1

MEMORANDUM

TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS/SPPD

FROM: Graham Gibson, Susan McClutchey, and Amanda Singleton, ERG

DATE: January 2011

SUBJECT: Revised Methodology for Estimating Impacts from Industrial, Commercial, 

Institutional Boilers at Area Sources of Hazardous Air Pollutant Emissions

1.0 INTRODUCTION

The purpose of this memorandum is to discuss the methodology used to estimate the 

costs, emission reductions, and secondary impacts from industrial, commercial, and institutional 

boilers at area sources of hazardous air pollutants (HAP). These impacts were calculated for 

existing units and new units projected to be operational three years after the rule is expected to 

be promulgated. The results of the impacts analysis are presented for both the most stringent 

regulatory option evaluated and the regulatory option contained in the final rule. The 

development of the maximum achievable control technology (MACT) floor and Generally 

Achievable Control Technology (GACT) level of control, projection of new units, and a detailed 

description of the cost equations used to estimate costs for various control technologies is 

presented in other memoranda.1,2,3 This memorandum is organized as follows:

1.0 Introduction

2.0 Overview of Regulatory Options

3.0 Estimating Cost Impacts

4.0 Methodology for Estimating Emission Reductions

5.0 Methodology for Estimating Secondary Impacts

6.0 References
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2.0 OVERVIEW OF REGULATORY OPTIONS

Four control options were considered for existing boilers at area sources of HAP. A 

description of the four options is described below. 

2.1 Existing Units

• Option 1E represents the option where all boilers, regardless of fuel type or size, must 

meet mercury and CO numerical emission limits based on MACT and PM numerical 

emission limits based on GACT. PM GACT was identified to be a multiclone for existing 

units.

• Option 2E represents the same emission limits as discussed in 1E above for large units 

(equal to or greater than 10 mmBtu/hr). Small units are exempt from numerical limits and 

instead are required to meet a work practice standard of a biennial tune-up. All facilities 

are required to conduct an energy assessment.

• Option 3E represents the option in which all coal boilers equal to or greater than 10 

mmBtu/hr must meet mercury and CO numeric emission limits based on MACT. All 

biomass and liquid boilers equal to or greater than 10 mmBtu/hr must meet a CO 

numerical emission limit, based on MACT. All facilities with a large boiler are required 

to conduct an energy assessment. Small boilers are exempt from numeric emission limits 

for all pollutants, but are required to meet a work practice standard of a biennial tune-up.

There are no numerical emission limits for PM under this option for any size or type of 

unit.

• Option 4E represents the option which is discussed most prominently in the preamble. In 

this option, all coal boilers equal to or greater than 10 mmBtu/hr must meet mercury and 

CO numeric emission limits based on MACT. All biomass and liquid boilers must 

comply with GACT for urban HAP, which is a boiler tune-up. All facilities with a large 

boiler are required to conduct an energy assessment. Small coal-fired boilers are exempt 

from numeric emission limits for all pollutants, but are required to meet a work practice 

standard of a biennial tune-up. There are no numerical emission limits for PM under this 

option for any size or type of unit.

2.2 New Units

Four control options were considered for new boilers at area sources of HAP. A detailed 

description of the four options is described below.

• Option 1N represents the option where all boilers, regardless of fuel type or size, must 
3

meet mercury and CO limits based on MACT and PM numerical emission limits based 

on GACT. GACT for new units is based on PM limits in the New Source Performance 

Standards (NSPS) for Industrial, Commercial, and Institutional Boilers (40 CFR part 60 

subparts Db, Dc).

• Option 2N represents the same emission limits as discussed in 1N above for large units 

(equal to or greater than 10 mmBtu/hr). Small units are exempt from numerical emission 

limits and instead are required to meet a work practice standard of a biennial tune-up. 

• Option 3N requires all coal boilers, regardless of size, must meet mercury and CO limits 

based on MACT and PM numerical emission limits based on GACT. All biomass and 

liquid boilers, regardless of size, must meet CO limits based on MACT and PM 

numerical emission limits based on GACT.

• Option 4N - represents the option in which all coal boilers equal to or greater than 10 

mmBtu/hr must meet mercury and CO numeric emission limits based on MACT. All 

biomass and liquid boilers must comply with GACT , which is a tune-up. Small boilers 

coal-fired are exempt from numeric emission limits for all pollutants, but are required to 

meet a work practice standard of a biennial tune-up. All units greater than 10 mmBtu/hr 

have PM emission limits based on GACT. The emission limit changes for units greater 

than 30 mmBtu/hr.

3.0 ESTIMATING COST IMPACTS

For each option, a percentage of units in each model unit were assumed to require control 

devices in order to meet the limit when the baseline emissions for the model unit exceeded the 

MACT floor emission limit applicable to each model. A detailed description of the options is 

described below. A summary table comparing the overall capital and annualized costs of option 

4E for existing units and option 4N for new units is presented in Table 1. The cost, emission 

reduction, and secondary impacts summarized here and in Sections 4, and 5, respectively, reflect 

the impacts for new units when using the NSPS limit of 0.03 lb/mmBtu for PM. The equations 

used to estimate the control, testing, monitoring, and work practice costs are discussed in another 

memorandum.3 The following logic was used to apply control, testing, and monitoring costs to 

each boiler:
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3.1 Option 1E

Control Cost Impacts

Mercury Control

A new fabric filter installation was expected to achieve the mercury emission limits in the 

final rule. Where baseline mercury emissions were found to be greater than the MACT floor, the 

cost of a fabric filter was estimated for a portion of the boilers represented by the model unit. 

Based on the data used in the MACT floor analysis, a fraction of units in each subcategory 

meeting the MACT floor for Hg was estimated.

For boilers designed to burn biomass one of the boilers was meeting the floor and the 

other unit was not meeting the floor. In the cost impacts analysis, 50 percent of the biomass units 

were estimated to install a fabric filter to meet the floor. For boilers designed to burn coal, 86

percent of units were achieving the MACT floor emission limit for coal, so a new fabric filter 

was estimated to be installed at 14 percent of the existing coal-fired boilers. For liquid fuel units, 

there were no area source boilers with emission test data available for mercury. In the absence of 

other information about the distribution of units that would require a fabric filter to be installed, 

this cost impacts analysis assumes that 50 percent of the liquid fuel units would install a fabric 

filter to meet the mercury limit. 

CO/Organic HAP Control

Organic HAP and carbon monoxide can be controlled by either improving the 

combustion efficiency of the unit, or installing an oxidation catalyst on the exhaust of a 

combustion unit. The control strategy necessary to meet the MACT floor emission limit will vary 

depending on the magnitude between the baseline emissions and the CO MACT floor. 

Most boilers are designed to operate with CO emissions at or near 400 parts per million 

(ppm). A boiler tune-up was estimated in the cost impacts analysis if the unit’s baseline 

emissions exceeded the floor for carbon monoxide (CO), but were less than or equal to 400 ppm 

@ 3% O2. The combustor design of the boilers in the area source inventory is not known and this 

impacts analysis assumes that all areas source boilers firing solid fuels have a stoker combustor 

design since this is the predominant combustor design in the major source boiler inventory. The 
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baseline emissions for area source boilers in all fuel categories are less than 400 ppm, and so it is 

assumed that combustion controls, either a basic tune-up or a more advanced burner replacement 

or installation of a linkageless boiler management system, can achieve the MACT floor emission 

limits. No oxidation catalysts are estimated to be required to meet the MACT floor emission 

limits.

Based on the emission test data used to calculate the MACT floor for CO, 29 percent of 

units burning coal are exceeding the MACT floor and these units would be expected to install a 

linkageless boiler management system to comply with the CO limits. For units burning biomass, 

69 percent of the units are exceeding the MACT floor emission limits, and so 69 percent of the 

units are estimated to install a linkageless boiler management system. For units burning liquids, 

10 percent of the units are exceeding the floor and this cost impacts analysis assumes these units 

will install a new low NOx replacement burner in order to meet the CO limits. The units not 

expected to install these advanced controls are expected to conduct an annual tune-up to maintain 

in compliance with the proposed CO limit overtime.

Particulate Matter Control

For all units that were not expected to install a fabric filter for mercury control, the cost 

impacts analysis for this option assumes that the unit would install a multiclone to achieve the 

GACT emission limits for PM. Based on the current MACT floor analysis, 44 percent of coal 

units and 50 percent of liquid units would install a multiclone. Existing biomass units not 

expected to install a fabric filter would also install a multiclone. Base on the current MACT 

floor analysis, 50 percent of existing biomass units would install a multiclone. 

Testing and Monitoring Cost Impacts

Testing and monitoring requirements varied depending on the equipment installed on the 

unit to control emissions, the design capacity of the model unit, and the fuel category of the 

model unit.

Testing Costs

All boilers designed to burn solid fuels were expected to conduct an annual compliance 
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test for PM, Hg, and CO. The cost to conduct stack tests for these three pollutants was estimated 

to be $15,000 per year. 

Boilers designed to burn liquid fuels were expected to conduct an annual compliance test 

for PM and CO. In lieu of a stack test boilers designed to burn liquid fuels were expected to 

conduct fuel analysis, or report fuel analyses received from a fuel supplier for chlorine and Hg.

Conducting stack tests for PM and CO was estimated to be $13,000 per year and the cost to 

conduct fuel analysis for Hg was estimated to be $600 per year. Although solid fuels are eligible 

to comply with the rule through fuel analysis in lieu of stack testing, when the mercury content 

of the fuel is below the MACT floor emission limit, this cost estimate conservatively assumed 

that only units designed to fire liquid fuels would use this compliance alternative. The methods 

and data sources used to estimate testing and monitoring costs are discussed in other 

memoranda.3

Monitoring Costs

Various monitor configurations were installed based on the size of the unit and the 

pollution control devices expected to be installed to achieve the MACT floor emission limits. For 

units expected to install a fabric filter, an annualized cost of $9,700 for a bag leak detection 

monitor was included in the cost analysis. For units that did not install a bag leak detector, an 

annualized cost of $14,660 for an opacity monitor was included in the cost analysis. 

Fuel Savings Impacts

This cost analysis includes an estimate of energy savings for every unit that is expected to 

install controls to improve combustion, or conduct an annual tune-up or energy assessment. The 

Department of Energy has conducted energy assessments at selected manufacturing facilities and 

reports that facilities can reduce fuel/energy use by 10 to 15 percent by using best practices to 

increase their energy efficiency. Many best practices are considered pollution prevention 

because they reduce the amount of fuel combusted which results in a corresponding reduction in 

emissions from the fuel combustion. Further boiler tune-ups have been shown to improve the 

efficiency of a boiler between 1 and 5 percent, depending on the age of the unit and the time 

lapse since the previous tune-up. Other combustion controls such as upgrading burners and 

installation of an LBMS are also expected to improve the efficiency of the unit, thus reducing 
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fuel consumption. This cost analysis assumes an annual fuel savings of 1 percent. The energy 

savings is estimated using Equation 1:

Annual Fuel Savings (mmBtu/yr) = DC * CF * Ophours * EG (Equation 1)

Where:

DC = unit design capacity (mmBtu/hr)

Ophours = annual operating hours, assumed 8400 (hours/year)

EG = Efficiency gain, estimated to be 1%

CF = annual average capacity factor, 0.5 for liquid and 0.65 for coal and biomass

After the fuel savings for each boiler was calculated, the both industrial and commercial 

prices for coal, #2 distillate fuel oil, and #6 residual fuel oil were obtained from the EIA.3 The 

EIA data reported fuel prices as $/ton for coal, and cents per gallon for fuel oil. The higher 

heating values were obtained from Table C-1 of the EPA Mandatory Reporting Rule (40 CFR 

part 98 subpart C) and the higher heating values were used to convert the fuel prices to a 

standard unit of measure, $ per mmBtu. Using the distribution of SIC codes reported in the 13-

state boiler inspector inventory, the model units were distributed to an industrial or commercial 

sector, and then the appropriate fuel price was multiplied by the calculated fuel savings. This 

cost analysis only estimates the fuel savings from units in the coal and liquid fuel categories. A 

fuel savings was not estimated for units in the biomass fuel category since the price of biomass 

fuels is variable, and often biomass is an on-site industrial byproduct instead of a purchased fuel.

3.2 Option 2E

Option 2E follows the same logic for estimating control costs as option 1E outlined 

above, with the exception of small units (less than 10 mmBtu/hr). In option 2E, the only cost 

estimated for small units is the cost of an annual tune-up for each boiler. No testing and 

monitoring costs were included in option 2E for small units. Option 2E also includes the cost of 

an energy assessment at every area source facility, approximately 91,339 facilities. As discussed 

in the memorandum for Estimating Control Costs from Major Source Boilers and Process 

heaters, the cost of an energy assessment ranges from $75,000 for industrial-scale energy 

assessments to between $2,000 and $5,000 per energy assessment for institutional and 

commercial-scale assessments.

4

 The facility’s classification of either an industrial or commercial 

facility was assigned using the distribution of SIC codes in the 13-state boiler inspector 
8

inventory. The cost of each type of assessment was annualized over 5 years at 7 percent to obtain 

an annualized cost estimate. 

3.3 Option 3E

Option 3E includes control device and testing/monitoring cost estimation for mercury and 

CO from large coal units. As mentioned in option 1E, 56 percent of large coal units, or 321 

boilers are expected to install a fabric filter in order to meet the mercury limit. In addition, 29 

percent of large coal units are expected to install advanced combustion controls in order to meet 

the CO limit. This analysis uses the cost of a linkageless boiler management system to estimate 

the costs of advanced combustion control. The remaining 71 percent of large coal units are 

expected to meet the CO limit with a tune-up. The testing and monitoring costs for large coal 

units include a test for CO and mercury, as well as a bag leak detection system for the 321 

boilers that are expected to install a fabric filter. There are no numerical PM emission limits 

under this option, and so no additional testing costs for PM or opacity monitoring costs were 

assessed in the cost impacts analysis for this option.

Under option 3E liquid and biomass boilers are not subject to numerical emission limits 

for mercury and there are no costs included in the impacts analysis to install fabric filters or 

conduct mercury fuel analysis or stack testing. Large liquid and biomass boilers are subject to 

numerical emission limits for CO. This cost impacts analysis estimates that all the biomass and 

liquid fuel units can meet the CO emission limits by conducting an annual tune-up. These large 

units must also conduct testing and monitoring activities for CO to demonstrate compliance with 

the numerical emission limits.

Option 3E exempts small boilers from numerical emission limits. Instead these units must 

conduct a work practice standard of a biennial tune-up. The cost impacts analysis does not 

include any additional testing and monitoring requirements for these small boilers.

Finally, option 3E proposes that all facilities with large boilers conduct an energy 

assessment. For this cost impacts analysis one large boiler per facility was assumed, or 13,268 

facilities estimated to conduct an assessment. Similar to the discussion under option 2E, the cost 

of the assessment ranged from $75,000 for industrial-scale energy assessments to between 

$2,000 and $5,000 per energy audit for institutional and commercial-scale assessments.

2

 
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3.4 Option 4E

Option 4E includes control device and testing/monitoring cost estimation for mercury and 

CO from large coal units. As mentioned in option 1E, 14 percent of large coal units, or 80 boilers 

are expected to install a fabric filter in order to meet the mercury limit. In addition, 19 percent of 

large coal units are expected to install advanced combustion controls in order to meet the CO 

limit. This analysis uses the cost of a linkageless boiler management system to estimate the costs 

of advanced combustion control. The remaining 81 percent of large coal units are expected to 

meet the CO limit with a tune-up. The testing and monitoring costs for large coal units include a 

test for CO and mercury, as well as a bag leak detection system and oxygen monitoring for the 

80 boilers that are expected to install a fabric filter. There are no numerical PM emission limits 

under this option, and so no additional testing costs for PM or opacity monitoring costs were 

assessed in the cost impacts analysis for this option.

Under option 4E liquid and biomass boilers are not subject to numerical emission limits 

for mercury or CO and there are no costs included in the impacts analysis to install control 

equipment or conduct mercury or CO fuel analysis or stack testing. This cost impacts analysis 

includes the cost of a biennial tune-up for all the biomass and liquid fuel. 

Option 4E exempts small coal-fired boilers from numerical emission limits. Instead these 

units must conduct a work practice standard of a biennial tune-up. The cost impacts analysis does 

not include any additional testing and monitoring requirements for these small boilers.

Finally, option 4E proposes that all facilities with large boilers conduct an energy 

assessment. For this cost impacts analysis one large boiler per facility was assumed, or 13,268 

facilities estimated to conduct an assessment. Similar to the discussion under option 2E, the cost 

of the assessment ranged from $75,000 for industrial-scale energy assessments to between 

$2,000 and $5,000 per energy assessment for institutional and commercial-scale assessments.

2

 

3.5 Option 1N

New area source boilers are subject to an NSPS (40 CFR part 60 subparts Db, Dc) to 

regulate emissions of PM, NOx and SO2. The cost impacts analysis considered controls that 

would likely be installed to comply with the NSPS and includes an estimate of any additional 

control, testing and monitoring costs that would not be already conducted to meet the 

requirements of the NSPS. Based on a review of the NSPS, this analysis assumes all biomass 
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boilers greater than 30 mmBtu/hr will have an ESP control installed as the baseline to meet the 

NSPS PM limits; all coal boilers greater than 75 will have an FF and wet scrubber installed to

meet PM and SO2 limits; all coal boilers between 30 and 75 will have a Fabric Filter and use low 

sulfur coal to meet PM and SO2 limits, and all liquid boilers greater than 30 will have an FF 

installed to meet PM limits. The NSPS does not regulate PM for units less than 30 mmBtu/hr. 

Mercury Control

A new fabric filter installation was expected to achieve the mercury emission limits in the 

final rule. Where baseline mercury emissions were found to be greater than the MACT floor, the 

cost of a fabric filter was estimated for a portion of the boilers represented by the model unit. All 

new boilers, regardless of size or fuel, were expected to install a fabric filter in order to meet the 

mercury limits under this option. Comparing these mercury control requirement to the expected 

controls under the NSPS, all biomass boilers are expected to install a fabric filter to meet the 

mercury limit and all liquid and coal boilers less than or equal to 30 mmBtu/hr are expected to 

install a fabric filter to meet the mercury limit.

CO/Organic HAP Control

New boilers are expected to be equipped with new and efficient burners, and it was 

assumed that an annual tune-up could achieve the CO numeric emission limit for all sizes and 

types of boilers. Other advanced combustion controls were not considered as a control alternative 

for new boilers. As mentioned under 1E, the control strategy necessary to meet the MACT floor 

emission limit will vary depending on the magnitude between the baseline emissions and the CO 

MACT floor. 

Particulate Matter Control

Under this option all units are expected to install a fabric filter for mercury control, which 

has a co-benefit of reducing PM emissions, as well as other non-mercury metallic HAP. No 

additional control costs were estimated for PM control at new boilers.

Testing and Monitoring Cost Impacts
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Testing and monitoring requirements varied depending on the equipment installed on the 

unit to control emissions, the design capacity of the model unit, and the fuel category of the 

model unit.

Testing Costs

All boilers designed to burn solid fuels were expected to conduct an annual compliance 

test for PM, Hg, and CO. The cost to conduct stack tests for these three pollutants was estimated 

to be $15,000 per year. 

Boilers designed to burn liquid fuels were expected to conduct an annual compliance test 

for PM and CO. In lieu of a stack test boilers designed to burn liquid fuels were expected to 

conduct fuel analysis, or report fuel analyses received from a fuel supplier for chlorine and Hg. 

Conducting stack tests for PM and CO was estimated to be $13,000 per year and the cost to 

conduct fuel analysis for Hg was estimated to be $600 per year. Although solid fuels are eligible 

to comply with the final rule through fuel analysis in lieu of stack testing, when the mercury 

content of the fuel is below the MACT floor emission limit, this cost estimate conservatively 

assumed that only units designed to fire liquid fuels would use this compliance alternative. The 

methods and data sources used to estimate testing and monitoring costs are discussed in other 

memoranda.3

Monitoring Costs

Various monitor configurations were installed based on the size of the unit and the 

pollution control devices expected to be installed to achieve the MACT floor emission limits. For 

units expected to install a fabric filter, an annualized cost of $9,700 for a bag leak detection 

monitor was included in the cost analysis. For units that did not install a bag leak detector, an 

annualized cost of $14,660 for an opacity monitor was included in the cost analysis. 

3.6 Option 2N

Option 2N follows the same logic for estimating control costs as option 1N outlined 

above, with the exception of small units (less than 10 mmBtu/hr). In option 2N, the only cost 

estimated for small units is the cost of an annual tune-up for each boiler. No testing and 

monitoring costs were included in option 2N for small units 
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3.7 Option 3N

Option 3N includes identical requirement for coal units as outlined under option 1N. 

Under option 3N liquid and biomass boilers are not subject to numerical emission limits for 

mercury and there are no costs included in the impacts analysis to install fabric filters for 

mercury control or conduct mercury fuel analysis or stack testing. Liquid and biomass boilers are 

subject to numerical emission limits for CO. This cost impacts analysis estimates that all the 

biomass and liquid fuel units can meet the CO emission limits by conducting an annual tune-up. 

These units must also conduct testing and monitoring activities for CO to demonstrate 

compliance with the numerical emission limits.

Option 3N also includes a numerical PM emission limit for coal, biomass, and liquid 

boilers, based on the NSPS limits applicable to each of these categories. Since all coal units are 

subject to mercury emission limits, they are expected to meet a PM GACT limit of 0.03

lb/mmBtu without any additional control requirements. The NSPS PM limit for biomass is 0.03

lb/mmBtu, which is based on the performance of an electrostatic precipitator (ESP). Since 

biomass units greater than 30 mmBtu/hr are already subject to this limit under the NSPS, this 

cost analysis applies the costs for an ESP to units less than or equal to 30 mmBtu/hr. The NSPS 

PM limit for liquids is also 0.03 lb/mmBtu. Based on the calculated average baseline emission 

factors analysis distillate liquids are expected to meet that limit without any additional control.5

However residual liquid units are expected to install a fabric filter to meet the PM emission limit.

Under option 3N, all boilers less than or equal to 30 mmBtu/hr are estimated to incur 

costs to test for PM and CO, at an estimate cost of $14,000 per year. Boilers greater than 30 

mmBtu/hr will incur PM stack testing costs under the NSPS. Coal boilers are estimated to incur 

additional costs to test for mercury and the cost to conduct tests for PM, CO, and Hg is estimated 

to be $19,000 per year. 

3.8 Option 4N

Option 4N includes mercury and CO emission limits for coal units greater than 10 

mmBtu/hr. Under option 4N liquid and biomass boilers are not subject to numerical emission 

limits for mercury or CO and there are no costs included in the impacts analysis to install add-on 

controls for mercury or CO control or conduct mercury or fuel analysis or stack testing. This 

cost impacts analysis estimates an biennial tune-up to meet GACT requirements for all the 

biomass and liquid fuel units. 
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Option 4N also includes a numerical PM emission limit for coal, biomass, and liquid 

boilers. The emission limits are set for units between 10 mmBtu/hr and 30 mmBtu/hr 

respectively. Coal units in this range are expected to meet emission limits of 0.42 lb/mmBtu. 

These mid-range Biomass boilers are subject to an emission limit of 0.069 lb/mmBtu, and liquid 

units in this range must meet an emission limit of 0.03 lb/mmBtu. All units greater than or equal 

to 30 mmBtu/hr, regardless of fuel type, are expected to meet a PM GACT limit of 0.03 

lb/mmBtu. Coal units are expected to meet this limit using the same device installed for mercury 

control. Biomass units are expected to meet the PM emission limit using an electrostatic 

precipitator (ESP). Based on the calculated average baseline emission factors analysis distillate 

liquids are expected to meet that limit without any additional control.5 However residual liquid 

units are expected to install a fabric filter to meet the PM emission limit.

Under option 4N, all boilers from 10 mmBtu/hr to 30 mmBtu/hr are estimated to incur 

costs to test for PM, at an estimate cost of $8,000 per year. Boilers greater than 30 mmBtu/hr 

will incur PM stack testing costs under the NSPS. Coal boilers are estimated to incur additional 

costs to test for mercury and CO the cost to conduct tests for PM, CO, and Hg is estimated to be 

$19,000 per year.

3.9 Summary of Cost Impacts

In the final rule, option 4E is the option selected for existing boilers and option 4N is the 

option selected for new boilers. Table 1 summarizes the costs of the promulgated option for new 

and existing boilers at area sources of HAP. Appendix A of this memorandum provides a 

detailed summary of the costs for each model unit.

Table 1: Summary of Costs of Promulgated Options

Costs shown in $106 (2008) with capital recovery estimated at 7%

Type of 

Unit Option

Number 

of Boilers TAC

TAC 

considering 

fuel savings

Testing & 

Monitoring 

TAC Control TAC

Control 

TCI

New 4N 6,779 $48 $51.3 $25 $36 $100

Existing 4E 182,677 $436 $51.6 $7 $429 $1,295
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4.0 METHODOLOGY FOR ESTIMATING EMISSION 

REDUCTIONS

This section discusses the methodology used to estimate emission reductions from boilers 

at both existing and new facilities and it presents a summary of the results for the regulatory 

options 1E/1N and 4E/4N.

4.1 Emission Reductions from Existing Boilers

Each model area source boiler was assigned baseline emissions based on the calculated 

baseline averages for existing major source combustion units in the same size and fuel 

subcategory. The development of area source model units and the procedures and results of the 

baseline emissions analysis is presented in other memoranda.

5-6

Emission Reductions for Option 1E

Emission reductions for all pollutants were calculated on a ton per year basis. Emission 

reductions of Hg and CO were calculated by subtracting the baseline emissions assigned to each 

model unit from the MACT floor (or GACT) emission limits corresponding to the subcategory 

for each model boiler. A detailed discussion of the procedures and results of the MACT floor 

analysis is presented in another memorandum.

1

For all units expected to install a fabric filter to meet the mercury MACT floor emission 

limits, this fabric filter achieves a co-benefit of reducing emissions of PM and non-mercury 

metallic HAP. To calculate the PM emission reductions from units expected to install a fabric 

filter, the baseline emissions assigned to each model boiler were subtracted from the calculated 

average baseline emission factor corresponding to a fabric filter level of control in the same fuel 

category. For example, the PM baseline emission factor for uncontrolled or multiclone-equipped 

biomass boilers is 0.27 lb/mmBtu, and the calculated baseline emission factors for biomass 

boilers equipped with a fabric filter is 0.004 lb/mmBtu. The emission reductions were estimated 

using the difference of these two factors, or 0.266 lb/mmBtu. The methodology used to calculate 

average baseline emission factors for different fuel and control configurations is discussed in 
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another memorandum.5 It was assumed that the remaining boilers that did not install a fabric 

filter will install a cyclone or multiclone to reduce PM emissions. Multiclones were identified as 

a GACT level of control for PM. Emission reductions for units expected to install a multiclone 

were estimated by multiplying the baseline emissions of each model unit by the expected PM 

control efficiency of a multiclone specific to the fuel category. These control efficiencies for 

various control devices are detailed in another memorandum.5 Model units with a design 

capacity greater than 10 mmBtu/hr were expected to already have a multiclone installed as a 

baseline level of control, so no additional PM emission reductions were estimated from these 

units, unless the unit installed a fabric filter for mercury control. 

To estimate the reductions in other non-mercury metallic HAP, the percent reduction in 

filterable PM was calculated for each model boiler expected to install a fabric filter for mercury 

control. This percent reduction was multiplied by the baseline emissions for each of the nonmercury metallic HAP. Since fabric filters capture fine particulate, this analysis assumes that 

each model boiler would achieve an identical percent reduction from baseline emissions for each 

non-mercury metallic HAP as was achieved for PM. For model boilers that were expected to 

install a multiclone to meet the PM GACT limit, a 10 percent reduction was estimated for nonmercury metallic HAP.

PM2.5 emissions comprise a fraction of total filterable PM emissions depending on the 

fuel combusted and control device configuration installed on the unit. The methods used to 

derive the contribution of PM2.5 to overall filterable PM are presented in other memoranda.5

 To 

calculate emission reductions for PM2.5 for each model boiler, the emission reductions for PM 

were multiplied by the applicable PM2.5 fraction. 

For any boiler conducting a tune-up or installing advanced combustion controls such as a 

replacement burner or linkageless boiler management system, a one percent gain in combustion 

efficiency was estimated, resulting in an estimated one percent emissions reduction of all 

pollutants. Efficiency gains reduce fuel use, and in turn, emissions of hazardous air pollutants.8 

A one percent reduction in emissions for these pollutants was estimated by multiplying the 

baseline emissions for each unit by a factor of 0.01.

To convert emission reductions from an emission rate on a heat input basis to an annual 

emission rate, Equation 2 was used:
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Annual Emission Rate (tpy) = ERHI * 0.0005 * Ophours * CF (Equation 2)

Where:

ERHI = emission rate (lb/mmBtu)

0.0005 = conversion factor, lbs per ton

Ophours = annual operating hours, assumed 8760 (adjusted using capacity factor)

CF = annual average capacity factor, 0.68

To convert emission reductions from a concentration basis to an annual emission rate, 

Equations 3 and 4 were used:

Annual Emission Rate (tpy) = ERC * 0.000001 * QS * 60 * Ophours * MW * 0.0026 * 

0.0005 * (20.946 – O2) / (20.946 – Std O2) * CF (Equation 3)

Where:

ERC = emission concentration (ppm @ 3% O2)

0.000001 = conversion factor, ppm to parts

QS = exhaust flowrate (dscfm)

60 = conversion factor, minutes to hours

Ophours = annual operating hours reported in 2008 survey (hours/year)

MW = molecular weight of pollutant, in lb per lb-mole

0.0026 = conversion factor, lb-mole per dry standard cubic foot of gas

0.0005 = conversion factor, lb per ton

20.946 = percentage of oxygen in ambient air

O2 = percentage of oxygen assumed in exhaust gas

Std. O2 = 3 percent oxygen in standardized emission concentration for final rule. 

CF = annual average capacity factor, 0.68

Annual Emission Rate (tpy) = ERC * 0.0283 * QS * 60 * Ophours * 0.000000001 * 0.0022 

* 0.0005 * (20.946 – O2) / (20.946 – Std O2) * CF (Equation 4)

Where:

ERC = emission concentration (ng/dscm @ 7% O2)

0.0283 = conversion factor, dry standard cubic meter per dry std. cubic foot

QS = exhaust flowrate (dscfm)

60 = conversion factor, minutes per hour

Ophours = annual operating hours reported in 2008 survey (hours/year)

0.000000001 = conversion factor, ng to g

0.0022 = conversion factor, g per lb

0.0005 = conversion factor, lb per ton

20.946 = percentage of oxygen in ambient air

O2 = percentage of oxygen assumed in exhaust gas

Std O2 = 7 percent oxygen in standardized emission concentration for final rule.

CF = annual average capacity factor, 0.68
17

Converting concentrations to an annual emission rate required an oxygen concentration 

and exhaust flowrate estimated for each specific fuel type. The development of these 

assumptions and estimates is presented in another memorandum.4

Emission Reductions for Option 4E

The same calculations discussed for estimating emission reductions for option 1E were 

applied to all large coal boilers. For small model boilers, the emission reductions were based on a 

one percent gain in efficiency expected from the biennial tune-up work practice standard. For 

large biomass and liquid units no add-on controls for PM or mercury are expected since these

units are not subject to numerical emission limits for PM or Hg. Instead, a similar one percent 

gain in efficiency is expected to occur as a result of conducting an annual tune-up or installing 

advanced combustion controls necessary to meet the CO numerical limit in each category. 

Efficiency gains reduce fuel use, and in turn, emissions of hazardous air pollutants. A one 

percent reduction in all types of emissions was estimated by multiplying the baseline emissions 

for each unit by a factor of 0.01. A summary of the estimated emission reductions at existing 

units for all options is located in Appendix B-1.

4.2 Emission Reductions from New Boilers 

Based on industrial and commercial fuel consumption projections from the EIA and a 

history of boiler installation dates in the boiler inspector inventory, there are 6,779 new area 

source boilers expected to come on-line by 2013.7

 These new projected boilers are expected to 

fire biomass, coal, and liquid fuels. An average (mean) design capacity of area source boilers 

firing similar fuel type, in the same size category, and in the same sector (industrial or 

commercial) was estimated to develop new model units representative of the existing boiler 

inventory. New model units were assigned baseline emissions in the same manner as existing 

area source model units. The projection of new model area source boilers and the procedures 

and results of the baseline emissions analysis is presented in other memoranda.

2

As discussed in Section 3.4, the NSPS for Industrial, Commercial and Institutional 

Boilers (40 CFR part 60, subparts Db, Dc) (NSPS) were reviewed to identify the expected 

baseline level of control for projected new units. Then, the average baseline emission factor 
18

corresponding to the expected level of control and fuel category was assigned to each new model 

boiler. New biomass boilers larger than 30 mmBtu/hr were expected to install an ESP; new coal 

boilers larger than 75 mmBtu/hr were expected to install a fabric filter and wet scrubber; new 

coal boilers between 30 and 75 mmBtu/hr would only have a fabric filter installed and were 

expected to meet the SO2 limits in the NSPS by using coals with a low sulfur content; new 

boilers larger than 30 mmBtu/hr and combusting liquid fuels were expected to install a fabric

filter. All new boilers less than 30 mmBtu/hr would have no add-on controls. For this impacts 

analysis, it was assumed that all new solid fuel units would be stokers, since stoker boilers are 

the most common type of solid fuel boilers and all new units would have NOx control installed 

as a baseline control, regardless of fuel. Based on the EIA fuel projections, all new coal boilers 

are projected to be less than 10 mmBtu/hr and the only 49 model boilers firing biomass are 

expected to exceed 30 mmBtu/hr. 

Emission Reductions for Option 1N

After an appropriate baseline level of control was determined for each model unit, an 

average baseline emission factor was calculated for existing units within the same fuel category 

and having the same level of control was assigned to each model boiler. The NSPS specifies PM 

and SO2 limits for new solid- and liquid-fired combustion units based on heat input. It was 

assumed that all new solid and liquid units would be constructed to meet these limits and those 

limits were used as baseline emission values, where applicable. For units less than 30 mmBtu/hr, 

the baseline emissions for PM were estimated assuming the unit was uncontrolled and the target 

PM emission limit from the NSPS was used as the GACT level of control. The baseline 

emissions for each unit were subtracted from the new source MACT floor for Hg and CO and 

GACT emission limit for PM corresponding to each unit’s subcategory. The same calculations 

discussed in Section 4.1 of this memo were used to estimate the reductions for new units.

Emission Reductions for Option 4N

For new coal boilers, the emission reductions were calculated using the same methods 

discussed for Option 1N above. For new biomass boilers less than 30 mmBtu/hr, emission 

reductions for PM were calculated by subtracting the PM NSPS emission limits from a baseline 

emission factor representing uncontrolled units. Since an ESP is not expected to be very effective 
19

at capturing mercury emissions, mercury emissions reductions from all biomass units were

estimated based on a one percent efficiency improvement, resulting from annual tune-ups or 

other combustion controls expected to occur in order to demonstrate compliance with CO 

emission limits. For new biomass boilers greater than or equal to 30 mmBtu/hr, there were no 

estimated additional PM or non-Hg metallic HAP emission reductions since these larger biomass 

boilers are already expected to be in compliance with a PM NSPS limit using an ESP. 

New residual liquid boilers less than 30 mmBtu/hr were expected to install a fabric filter 

to meet the PM emission limit. Since a fabric filter is effective at capturing fine particulate, 

additional emission reductions for mercury were calculated by subtracting the average baseline 

emission factor for heavy liquid boilers equipped with a fabric filter from the average baseline 

emission factor corresponding to an uncontrolled heavy liquid unit. 

The average baseline emission factor for PM at uncontrolled distillate liquid units is less 

than the NSPS emission limit for liquid units. As a result, no additional PM, Hg, or non-Hg 

metallic HAP emission reductions were estimated from installing additional PM controls. 

Instead, these reductions were estimated based on a one percent efficiency improvement, 

resulting from annual tune-ups or other combustion controls expected to occur in order to 

demonstrate compliance with CO emission limits. 

 Under this option, new small units do not qualify for the same tune-up work practice 

standards that apply to existing units since it is expected that new units can be designed to allow 

for stack test diameters that would be compatible with EPA test methods. A summary of the 

estimated emission reductions at for all new source options is located in Appendix B-2.

5.0 METHODOLOGY FOR ESTIMATING SECONDARY 

IMPACTS

Secondary impacts include the solid waste and electricity required to operate air pollution 

control devices, as well as the additional energy savings resulting from improved combustion 

controls or work practices required by the NESHAP. This section documents the inputs and 

equations used to estimate these secondary impacts, and it summarizes the impacts at existing 

units under promulgated regulatory option 4E and new units under promulgated regulatory 

option 4N. Table 5-1 summarizes the secondary impacts of this promulgated NESHAP. 
20

Appendices C-1 and C-2 present a detailed breakdown of the secondary waste and energy 

impacts from each subcategory of existing and new boilers, respectively.

Table 5-1:. Summary of Secondary Impacts

Impact New Units

(Option 4N)

Existing Units

(Option 4E)

Solid Waste (tons/yr) 540 1,800

Purchased Electricity (kW-hr/yr) 8.0 million 25.4 million

CO2 Emissions from Electricity (tons/yr) 5,300 16,900

Energy Savings* (tBtu/yr) 2.3 19.6

* Energy savings is calculated for units in the coal and liquid subcategories.

The secondary impacts were calculated using algorithms and assumptions described in 

another memorandum.3 These algorithms and assumptions were applied to the existing boilers, 

where the baseline emissions for each unit exceeded the promulgated MACT floor emission 

limit. For new units, the algorithms and assumptions were applied to model units representing 

units expected to come online between 2010 and 2013, when the baseline emissions for each 

model exceeded the promulgated MACT floor or GACT emission limit for new units. The 

methodology used to assign baseline emission factors to new and existing units are discussed in 

another memorandum.5

5.1 Solid Waste Impacts

Solid waste is generated from collecting dust and fly ash in fabric filters or ESP control 

devices. Solid waste impacts were estimated for every unit expected to install a fabric filter to 

meet mercury emission limits, or install an ESP to meet PM emission limits. The total national

solid waste amounts in Table 5-1 were determined by adding the per unit solid waste estimates 

for all new and existing units, respectively. To estimate the solid waste contribution from each of 

these control devices, the variables were calculated based on characteristics reported for each 

model unit. The calculations used to estimate each variable and the quantity of solid waste 

generated are provided in another memorandum.3

The solid waste (dust, fly ash) generated by the use of an electrostatic precipitator was 

calculated when an electrostatic precipitator was determined to be necessary to meet the GACT 
21

emission limits for PM. Estimates of the solid waste collected in an ESP was based on several 

variables including: exhaust flow rate from the combustion unit to the control device (acfm); 

the inlet loading of particulate matter to the control device (gr/acfm); operating hours (hr/year) 

and the efficiency of the control device required to meet the PM emission limits in the 

promulgated NESHAP. 

The solid waste generated from the collection of dust and fly ash in a fabric filter was 

calculated when a fabric filter was determined to be necessary to meet the promulgated NESHAP 

emission limits for particulate matter and/or mercury. The calculation required the use of three 

variables, including: exhaust flow rate from the combustion unit to the control device (dscfm); 

operating hours (hr/year) and the inlet loading of particulate matter to the control device 

(gr/acfm).

5.2 Electricity Impacts

The amount of electricity required to operate a control device was calculated for an 

electrostatic precipitator and fabric filter. These impacts were assessed for every unit that was 

estimated to require particulate matter control. Electricity requirements are one output of the 

cost algorithms used in the analyses, so no additional calculations were necessary. For some 

units, an electrical demand from multiple control devices was estimated. The total national 

electricity demand in Table 5-1 was determined by adding the per unit solid waste estimates for 

all new and existing units, respectively. To estimate the electricity demand from each of these 

control devices, a set of variables were calculated based on characteristics assigned to each 

model unit. The constants, variables, and calculations used to estimate each variable and the 

electricity demand to operate the control devices are provided in another memorandum.3

5.3 Greenhouse Gas Emissions from Electricity Usage

Since Greenhouse Gases are generated from electricity production, an estimate of carbon 

dioxide emissions was generated for the electricity impacts of the add-on air pollution control 

devices. The total electricity impact amount was multiplied by the national average carbon 

monoxide emission factor for carbon dioxide emissions from EPA’s 2005 e-GRID to obtain the 

expected annual carbon dioxide emissions.9 No carbon dioxide emissions were estimated for 

boilers conducting a boiler tune-up since no electricity impacts were estimated for those units.
22

5.4 Energy Savings Impacts

The energy savings from combustion controls such as low NOx burners or linkageless 

boiler management systems, and work practice standards, including a tune-up, and implementing 

the energy audit findings with a short-term payback can improvements in efficiency, thereby 

reducing fuel consumption. Although these combustion improvements have been documented to 

achieve efficiency gains between 5 and 10 percent from the baseline operating conditions, this 

secondary impacts analysis estimates a 1 percent efficiency gain, to be conservative and 

consistent with the assumptions made in Section 3.1 of this memorandum. Quantifying the exact 

gains in efficiency from each of these work practice standards is difficult, and may depend on the 

baseline operating efficiency of each unit. 

Section 3.1 discusses the fuel savings impacts in terms of annualized cost savings to each 

boiler, and the national energy savings presented in Table 5-1 of this section follows the same 

methodology as was discussed in Section 3.1 and reflect the savings from boilers in the coal and 

liquid fuel categories only.

5.5 Estimating Secondary Impacts for Regulatory Options 4E/4N

Regulatory Options 4E for existing and 4N for new units are both described in detail in 

Section 2 of this memorandum. For the secondary impacts analysis at existing units under option 

4E, the waste and electricity impacts were only assessed for large units (those greater than or 

equal to 10 mmBtu/hr) that are in the coal subcategory. Secondary impacts of solid waste and 

electricity were not assessed for the liquid and biomass subcategories because these boilers were 

not subject to PM or Hg numerical emission limits and were not expected to install add-on 

controls. Energy savings were estimated for all units firing anything other than biomass since all 

units were expected to conduct a tune-up or install combustion controls.

For new units under option 4N, the solid waste and electricity impacts were assessed for 

any size unit firing coal, liquid, or biomass, using the NSPS limit of 0.03 lb/mmBtu for PM. A 

one percent energy savings was estimated for all units firing coal or liquids that were estimated 

to require a tune-up to meet the CO limits from new boilers. Both tune-ups and combustion 

controls improve the efficiency of the unit, thereby reducing energy consumption.

6.0 REFERENCES
23

1. Singleton, A. and B. Long, ERG. Revised MACT Floor and GACT Analysis for the 

Industrial, Commercial, and Institutional Boilers National Emission Standards for 

Hazardous Air Pollutants – Area Source. January, 2011.

2. Singleton, A., ERG. New Unit Analysis Industrial, Commercial, and Institutional Boilers 

National Emission Standards for Hazardous Air Pollutants – Area Source. April, 2010.

3. Singleton, Aand S. McClutchey ERG. Revised Methodology for Estimating Control 

Costs for Industrial, Commercial, Institutional Boilers for the National Emission 

Standards for Hazardous Air Pollutants – Area Source. January, 2011.

4. Singleton, A. and S. McClutchey, ERG. Revised Methodology for Estimating Control 

Costs for Industrial, Commercial, Institutional Boilers and Process Heaters National 

Emission Standards for Hazardous Air Pollutants – Major SourceJanuary, 2011.

5. Gibson, G. and A. Singleton, ERG. Revised Development of Baseline Emission Factors 

for Boilers and Process Heaters at Commercial, Industrial, and Institutional Facilities. 

January, 2011.

6. Singleton, A., ERG. Methodology for Developing Model Units for Industrial, 

Commercial, and Institutional Boilers National Emission Standards for Hazardous Air 

Pollutants – Area Source. April, 2010.

7. U.S. Department of Energy. Energy Information Administration. Annual Energy Outlook 

2006 (Early Release) with Projections to 2030. Figure 3. Energy Consumption by Fuel, 

1980-2030 (quadrillion Btu).

8. Delta Institute. Sector-Based Based Pollution Prevention: Toxic Reductions through 

Energy Efficiency and Conservation Among Industrial Boilers. July 2002. Located 

online at http://www.delta-institute.org/publications/boilers/SectorBasedP2.pdf

9. U.S. Environmental Protection Agency. The Emissions & Generation Resource 

Integrated Database (eGRID). 2007. Located online at: 

http://www.epa.gov/cleanenergy/documents/egridzips/eGRID2007V1_1_year05_Summa

ryTables.pdf