SO2-to-SO3 

conversion rate (including conversion occurring in both the boiler and the SCR) would be 75 

percent of what the conversion was before the changes (i.e., before retrofitting the SCR and 

switching to the lower sulfur coal). 

Impact of Flue Gas Desulfurization (FGD) on Sulfuric Acid Emissions for Units that Retrofit 

SCR

The two most common FGD systems used for SO2 control include a lime-based spray dryer 

system (dry FGD) and a limestone-based wet FGD system (wet FGD). In each system, the 

reagent is injected into the flue gas stream in the form of slurry, causing a considerable drop in 

the flue gas temperature. Therefore, a strong potential exists for any SO3/H2SO4 present in flue 

gas to condense to acid mist. 

These FGD systems are effective at reducing SO3/H2SO4 emissions. More than 90 percent of 

SO3/H2SO4 is removed in a dry FGD, while up to about 50 percent removal occurs in a wet 

FGD system. Considering the effectiveness of FGD systems at mitigating SO3/H2SO4, the 

Agency expects that a unit installing SCR and FGD (wet or dry) at the same time would not 

increase sulfuric acid emissions significantly enough to trigger NSR. 

A unit that retrofits dry FGD at the same time as SCR would yield a substantial net decrease in 

sulfuric acid emissions because the dry FGD captures more than 90 percent of SO3/H2SO4. A 

unit that retrofits wet FGD at the same time as SCR might have a small increase in sulfuric acid 

emissions, but such an increase would not be sufficient to trigger the NSR threshold. EPA 

assumes that the SO2-to-SO3 conversion rate in the boiler and SCR are about 1.0 percent and 0.5 

percent, respectively. Taking a 90 percent reduction (in the case of dry FDG) brings the total 

SO3 down to well below the rate before installing SCR (i.e., a 90 percent reduction from 1.5 is 

less than 1.0). Assuming about a 50 percent reduction (in the case of wet FGD) also brings the 

total SO3 down to less than the rate before installing SCR (i.e., a 50 percent reduction from 1.5 

is less than 1.0). 

Sulfuric acid emissions could increase enough to trigger NSR if, after installing a wet FGD, a 

power company switched to burning a higher sulfur coal. Assuming that a company switched 

from 1 lb/MMBtu coal to 5 lb/MMBtu coal, SO3/H2SO4 emissions would increase by a factor 

of five (assuming that the coal switch did not impact the SO3 conversion rate in the boiler). 

Impact of Wet Electrostatic Precipitator (ESP) on Sulfuric Acid Emissions
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One potential control technology that could be used to mitigate SO3/H2SO4 emissions is a wet 

ESP. A wet ESP removes approximately 95% of the SO3/H2SO4 emissions. 

As explained above, installing a SCR is likely to less than double SO3/H2SO4 emissions from a 

coal-fired boiler (assuming an SO3 conversion rate of 1% in the boiler and an additional 0.5% 

from the SCR catalyst). Therefore, if there were no other changes (e.g. coal switching) 

installation of a wet ESP would reduce SO3/H2SO4 emissions substantially below the level 

emitted from a unit before the SCR was installed. 

As explained above, switching to a higher sulfur content coal at the same time as installing a wet 

FGD could lead to SO3/H2SO4 emissions increasing by a factor of five. Even without 

considering the SO3/H2SO4 emission reductions from the FGD itself, the wet ESP would reduce 

SO3/H2SO4 emissions substantially below the level emitted from a unit before the FGD was 

installed and the coal switch took place. 

If a company installed both an SCR and a wet FGD and switched from 1 lb/MMBtu coal to 5 

lb/MMBtu coal, SO3/H2SO4 emissions would increase by a factor of ten, assuming that the coal 

switch did not impact the SO3 conversion rate in the boiler (the factor of ten increase is based on 

a very conservative assumption of a 1% SO2-to-SO3 conversion rate in the SCR), and without 

considering SO3/H2SO4 emission reductions from the FGD. Considering the removal 

efficiency of the wet ESP, the wet ESP would reduce SO3/H2SO4 emissions substantially below 

the level emitted from a unit before the FGD was installed and the coal switch took place 

(without even considering the SO3/H2SO4 reductions from the FGD itself). 

Increases in Carbon Monoxide (CO) and Unburned Carbon (Solid Particulate) Emissions from 

Combustion Controls

The Supplemental Notice discusses increases in CO and unburned carbon from combustion 

controls. This TSD provides additional information to support the information in the 

Supplemental Notice. 

The NOx removal efficiency for each type of combustion control used in EPA’s analysis for 

CAIR was estimated as an average of the reported efficiencies for a large number of units 

equipped with these controls. In a unit equipped with both low-NOx burner (LNB) and overfire 

air (OFA) technologies, LNB provides a greater part of the overall NOx removal reduction. 

Since the NOx removal efficiencies used in EPA’s analysis are not aggressive, it is believed that 

the units installing combustion controls can opt for moderate levels of OFA flow rates and still 

achieve the NOx reduction levels projected in EPA’s analysis, without causing significant 

increases in the CO and unburned carbon emissions. 

Analysis of SO3/H2SO4 Mitigation Costs for CAIR SCR and/or Wet FGD Projects
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The following information supplements information on SO3/H2SO4 mitigation costs presented 

in the Supplemental Notice. 

The EPA used the Integrated Planning Model (IPM)3

 to provide an estimate of the possible cost 

impacts for CAIR units that may install SO3/H2SO4 controls. For the reasons stated in the 

Supplemental Notice, EPA believes that its analysis overstates the likely true cost impact. As 

discussed in the Supplemental Notice, EPA analyzed the cost impacts of SO3/H2SO4 mitigation 

by conducting an IPM sensitivity analysis in which we added costs for wet ESP to every unit that 

installs SCR and/or wet FGD.4 Table 3 presents the results of the SO3/H2SO4 mitigation 

sensitivity analysis. The Supplemental Notice discusses these results in detail. 

The EPA estimated the costs of wet ESP for use in the SO3/H2SO4 sensitivity analysis. The 

costs used in the analysis are as follows (9-11):

For a 500 MW unit: 

Capital cost: $40/kW 

Fixed O&M: $0.71/kW-yr 

Variable O&M: 0.054 mills/kWh 

Scaling factor for capital and fixed O&M cost: (500/MW)^0.3 

Variable O&M applies to all unit sizes - no scaling factor 

Table 1: SO2 and NOx Estimated Marginal Cost (1999$ per ton)1

SO2 Annual NOx Annual 

2010 2015 2009 2015 

Sensitivity analysis with SO3/H2SO4 mitigation 

(based on CAIR/CAMR/CAVR modeling) $700 $900 $1,600 $2,000 

1 EPA IPM modeling is available in the docket. Projected costs are rounded to the nearest hundred dollars. 

Marginal Cost Curves

In our analysis for the final CAIR, the Agency developed marginal cost curves to examine the 

changes in marginal costs for EGUs at varying levels of SO2 and NOx emission reductions. 

 

3

 The IPM is a multiregional, dynamic, deterministic linear programming model of the U.S. electric power sector. 

The Agency uses IPM to examine costs and, more broadly, to analyze the projected impact of environmental polices 

on the electric power sector in the 48 contiguous States and the District of Columbia. 4 Although EPA based this analysis on installation of wet ESP, the Agency is not making any determination or 

prediction regarding what the specific NSR requirements might be for these projects. While the Agency believes 

that only a subset of units installing SCR and/or wet FGD will, in fact, have increases in SO3/H2SO4 that warrant 

the installation of wet ESP, due to the limitations of the IPM model, EPA made the conservative assumptions that all 

such units will install wet ESP. 
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These curves were presented in the final CAIR (70 FR 25204-25213)5. The EPA used the 

marginal cost curve analysis to corroborate its finding concerning the cost effectiveness of CAIR 

emission reductions. All dollar values are reported in 1999$. 

The Agency developed the marginal cost curves using the Technology Retrofit and Updating 

Model (TRUM), a model that selects investment options and dispatches generation to meet 

electricity demand. For simplicity, TRUM was developed as a steady-state, single-region 

spreadsheet model supported by Visual Basic for Applications (VBA) code. The TRUM consists 

of a set of sample generating units with varying characteristics. The mix of generation types and 

sizes was chosen to mirror, in general terms, the nationwide mix of capacities. The TRUM relies 

on the same underlying data as IPM. The Agency described it’s use of TRUM in a TSD for the 

final CAIR entitled “Modeling of Control Costs, Emissions, and Control Retrofits for Cost 

Effectiveness and Feasibility Analyses,” March 2005, as well as in a memo entitled “Analysis of 

the Marginal Cost of SO2 and NOx Reductions,” January 28, 2004 (the TSD and memo are both 

available in the CAIR docket (EPA-HQ-OAR-2003-0053). 

As part of our analysis for the Supplemental Notice, EPA developed marginal cost curves based 

on the IPM sensitivity analysis with SO3/H2SO4 mitigation, to examine the changes in marginal 

costs for EGUs at varying levels of SO2 and NOx emission reductions with the added costs of 

SO3/H2SO4 mitigation. Marginal cost curves based on the SO3/H2SO4 sensitivity for SO2 

reductions in 2010 and 2015 and NOx reductions in 2010 and 2015 are shown in Figures 1, 2, 3 

and 4, respectively. 

Figure 1 shows that the “knee” in the 2010 marginal SO2 cost curve – the point where the cost of 

controlling a ton of SO2 from EGUs is increasing at a noticeably higher rate – appears to occur 

at higher than $2,500 per ton of SO2 reduced. Figure 2 shows that the “knee” in the 2015 

marginal SO2 cost curve appears to occur at about $2,000 per ton of SO2 reduced. The 

projected marginal costs for this sensitivity analysis are $700 per ton in 2010 and $900 per ton in 

2015, as shown in Table 3. For both 2010 and 2015, the marginal costs in the SO3/H2SO4 

sensitivity analysis are below the points at which the costs begin to increase at a significantly 

higher rate in the respective marginal cost curves. 

Figure 3 shows that the “knee” in the 2010 marginal NOx cost curve appears to occur at about 

$2,500 per ton of NOx reduced. Figure 4 shows that the “knee” in the 2015 marginal NOx cost 

curve appears to occur at about $2,000 per ton of NOx reduced. The projected marginal costs for 

this sensitivity analysis are $1,600 per ton in 2010 and $2,000 per ton in 2015, as shown in Table 

3. For both 2010 and 2015, the marginal costs in the SO3/H2SO4 sensitivity analysis are not 

 

5 As explained in the final CAIR, EPA used the marginal cost curve analysis solely to corroborate its findings 

concerning cost effectiveness of CAIR emission reductions. The marginal cost curve reflects only emissions 

reduction and cost information, and not other considerations. We note that it might be reasonable in a particular 

regulatory action to require emissions reductions past the knee of the curve to reduce overall costs of meeting the 

NAAQS or to achieve benefits that exceed costs. It should be noted that similar analysis for other source categories 

may yield different curves.
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above the points at which the costs begin to increase at a significantly higher rate in the 

respective marginal cost curves. 

As was the case in the final CAIR, the Agency is using marginal cost curve analyses solely to 

corroborate its findings concerning cost effectiveness of CAIR emission reductions in the 

SO3/H2SO4 mitigation sensitivity. 

Marginal Cost Curve of SO2 Abatement in 2010 Sensitivity Analysis with SO3/H2SO4 

Mitigation

$ 0

$500

$1,00 0

$1,50 0

$2,000

$2,500

$3,000

6.00 5.50 5.00 4.50 4.00 3.50 3.00 2.50 2.00 1.50 1.00

SO2 Emissions in CAIR States (millions of tons) Marginal Cost (1999$/ton)

Result s using TRUM; IPM result s would dif f er.

TRUM emissions and marginal cost s have been adjust ed by 2% t o more closely

(Source: EPA, TRUM Model Analysis, 2005)

Figure 1: Marginal Cost Curve of SO2 Abatement in 2010 Sensitivity Analysis with 

SO3/H2SO4 Mitigation
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Marginal Cost Curve of SO2 Abatement in 2015 Sensitivity Analysis with SO3/H2SO4 

Mitigation

$0

$500

$1,000

$1,500

$2,000

$2,500

6.00 5.50 5.00 4.50 4.00 3.50 3.00 2.50 2.00 1.50 1.00

SO2 Emissions in CAIR States (millions of tons) Marginal Cost (1999$/ton)

Results using TRUM; IPM r esults would dif f er .

TRUM emissions and mar ginal costs have been adjusted by 1% to mor e closely match the IPM r esults.

(Source: EPA, TRUM Model Analysis, 2005)

Figure 2: Marginal Cost Curve of SO2 Abatement in 2015 Sensitivity Analysis with 

SO3/H2SO4 Mitigation 

Marginal Cost Curve of NOx Abatement in 2010 Sensitivity Analysis 

with SO3/H2SO4 Mitigation

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

2.25 2.00 1.75 1.50 1.25 1.00 0.75

 NOx Emissions in CAIR States (millions of tons)

Marginal Cost (1999$/ton)

Results using TRUM; IPM results would differ.

TRUM emissions and marginal costs have 

(Source: EPA, TRUM Model Analysis, 2005)

Figure 3: Marginal Cost Curve of NOx Abatement in 2010 Sensitivity Analysis with 

SO3/H2SO4 Mitigation 
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Marginal Cost Curve of NOx Abatement in 2015 Sensitivity Analysis 

with SO3/H2SO4 Mitigation

$0

$500

$1,000

$1,500

$2,000

$2,500

2.25 2.00 1.75 1.50 1.25 1.00 0.75

NOx Emissions in CAIR States (millions of tons)

Marginal Cost (1999$/ton)

Results using TRUM; IPM results would differ. 

TRUM emissions and marginal costs have been 

(Source: EPA, TRUM Model Analysis, 2005)

Figure 4: Marginal Cost Curve of NOx Abatement in 2015 Sensitivity Analysis with 

SO3/H2SO4 Mitigation 

Boilermaker Labor and Installation Timing Analysis for SO3/H2SO4 Controls 

For the CAIR final rule, the Agency analyzed boilermaker labor availability for installing NOx 

and SO2 retrofits for CAIR, as discussed in the CAIR preamble (70 FR 25215-25225) and in a 

TSD entitled “Boilermaker Labor and Installation Timing Analysis,” OAR-2003-0053-2092 

(“final CAIR boilermaker TSD”). For the Supplemental Notice, EPA completed an analysis to 

determine the impact of installing SO3/H2SO4 controls on boilermaker labor availability during 

the two CAIR phases. This TSD provides additional information regarding EPA’s boilermaker 

labor analysis for SO3/H2SO4 controls. 

EPA examined the impact of installing wet ESP on the availability of boilermaker labor during 

the time when control retrofits will be installed for the two CAIR phases. EPA’s analysis 

assumed that units that might experience sulfuric acid emission increases greater than the 

sulfuric acid mist NSR threshold while incorporating NOx and/or SO2 controls for CAIR would 

choose to install wet ESP (a very conservative assumption because SO3/H2SO4 mitigation 

measures are available that would require less boilermaker labor than wet ESP). For this 

boilermaker labor analysis, the Agency used the same assumptions regarding boilermaker 

availability factors (i.e., boilermaker sources, population, average annual work hours, activity 

periods, and duty rates) that the Agency used in the boilermaker analysis for the final CAIR. 
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These factors are defined in the final CAIR boilermaker TSD. 

EPA conducted boilermaker analysis based on the following three scenarios. The CAIR 

examined boilermaker labor requirements for NOx and SO2 control retrofits based on these same 

three scenarios: 

1. CAIR Phase I Policy Case. This scenario examines boilermaker labor requirements for 

the initial CAIR phase (2009 for NOx and 2010 for SO2). 

2. Modified CAIR Phase I Policy Case. This scenario also examines boilermaker labor 

requirements for the initial CAIR phase (2009 for NOx and 2010 for SO2). However, 

this scenario is based on EIA assumptions for electricity demand and natural gas prices 

and UARG assumptions for boilermaker duty rates (UARG submitted assumptions for 

boilermaker duty rates during the CAIR comment process). See the final CAIR 

boilermaker TSD for further discussion of the assumptions for this scenario. 

3. CAIR Phase II Policy Case. This scenario examines boilermaker labor requirements for 

the second CAIR phase (2015 for both NOx and SO2), and is based on EIA assumptions 

for electricity demand and natural gas prices and UARG assumptions for boilermaker 

duty rates (see scenario 2, above). 

The Agency analyzed the scenarios of CAIR SCR and/or FGD retrofits and coal switches that 

may increase sulfuric acid emissions sufficiently to trigger the NSR threshold, as discussed in 

the Supplemental Notice. For it’s analysis of boilermaker labor requirements for SO3/H2SO4 

controls, the Agency examined units in the CAIR_CAMR_CAVR IPM parsed files6 to 

determine which units are projected to install SCR and/or wet FGD during the two CAIR 

phases. In doing so, it was important to only include incremental retrofits, to prevent doublecounting of retrofits that occur in 2010 but show up as retrofits in 2015 as well, and to prevent 

the inclusion of units that install retrofits before CAIR takes effect. From these units, EPA 

eliminated units 1) installing SCR but switching from high to low sulfur coal, 2) installing wet 

FGD but not switching from low to high sulfur coal, and 3) installing both SCR and wet FGD 

but not switching from low to high sulfur coal. As discussed in the Supplemental Notice, the 

Agency believes that the three aforementioned categories of retrofits would not increase 

SO3/H2SO4 emissions sufficiently to trigger NSR. The remaining units were included in 

EPA’s boilermaker labor analysis, assuming that such units would retrofit wet ESP to avoid 

exceeding the NSR threshold. From this analysis, the following amounts of wet ESP 

installations were estimated for the three CAIR scenarios described above:7

 

6

 Parsed files refer to files that show unit-specific projections based on how model plants are projected to change in 

IPM. All relevant parsed files are in the CAIR docket (EPA-HQ-OAR-2003-0053). 7

 The Agency estimated capacity of wet ESP retrofits based on the CAIR/CAMR/CAVR IPM modeling. For the 

Modified CAIR Phase I Policy Case, the Agency estimated an increased wet ESP retrofit capacity to take into 

account EIA assumptions for electricity demand and natural gas prices. Capacity of NOx and SCR retrofits used in 

this analysis are consistent with the retrofit capacities in the boilermaker labor analysis for the final CAIR (i.e., they 

are based on CAIR modeling that does not include the CAMR and CAVR requirements). 
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1. 41.66 GW of wet ESP retrofits required for CAIR Phase I Policy Case 

2. 48.75 GW of wet ESP retrofits required for Modified CAIR Phase I Policy Case 

3. 27.76 GW of wet ESP retrofits required for CAIR Phase II Policy Case 

The boilermaker duty rate for installing wet ESP was determined to be 0.05 boilermaker year per 

MW of wet ESP retrofit. This was based on a comparison of the boilermaker labor-related 

scopes included in installing wet ESP, FGD, and SCR. The boilermaker labor requirements were 

estimated using the above amounts of wet ESP retrofits, boilermaker duty rate, and the 

boilermaker requirements associated with installing NOx and SO2 controls (as included in the 

original boilermaker analysis). 

In EPA’s original boilermaker analysis, the Agency included all states it anticipates will be 

regulated under CAIR, including those states regulated for ozone-season NOx only and New 

Jersey and Delaware. The current boilermaker analysis includes the same group of states; 

however, this analysis is not perfectly comparable with the previous boilermaker analysis since 

the current analysis includes units that retrofit SO3/H2SO4 mitigation controls as a result of the 

Clean Air Visibility Rule, and thus overstates the cost and boilermaker labor required for wet 

ESP. For the sake of consistency though, the same number of FGD and SCR retrofits was 

assumed in this boilermaker analysis as in the original boilermaker analysis. These values are 

shown in the “Boilermaker Calculations” spreadsheet. 

Based on the current boilermaker labor analysis, EPA determined that adequate boilermaker 

labor would be available for all three CAIR scenarios evaluated, even considering additional 

boilermakers that may be needed to install SO3/H2SO4 controls. The results of this analysis are 

summarized below: 

1. For CAIR Phase I Policy Case, the required labor for installing all NOx, SO2, and 

SO3/H2SO4 controls is 12,300 boilermaker years, compared with the available labor of 

24,000 boilermaker years. This represents a high contingency factor in the available 

labor of 95 percent. 

2. For the Modified CAIR Phase I Policy case, the required labor for installing all NOx, 

SO2, and SO3/H2SO4 controls is 24,300 boilermaker years, compared with the 

available labor of 25,100 boilermaker years. This represents a contingency factor in the 

available labor of 4 percent. This contingency factor falls short of the 15 percent factor 

in the boilermaker labor analysis conducted for the final CAIR. However, it should be 

noted that this case is based on using conservative boilermaker duty rates for SCR and 

FGD retrofits that were proposed by UARG, a commenter on the original CAIR 

proposal. The EPA performed boilermaker analysis on this scenario to verify adequacy 

of the available boilermaker labor force for CAIR, using the UARG-proposed 

boilermaker duty rates, which were substantially higher than those recommended by 
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EPA and which were judged to be the outer bounds of the boilermaker requirements for 

installing SCR and FGD retrofits. Additionally, this scenario is based on EIA 

assumptions for electricity demand and natural gas prices, which are higher than the 

assumptions that the Agency believes are most appropriate for these parameters. For 

these reasons, the boilermaker availability contingency factor of 4 percent for this 

highly conservative case is considered adequate. 

3. For CAIR Phase II Policy Case, the required labor for installing all NOx, SO2, and 

SO3/H2SO4 controls is 18,000 boilermaker years, compared with the available labor of 

24,400 boilermaker years. This represents a contingency factor in the available labor of 

36 percent, which is considered adequate. 

References

1. M. Gregory, et. al., “The Impact of SCR and SNCR Systems on Plant Equipment and 

Operations,” EPRI/EPA Joint Symposium on Stationary Combustion NOx Control, May 

16-19, 1995, Kansas City, Missouri 

2. D. Capozella, et. al., Unique Design Solutions and Implementation Approach for Dayton 

Power and Light Killen Station SCR Project,” Mega Symposium, August 30– September 

2, 2004, Washington, DC 

3. S. Weis, et. al., “O&M Cost Optimized SCR Operation and Management at AES’s 

Somerset Station,” Mega Symposium, August 30– September 2, 2004, Washington, DC 

4. J. Garner, et. al., “Performance Results of SCR Installation for Henderson Municipal 

Power & Light’s Station Two,” Mega Symposium, August 30– September 2, 2004, 

Washington, DC 

5. T. Smith, “Saving Catalyst Cost and Optimizing Unit Performance by Means of EON’s 

SCR Management System,” Mega Symposium, August 30– September 2, 2004, 

Washington, DC 

6. FGD and DeNOx Newsletter, No. 317, September 2004, McIlvaine website, 

http://www.mcilvainecompany.com/

7. Control of Nitrogen Oxide Emission: Selective Catalytic Reduction (SCR), Department 

of Energy, Topical Report No. 9, July 1997 

8. Form 767, EIA database, http://www.eia.doe.gov/cneaf/electricity/page/eia767.html

9. R. Staehle, et. al., "The Past, Present, and Future of Wet Electrostatic Precipitators in 

Power Plant Applications," Mega Symposium,May 19-22, 2003, Washington, DC. 

10. K. Kumar, et.al., "Wet ESP for Controlling Sulfuric Acid Plume following an SCR 

System," ICAC Forum 2002, February 12-13, 2002, Houston, Texas. 

11. FGD and DeNOx Newsletter, June 2002, 

http://www.mcilvainecompany.com/utility/subscriber/newsletter/fgdnl290/wesp%20contr

ols%20blue%20plume.htm