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MEMORANDUM 

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

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

DATE: April 2010 

SUBJECT: 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 by the year 2013, 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 proposed 

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 Impacts Shown in Regulatory Impacts Analysis (RIA) 

7.0 References 
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2.0 OVERVIEW OF REGULATORY OPTIONS 

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

description of the three 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 audit. 

 Option 3E represents the primary proposed option discussed 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 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 audit. 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. 

2.2 New Units 

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

detailed description of the three options is described below. 

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

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. 
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 Option 3N represents the primary proposed option discussed in the preamble. In this 

option, 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. 

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 three options 

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

option 3E for existing units and option 3N for new units is presented in Table 1. 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: 

3.1 Option 1E 

Control Cost Impacts 

Mercury Control 

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

proposed 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, 44 percent of units were achieving the proposed MACT floor 

emission limit for coal, so a new fabric filter was estimated to be installed at 56 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 
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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 (other than Dutch ovens and PC-coal 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 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 proposed 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 meeting 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, 

72 percent of the units are exceeding the MACT floor emission limits, and so 72 percent of the 

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

86 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. 
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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 

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 greater than 100 mmBtu/hr were expected to install CO CEMS in 

lieu of conducting a CO stack test and the cost to conduct tests on PM and Hg was estimated to 

be $12,000 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. Combustion units greater than 

100 mmBtu/hr were expected to install CO CEMS in lieu of conducting a CO stack test and the 

cost to conduct tests on PM and fuel analysis for Hg was estimated to be $8,600 per year. 

Although solid fuels are eligible to comply with the proposed 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 
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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 greater than 100 mmBtu/hr, an annualized 

cost of $53,300 for a CO CEMS 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 audit. 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 

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 
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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 audit 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 audit ranges from $75,000 for industrial-scale energy audits to between $2,000 

and $5,000 per energy audit for institutional and commercial-scale audits.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 inventory. The cost of each type of audit was 

annualized over 5 years at 7 percent to obtain an annualized cost estimate. 

3.3 Option 3E 

The proposed 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 
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321 boilers that are expected to install a fabric filter. There are no proposed 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 audit. 

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

estimated to conduct an audit. Similar to the discussion under option 2E, the cost of the audit 

ranged from $75,000 for industrial-scale energy audits to between $2,000 and $5,000 per energy 

audit for institutional and commercial-scale audits.2

 

3.4 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 

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. 
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Mercury Control 

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

proposed 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 

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 
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to be $15,000 per year. Combustion units greater than 100 mmBtu/hr were expected to install 

CO CEMS in lieu of conducting a CO stack test and the cost to conduct tests on PM and Hg was 

estimated to be $12,000 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. Combustion units greater than 

100 mmBtu/hr were expected to install CO CEMS in lieu of conducting a CO stack test and the 

cost to conduct tests on PM and fuel analysis for Hg was estimated to be $8,600 per year. 

Although solid fuels are eligible to comply with the proposed 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 greater than 100 mmBtu/hr, an annualized 

cost of $53,300 for a CO CEMS 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. 

3.4 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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3.5 Option 3N 

The proposed 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. 

3.6 Summary of Cost Impacts 

Option 3E is the proposed option for existing boilers and option 3N is the proposed 

option for new boilers. Since new boilers and their exhaust stacks can be designed to allow for 

stack testing, the tune-up work practice standard does not apply to new small units. Table 1 

summarizes the costs of the proposed 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. 
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Table 1: Summary of Costs of Proposed 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 3N 6,779 $317 $266 $193 $124 $388 

Existing 3E 182,677 $696 $279 $94 $550 $1,672 

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 3E/3N.

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 
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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 0.26 lb/mmBtu, and the calculated baseline emission factors for biomass 

boilers equipped with a fabric filter is 0.01 lb/mmBtu. The emission reductions were estimated 

using the difference of these two factors, or 0.25 lb/mmBtu. The methodology used to calculate 

average baseline emission factors for different fuel and control configurations is discussed in 

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, a 75 percent reduction. 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 
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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: 

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, 0.5 for liquid and 0.65 for coal and biomass 

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 * ρair * QS * 60 * Ophours * 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 

ρair = density of air, 0.0749 lb/dscf 

QS = exhaust flowrate (dscfm) 

60 = conversion factor, minutes to hours 

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

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 proposed rule. 

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

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, dscm to dscf 

QS = exhaust flowrate (dscfm) 

60 = conversion factor, minutes to hours 

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

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

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 3E 

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 both option 1 and option 2a are 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 
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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 

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. 
17

Emission Reductions for Option 3N

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 

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 proposed 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. As a result, 

new A summary of the estimated emission reductions at existing units for both option 1N and the 

proposed option 3N are located in Appendix B-2. 

Incremental Emission Reductions if Energy Audit Findings are Implemented 

We evaluated the potential additional reductions and fuel savings that could occur as a 

result of implementing certain cost-effective energy efficiency improvements identified during 
18

the audit. Using the Department of Energy references of a 10 to 15 percent improvement in 

efficiency, a range of incremental emission reductions was estimated considering efficiency 

gains between 5 and 10 percent. We applied the control efficiency ranges of 5 and 10 percent 

reduction to the emissions remaining after MACT level of controls were installed on the unit to 

identify the potential for additional emission reductions if the findings of an energy audit were 

implemented. Table 3 summarizes the potential additional emission reductions that could occur 

under a beyond the floor option of implementing any findings in the audit with a short term 

payback. The fuel savings were estimated using Equation 1 described in 3.1 of this memo that 

was used to estimate fuel savings. In this case the efficiency gain term was modified to be 

between 5 and 10 percent. A summary of the estimated incremental emission reduction and fuel 

savings is shown in Table 3. 

A summary of the estimated emission reductions at existing area source boilers for 

options 1E, 2E, and the proposed option 3E are located in Appendix B-1. A summary of the 

estimated emission reductions at new area source boilers for options 1N, 2N, and the proposed 

option 3N are located in Appendix B-2. 
19

Table 3 Emission Reductions and Energy Savings Resulting from Implementing Cost Effective Findings of an 

Energy Audit at Facilities with Large (≥10 mmBtu/hr) Boilers 

 Assuming a Five Percent Efficiency Gain From Implementing Audit Findings 

Emission 

Reductions and 

Energy Savings Per 

Facility 

HCl 

Emission 

Reductions 

(tpy) 

Filterable 

PM 

Emission 

Reductions 

(tpy) 

Non-Hg 

Metals 

Emission 

Reductions 

(tpy) 

Hg 

Emission 

Reductions 

(tpy) 

VOC 

Emission 

Reductions 

(tpy) 

Energy 

Saved 

(mmBtu/yr) 

Annual Fuel 

Savings ($/yr) 

Min 3.92E-03 3.01E-02 1.12E-03 9.21E-07 3.59E-04 3.85E+03 $0 

Max 2.40E-01 3.11E+00 1.64E-01 3.28E-05 2.93E-02 3.80E+04 $860,704 

Average 1.73E-02 1.74E-01 1.98E-02 4.64E-06 1.86E-03 6.15E+03 $95,279 

Median 3.92E-03 3.01E-02 2.39E-02 3.45E-06 4.20E-04 5.54E+03 $125,613 

TOTAL 

(13,268 facilities with 

a large boiler) 

2.29E+02 2.31E+03 2.63E+02 6.16E-02 2.47E+01 8.16E+07 $1,264,161,683 

 Assuming a 10 Percent Efficiency Gain From Implementing Audit Findings 

Emission 

Reductions and 

Energy Savings Per 

Facility 

HCl 

Emission 

Reductions 

(tpy) 

Filterable 

PM 

Emission 

Reductions 

(tpy) 

Non-Hg 

Metals 

Emission 

Reductions 

(tpy) 

Hg 

Emission 

Reductions 

(tpy) 

VOC 

Emission 

Reductions 

(tpy) 

Energy 

Saved 

(mmBtu/yr) 

Annual Fuel 

Savings ($/yr) 

Min 7.84E-03 6.02E-02 2.25E-03 1.84E-06 7.18E-04 7.69E+03 $0 

Max 4.80E-01 6.23E+00 3.28E-01 6.56E-05 5.87E-02 7.60E+04 $1,721,408 

Average 3.45E-02 3.48E-01 3.96E-02 9.28E-06 3.73E-03 1.23E+04 $190,558 

Median 7.84E-03 6.02E-02 4.79E-02 6.89E-06 8.40E-04 1.11E+04 $251,226 

TOTAL 

(13,268 facilities with 

a large boiler)

4.58E+02 4.62E+03 5.26E+02 1.23E-01 4.94E+01 1.63E+08 $2,528,323,367 

* Although the energy savings in mmBtu/yr are calculated for all fuels, additional fuel savings in $/yr consider only 

units in the coal and liquid categories. Biomass is often an industrial byproducts and was not assigned a purchase 

price.

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 proposed regulatory option 3E and new units under proposed regulatory option 3N. 
20

Table 5-1 summarizes the secondary impacts of this proposed NESHAP. 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 

(proposed regulatory Option 3N) 

Existing Units 

(proposed regulatory Option 3E)

Solid Waste (tons/yr) 2,100 14,300

Purchased Electricity (kW-hr/yr) 24 million 206 million

Energy Savings* (tBtu/yr) 2.34 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 proposed 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 proposed 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 proposed 

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 proposed 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 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 
22

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. 

5.4 Estimating Secondary Impacts for Regulatory Options 3E/3N 

Regulatory Options 3E for existing and 3N for new units are both described in detail in 

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

3E, 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 3N, the solid waste and electricity impacts were assessed for 

any size unit firing coal, liquid, or biomass. 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 IMPACTS ANALYSIS PRESENTED IN RIA 

The cost, emission reduction, and secondary impacts summarized in Sections 3, 4, and 5 

of this memorandum reflect the impacts for new units when using the NSPS limit of 0.03 

lb/mmBtu for PM. The cost and emission reductions analyzed in the RIA and presented in the 

preamble reflect an earlier analysis that were incorrectly based on the PM NSPS limits for 

modified sources, which were 0.1 lb/mmBtu for biomass and 0.051 lb/mmBtu for liquid and 

coal. The results of this earlier analysis are summarized in Appendix D in order to document the 

values used in the RIA. The cost, emission, and secondary impacts all increased as a result of this 
23

revision. The total annualized costs increased from $311 million to $317 million as a result of 

increased removal efficiencies on the ESPs expected to be needed for new biomass boilers. 

7.0 REFERENCES 

1. Singleton, A., ERG. MACT Floor Analysis for the Industrial, Commercial, Institutional 

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

2010. 

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, A., ERG. Methodology for Estimating Control Costs for Industrial, 

Commercial, Institutional Boilers National Emission Standards for Hazardous Air 

Pollutants – Area Source. April, 2010. 

4. Singleton, A., ERG. Methodology for Estimating Control Costs for Industrial, 

Commercial, Institutional Boilers and Process Heaters National Emission Standards for 

Hazardous Air Pollutants – Major Source. April, 2010. 

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

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

2010. 

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
Appendix A-1: Control, Testing and Monitoring Costs for Option 1E at Existing Area Source Boilers

 SIC Code 

 Number of 

Affected Boilers in 

SIC Code 

 Total Annualized 

Cost ($2008) 

 Total Capital 

Costs ($2008) 

01 - - - 

02 656 140,251,289 463,435,526 

07 - - - 

09 - - - 

14 165 28,346,481 81,576,819 

16 - - - 

17 603 121,847,342 390,533,836 

20 13,477 2,668,117,949 8,120,044,727 

23 165 28,346,481 81,576,819 

24 7,663 1,536,122,308 4,215,718,924 

26 - - - 

40 658 113,385,927 326,307,275 

41 - - - 

42 165 28,346,481 81,576,819 

43 - - - 

44 - - - 

45 54 18,403,948 72,901,690 

47 - - - 

48 1,481 255,118,336 734,191,367 

50 548 113,862,043 356,535,886 

51 951 220,220,650 744,250,567 

52 - - - 

53 1,149 225,290,735 708,165,983 

54 - - - 

55 1,601 282,735,961 840,876,141 

56 - - - 

57 - - - 

58 1,809 311,811,298 897,345,005 

59 576 107,229,332 271,934,921 

60 658 113,385,927 326,307,275 

64 54 18,403,948 72,901,690 

65 5,953 1,050,988,519 3,058,842,579 

70 9,947 1,749,844,150 5,058,941,834 

72 4,547 829,028,266 2,485,505,736 

73 329 56,692,964 163,153,637 

75 3,212 570,849,674 1,708,110,830 

76 - - - 

79 2,301 396,850,742 1,142,075,460 

80 34,412 6,564,371,776 20,261,355,450 

81 - - - 

82 68,103 12,025,782,792 35,034,528,390 

83 - - - 

84 329 56,692,964 163,153,637 

86 6,713 1,174,453,100 3,363,178,900 

87 1,331 232,149,606 678,973,095 

91 to 98 11,590 2,188,336,955 6,668,804,846 

Unknown 1,477 308,849,061 1,008,447,872 

TOTAL 182,677 33,536,117,005 99,581,253,536 
Appendix A-2: Control, Testing and Monitoring Costs for Option 3E at Existing Area Source Boilers

 SIC 

 Number of 

Affected 

Boilers in 

SIC Code 

 Total Annualized 

Cost ($2008) 

 Total Capital Costs 

($2008) 

 Number of 

Affected 

Facilities in 

SIC Code 

 Energy Audit - 

TAC 

 TAC Including 

Energy Audit Fuel Savings ($/yr) 

TAC considering 

Energy Savings 

 01 - - - - - - -

 02 656 2,551,540 5,603,665 328 138,348 2,689,888 4,860,346 (2,170,458)

 07 - - - - - - -

 09 - - - - - - -

 14 165 366,540 1,065,060 83 366,540 168,533 198,007

 16 - - - - - - -

 17 603 2,067,568 4,800,835 302 93,086 2,160,654 3,528,846 (1,368,192)

 20 13,477 43,504,037 103,985,544 6,739 1,718,248 45,222,285 51,704,498 (6,482,213)

 23 165 366,540 1,065,060 83 366,540 168,533 198,007

 24 7,663 32,453,710 68,505,280 3,832 42,272,812 74,726,522 172,773 74,553,749

 26 - - - - - - -

 40 658 1,466,163 4,260,234 329 1,466,163 664,975 801,188

 41 - - - - - - -

 42 165 366,540 1,065,060 83 366,540 168,533 198,007

 43 - - - - - - -

 44 - - - - - - -

 45 54 483,972 802,830 27 46,116 530,088 1,503,641 (973,553)

 47 - - - - - - -

 48 1,481 3,298,867 9,585,526 741 - 3,298,867 1,496,034 1,802,833

 50 548 2,683,187 5,350,553 275 187,026 2,870,213 1,838,259 1,031,954

 51 951 5,221,580 10,085,884 476 390,278 5,611,858 7,244,668 (1,632,810)

 52 - - - - - - -

 53 1,149 3,651,163 8,798,839 575 138,348 3,789,511 5,363,498 (1,573,987)

 54 - - - - - - -

 55 1,601 3,564,475 10,357,302 801 3,564,475 2,028,808 1,535,667

 56 - - - - - - -

 57 - - - - - - - -

 58 1,809 4,031,948 11,715,643 905 4,031,948 1,830,652 2,201,296

 59 576 1,284,589 3,732,637 288 - 1,284,589 - 1,284,589

 60 658 1,466,163 4,260,234 329 - 1,466,163 664,975 801,188

 64 54 483,972 802,830 27 46,116 530,088 1,503,641 (973,553)

 65 5,953 51,634,752 164,967,217 2,977 168,238 51,802,990 7,790,731 44,012,259

 70 9,947 23,262,787 65,784,397 4,974 138,348 23,401,135 13,681,323 9,719,812

 72 4,547 11,949,922 31,705,665 2,274 231,434 12,181,356 11,722,531 458,825

 73 329 733,082 2,130,116 165 - 733,082 334,618 398,464

 75 3,212 7,161,881 20,810,303 1,606 - 7,161,881 4,226,792 2,935,089

 76 - - - - - - -

 79 2,301 5,131,569 14,910,818 1,151 - 5,131,569 2,327,036 2,804,533

 80 34,412 139,408,571 379,580,608 17,206 3,267,404 142,675,975 132,026,007 10,649,968

 81 - - - - - - -

 82 68,103 198,885,995 578,352,776 34,052 1,278,438 200,164,433 103,865,356 96,299,077

 83 - - - - - - -

 84 329 733,082 2,130,116 165 733,082 334,618 398,464

 86 6,713 15,330,564 43,942,628 3,357 46,116 15,376,680 7,660,458 7,716,222

 87 1,331 2,965,261 8,616,166 666 - 2,965,261 1,513,042 1,452,219

 91 to 98 11,590 72,207,180 211,404,277 5,796 1,191,330 73,398,510 35,977,999 37,420,511

 Unknown 1,477 5,469,622 12,272,385 739 277,550 5,747,172 10,068,077 (4,320,905)

 TOTAL 182,677 644,186,822 1,792,450,488 91,351 51,629,236 695,816,058 416,439,799 279,376,259 

*Fuel savings estimates were prepared for boilers firing coal and oil. These estimates were based on an annual capacity factor of 65 percent 

for coal and a 50 percent capacity factor for liquids. Both assume a 1 percent gain in efficiency due to the installation of combustion controls 

or a tune-up.
Appendix A-3: Control, Testing and Monitoring Costs for Option 1N at New Area Source Boilers

Model Unit Sector

Number of 

Boilers 

Represented 

by Model

Design 

Capacity 

(mmBtu/hr)

Size 

Category

Fuel 

Category Baseline Control

TCI - Control Only 

($)

TAC - Control Only 

($/yr) TCI - T&M ($) TAC - T&M ($/yr) TOTAL - TCI ($)

New Biomass Unit 1 Commercial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 64,340,788 $ 22,109,735 $ 3,115,000 $ 2,009,000 $ 67,455,788 $ New Biomass Unit 2 Industrial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 64,340,788 $ 22,109,735 $ 3,115,000 $ 2,009,000 $ 67,455,788 $ New Biomass Unit 4 Commercial 11 21.0354469 > 10 Biomass Cyclone or Multiclone 14,143,051 $ 4,356,757 $ 489,500 $ 315,700 $ 14,632,551 $ New Biomass Unit 3 Industrial 49 131 > 10 Biomass Electrostatic Precipitator 209,047,426 $ 51,241,589 $ 9,519,377 $ 3,381,147 $ 218,566,803 $ New Coal Unit 1 Commercial 62 6.68176984 <= 10 Coal Cyclone or Multiclone 58,804,640 $ 19,965,091 $ 2,759,000 $ 1,779,400 $ 61,563,640 $ New Coal Unit 2 Industrial 93 6.68176984 <= 10 Coal Cyclone or Multiclone 88,206,961 $ 29,947,636 $ 4,138,500 $ 2,669,100 $ 92,345,461 $ New Distillate Unit 1 Commercial 5435 6.76086488 <= 10 Liquid No HAP APCD Control 4,610,126,467 $ 1,630,788,657 $ 217,943,500 $ 132,070,500 $ 4,828,069,967 $ New Distillate Unit 2 Industrial 407 6.76086488 <= 10 Liquid No HAP APCD Control 345,229,342 $ 122,121,616 $ 16,320,700 $ 9,890,100 $ 361,550,042 $ New Distillate Unit 3 Commercial 352 25.3122861 > 10 Liquid No HAP APCD Control 424,131,187 $ 132,826,851 $ 14,115,200 $ 8,553,600 $ 438,246,387 $ 

New Distillate Unit 4 Industrial 90 25.3122861 > 10 Liquid No HAP APCD Control 108,442,633 $ 33,961,411 $ 3,609,000 $ 2,187,000 $ 112,051,633 $ 

New Residual Unit 1 Commercial 95 5.94997049 <= 10 Liquid No HAP APCD Control 78,990,019 $ 28,173,707 $ 3,809,500 $ 2,308,500 $ 82,799,519 $ New Residual Unit 2 Commercial 45 17.5602083 > 10 Liquid No HAP APCD Control 47,363,088 $ 15,513,824 $ 1,804,500 $ 1,093,500 $ 49,167,588 $ 

Total 6779 TOTALS: $ 2,113,116,609 6,113,166,390 $ 280,738,777 $ 168,266,547 $ 6,393,905,167 $ 
Appendix A-4: Control, Testing and Monitoring Costs for Option 3N at New Area Source Boilers through 2013

Model Unit Sector

Number of Boilers Represented by Model

Design Capacity (mmBtu/hr)

Size Category

Fuel Category Baseline Control

TCI - Control Only ($)

TAC - Control Only ($/yr) TCI - T&M ($) TAC - T&M ($/yr) TOTAL - TCI ($)

TO($/

New Biomass Unit 1 Commercial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 32,014,034 $ 5,314,187 $ 3,999,557 $ 2,006,236 $ 36,013,592 $ 

$ 

New Biomass Unit 2 Industrial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 32,014,034 $ 5,296,718 $ 3,999,557 $ 2,006,236 $ 36,013,592 $ 

$ 

New Biomass Unit 4 Commercial 11 21.0354469 > 10 Biomass Cyclone or Multiclone 9,435,709 $ 1,489,288 $ 628,502 $ 315,266 $ 10,064,211 $ 

$ 

New Biomass Unit 3 Industrial 49 131 > 10 Biomass Electrostatic Precipitator 317,373 $ 140,875 $ 7,975,877 $ 2,611,847 $ 8,293,250 $ 

$ 

New Coal Unit 1 Commercial 62 6.68176984 <= 10 Coal Cyclone or Multiclone 58,804,640 $ 19,965,091 $ 2,759,000 $ 1,779,400 $ 61,563,640 $ 

$ 

New Coal Unit 2 Industrial 93 6.68176984 <= 10 Coal Cyclone or Multiclone 88,206,961 $ 29,947,636 $ 4,138,500 $ 2,669,100 $ 92,345,461 $ 

$ 

New Distillate Unit 1 Commercial 5435 6.76086488 <= 10 Liquid No HAP APCD Control 35,202,495 $ 15,625,625 $ 310,537,062 $ 155,769,885 $ 345,739,557 $ 

$ 

New Distillate Unit 2 Industrial 407 6.76086488 <= 10 Liquid No HAP APCD Control 2,636,139 $ 1,170,125 $ 23,254,569 $ 11,664,829 $ 25,890,708 $ 

$ 

New Distillate Unit 3 Commercial 352 25.3122861 > 10 Liquid No HAP APCD Control 2,279,904 $ 1,012,000 $ 20,112,060 $ 10,088,500 $ 22,391,964 $ 

$ 

New Distillate Unit 4 Industrial 90 25.3122861 > 10 Liquid No HAP APCD Control 582,930 $ 258,750 $ 5,142,288 $ 2,579,446 $ 5,725,218 $ 

$ 

New Residual Unit 1 Commercial 95 5.94997049 <= 10 Liquid No HAP APCD Control 78,990,019 $ 28,173,707 $ 2,422,500 $ 921,500 $ 81,412,519 $ 

$ 

New Residual Unit 2 Commercial 45 17.5602083 > 10 Liquid No HAP APCD Control 47,363,088 $ 15,513,824 $ 1,777,500 $ 1,066,500 $ 49,140,588 $ 

$ 

TOTALS 6779 TOTALS 387,847,327 $ 123,907,827 $ 386,746,973 $ 193,478,745 $ $ 

774,594,300 $ 
Appendix B-1: Emission Reductions from Existing Area Source Boilers

SUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1E Emission REDUCTIONS SUMMARY - Option 2E Emission REDUCTIONS SUMMARY - Option 3E Existing Boilers at Area Sources Existing Boilers at Area Sources Existing Boilers at Area Sources Existing Boilers at Area Fuel Category Pollutant

Baseline Emissions (tpy) Fuel Category Pollutant

Emission Reductions (tpy) Fuel Category Pollutant

Emission Reductions (tpy) Fuel Category Polluta

Biomass Hg 3.44E-01 Biomass Hg 1.19E-01 Biomass Hg 9.13E-02 Biomass Hg 10,958 boilers PM-filterable 76,183 10,958 boilers PM-filterable 40,820 10,958 boilers PM-filterable 28,342 10,958 boilers PM-filt

PM 2.5 23,240 PM 2.5 14,128 PM 2.5 4,645 PM 2.

HCl 2,126 HCl 21 HCl 21 HCl 

Total Hydrocarbons 1,802 Total Hydrocarbons 558 Total Hydrocarbons 428 Total H

VOC 1,034 VOC 320 VOC 246 VOC 

CO 97,695 CO 30,261 CO 23,187 CO 

Dioxins/Furans 2.40E-04 Dioxins/Furans 2.40E-06 Dioxins/Furans 2.40E-06 DioxinHF 59 HF 1 HF 1 HF 

SO2 17,368 SO2 174 SO2 174 SO2 

Non-Hg Metals 956 Non-Hg Metals 245 Non-Hg Metals 179 Non-H

Coal Hg 2 Coal Hg 1 Coal Hg 6.34E-01 Coal Hg 

3,710 boilers PM-filterable 15,388 3,710 boilers PM-filterable 10,713 3,710 boilers PM-filterable 5,351 3,710 boilers PM-filt

PM 2.5 3,017 PM 2.5 1,809 PM 2.5 1,433 PM 2.

HCl 6,784 HCl 68 HCl 68 HCl 

Total Hydrocarbons 250 Total Hydrocarbons 2 Total Hydrocarbons 2 Total H

VOC 144 VOC 1 VOC 1 VOC 

CO 12,465 CO 89 CO 102 CO 

Dioxins/Furans 2.56E-05 Dioxins/Furans 2.56E-07 Dioxins/Furans 2.56E-07 DioxinHF 183 HF 2 HF 2 HF 

SO2 53,031 SO2 530 SO2 530 SO2 

Non-Hg Metals 69 Non-Hg Metals 22 Non-Hg Metals 14 Non-H

Liquid Hg 3 Liquid Hg 0 Liquid Hg 2.52E-02 Liquid Hg 

168,003 boilers PM-filterable 23,243 168,003 boilers PM-filterable 16,484 168,003 boilers PM-filterable 4,485 168,003 boilers PM-filt

PM 2.5 3,416 PM 2.5 2,618 PM 2.5 595 PM 2.

HCl 2,973 HCl 39 HCl 30 HCl 

Total Hydrocarbons 2,557 Total Hydrocarbons 2,626 Total Hydrocarbons 1,118 Total H

VOC 1,468 VOC 1,507 VOC 642 VOC 

CO 20,092 CO 20,640 CO 8,832 CO 

Dioxins/Furans 2.48E-04 Dioxins/Furans 3.22E-06 Dioxins/Furans 2.48E-06 DioxinHF 270 HF 4 HF 3 HF 

SO2 68,541 SO2 891 SO2 685 SO2 

Non-Hg Metals 17,521 Non-Hg Metals 3,966 Non-Hg Metals 2,262 Non-H

TOTAL Hg 5 TOTAL Hg 1 TOTAL Hg 1 TOTAL Hg 

182,671 boilers PM-filterable 114,813 182,671 boilers PM-filterable 68,016 182,671 boilers PM-filterable 38,178 182,671 boilers PM-filt

PM 2.5 29,673 PM 2.5 18,555 PM 2.5 6,674 PM 2.

HCl 11,882 HCl 128 HCl 119 HCl 

Total Hydrocarbons 4,610 Total Hydrocarbons 3,186 Total Hydrocarbons 1,548 Total H

VOC 2,646 VOC 1,829 VOC 889 VOC 

CO 130,252 CO 50,989 CO 32,122 CO 

Dioxins/Furans 5.13E-04 Dioxins/Furans 5.88E-06 Dioxins/Furans 5.13E-06 DioxinHF 513 HF 6 HF 5 HF 

SO2 138,940 SO2 1,595 SO2 1,389 SO2 

Non-Hg Metals 18,547 Non-Hg Metals 4,233 Non-Hg Metals 2,455 Non-H

PROPO
Appendix B-2: Emission Reductions from New Area Source Boilers

SUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1N Emission REDUCTIONS SUMMARY - Option 2N Emission REDUCTIONS SUMMARY - Option 3N NEW Boilers at Area Sources NEW Boilers at Area Sources NEW Boilers at Area Sources NEW Boilers at Area SoFuel Category Pollutant

Baseline Emissions (tpy) Fuel Category Pollutant

Emission Reductions (tpy) Fuel Category Pollutant

Emission Reductions (tpy) Fuel Category Polluta

Biomass Hg 2.56E-02 Biomass Hg 1.75E-02 Biomass Hg 1.52E-02 Biomass Hg 200 boilers PM-filterable 1,578 200 boilers PM-filterable 1,436 200 boilers PM-filterable 621 200 boilers PM-filt

PM 2.5 1,199 PM 2.5 1,091 PM 2.5 472 PM 2.

HCl 159 HCl 2 HCl 2 HCl 

Total Hydrocarbons 365 Total Hydrocarbons 245 Total Hydrocarbons 213 Total H

VOC 209 VOC 141 VOC 122 VOC 

CO 7.29E+03 CO 4.90E+03 CO 4.24E+03 CO Dioxins/Furans 0 Dioxins/Furans 0 Dioxins/Furans 0 Dioxin

HF 4 HF 0 HF 0 HF 

SO2 1,296 SO2 13 SO2 13 SO2 

Non-Hg Metals 18 Non-Hg Metals 16 Non-Hg Metals 7 Non-H

Coal Hg 9.27E-02 Coal Hg 8.53E-02 Coal Hg 9.27E-04 Coal Hg 155 boilers PM-filterable 656 155 boilers PM-filterable 575 155 boilers PM-filterable 7 155 boilers PM-filt

PM 2.5 499 PM 2.5 437 PM 2.5 5 PM 2.

HCl 329 HCl 3 HCl 3 HCl 

Total Hydrocarbons 12 Total Hydrocarbons - Total Hydrocarbons - Total H

VOC 7 VOC - VOC - VOC 

CO 605 CO - CO - CO 

Dioxins/Furans 0 Dioxins/Furans 0 Dioxins/Furans 0 Dioxin

HF 9 HF 0 HF 0 HF 

SO2 2,572 SO2 26 SO2 26 SO2 

Non-Hg Metals 3 Non-Hg Metals 3 Non-Hg Metals 0 Non-H

Liquid Hg 2.82E-01 Liquid Hg 2.48E-01 Liquid Hg 5.76E-02 Liquid Hg 6,424 boilers PM-filterable 2,505 6,424 boilers PM-filterable 2,453 6,424 boilers PM-filterable 632 6,424 boilers PM-filt

PM 2.5 1,904 PM 2.5 1,865 PM 2.5 481 PM 2.

HCl 338 HCl 3 HCl 3 HCl 

Total Hydrocarbons 271 Total Hydrocarbons 260 Total Hydrocarbons 62 Total H

VOC 156 VOC 149 VOC 36 VOC 

CO 2,252 CO 2,159 CO 506 CO 

Dioxins/Furans 0 Dioxins/Furans 0 Dioxins/Furans 0 Dioxin

HF 30 HF 0 HF 0 HF 

SO2 11,148 SO2 111 SO2 111 SO2 

Non-Hg Metals 1,962 Non-Hg Metals 1,940 Non-Hg Metals 451 Non-H

TOTAL Hg 0 TOTAL Hg 0 TOTAL Hg 7.37E-02 TOTAL Hg 

6,779 boilers PM-filterable 4,739 6,779 boilers PM-filterable 4,464 6,779 boilers PM-filterable 1,259 6,779 boilers PM-filt

PM 2.5 3,602 PM 2.5 3,393 PM 2.5 957 PM 2.

HCl 825 HCl 8 HCl 8 HCl 

Total Hydrocarbons 648 Total Hydrocarbons 505 Total Hydrocarbons 274 Total H

VOC 372 VOC 290 VOC 158 VOC 

CO 10,145 CO 7,056 CO 4,750 CO 

Dioxins/Furans 0 Dioxins/Furans 0 Dioxins/Furans 0 Dioxin

HF 44 HF 0 HF 0 HF 

SO2 15,015 SO2 150 SO2 150 SO2 

Non-Hg Metals 1,983 Non-Hg Metals 1,959 Non-Hg Metals 458 Non-H

PROPO
Appendix C-1: Secondary Impacts for Existing Area Source Boilers for Option 3E

Electricity (kWh/yr) Solid Waste (tpy) Electricity (kWh

Biomass Unit 1 56 0.06 <10 Biomass - - 

 

Biomass Unit 2 255 0.28 <10 Biomass - - 

 

Biomass Unit 3 243 0.79 <10 Biomass - - 

 

Biomass Unit 4 5,414 2.46 <10 Biomass - - 

 

Biomass Unit 5 1,524 7.45 <10 Biomass - - 

 

Biomass Unit 6 3,418 21.04 >=10 Biomass - - 

 

Biomass Unit 7 48 131.00 >=10 Biomass - - 

 

Coal Unit 1 184 0.02 <10 Coal - - 

 

Coal Unit 2 153 0.25 <10 Coal - - 

 

Coal Unit 3 117 0.78 <10 Coal - - 

 

Coal Unit 4 2,301 2.26 <10 Coal - - 

 

Coal Unit 5 382 6.68 <10 Coal - - 

 

Coal Unit 6 573 23.49 >=10 Coal 206,017,433 14,309 206,017

 

Distillate Unit 1 6,632 0.06 <10 Liquid - - 

 

Distillate Unit 2 73,548 0.31 <10 Liquid - - 

 

Distillate Unit 3 26,537 0.74 <10 Liquid - - 

 

Distillate Unit 4 41,604 2.47 <10 Liquid - - 

 

Distillate Unit 5 8,392 6.76 <10 Liquid - - 

 

Distillate Unit 6 9,016 25.31 >=10 Liquid - - 

 

Distillate Unit 7 137 173.44 >=10 Liquid - - 

 

Residual Unit 1 21 0.04 <10 Liquid - - 

 

Residual Unit 2 109 0.29 <10 Liquid - - 

 

Residual Unit 3 91 0.74 <10 Liquid - - 

 

Residual Unit 4 1,246 2.68 <10 Liquid - - 

 

Residual Unit 5 594 5.95 <10 Liquid - - 

 

Residual Unit 6 74 17.56 >=10 Liquid - - 

 

Residual Unit 7 2 126.00 >=10 Liquid - - 

 

Totals 206,017

 

Fuel 

Category

Fabric Filter 

Total Energy Savings (mmB

Model Unit

Number of Boilers 

Represented by 

Model

Design 

Capacity 

(mmBtu/hr)

Size 

Category
Appendix C-2: Secondary Impacts for New Area Source Boilers for Option 3N

Electricity (kWh/yr) Solid Waste (tpy) Electricity (kWh/yr) Solid Waste (tpy) Electri

New Biomass Unit 1 70 7.45 <= 10 Biomass - - 2,483,358 557 

 

New Biomass Unit 2 70 7.45 <= 10 Biomass - - 2,483,358 557 

 

New Biomass Unit 4 11 21.04 > 10 Biomass - - 836,003 247 

 

New Biomass Unit 3 49 131.00 > 10 Biomass - - - - 

 

New Coal Unit 1 62 6.68 <= 10 Coal 4,048,641 220 - - 

 

New Coal Unit 2 93 6.68 <= 10 Coal 6,072,962 330 - - 

 

New Distillate Unit 1 5,435 6.76 <= 10 Liquid - - - - 

 

New Distillate Unit 2 407 6.76 <= 10 Liquid - - - - 

 

New Distillate Unit 3 352 25.31 > 10 Liquid - - - - 

 

New Distillate Unit 4 90 25.31 > 10 Liquid - - - - 

 

New Residual Unit 1 95 5.95 <= 10 Liquid 3,594,132 91 - - 

 

New Residual Unit 2 45 17.56 > 10 Liquid 4,038,517 127 - - 

 

Totals 

 

Total Energy Savin

Electrostatic Precipitator

Model Unit

Number of Boilers 

Represented by 

Model

Design 

Capacity 

(mmBtu/hr)

Size 

Category

Fuel 

Category

Fabric Filter 
Appendix D-1: Control, Testing and Monitoring Costs for Option 3N at New Area Source Boilers through 2013 - As displ

Model Unit Sector

Number of Boilers Represented by Model

Design Capacity (mmBtu/hr)

Size Category

Fuel Category Baseline Control

TCI - Control Only ($)

TAC - Control Only ($/yr) TCI - T&M ($) TAC - T

New Biomass Unit 1 Commercial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 12,368,958 $ 2,486,961 $ 3,999,557 $ 2

$ 

New Biomass Unit 2 Industrial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 12,368,958 $ 2,469,492 $ 3,999,557 $ 2

$ 

New Biomass Unit 4 Commercial 11 21.0354469 > 10 Biomass Cyclone or Multiclone 3,511,707 $ 630,059 $ 628,502 $ 

$ 

New Biomass Unit 3 Industrial 49 131 > 10 Biomass Electrostatic Precipitator 317,373 $ 140,875 $ 7,975,877 $ 2

$ 

New Coal Unit 1 Commercial 62 6.68176984 <= 10 Coal Cyclone or Multiclone 58,804,640 $ 19,965,091 $ 2,759,000 $ 1

$ 

New Coal Unit 2 Industrial 93 6.68176984 <= 10 Coal Cyclone or Multiclone 88,206,961 $ 29,947,636 $ 4,138,500 $ 2

$ 

New Distillate Unit 1 Commercial 5435 6.76086488 <= 10 Liquid No HAP APCD Control 35,202,495 $ 15,625,625 $ 310,537,062 $ 155

$ 

New Distillate Unit 2 Industrial 407 6.76086488 <= 10 Liquid No HAP APCD Control 2,636,139 $ 1,170,125 $ 23,254,569 $ 11

$ 

New Distillate Unit 3 Commercial 352 25.3122861 > 10 Liquid No HAP APCD Control 2,279,904 $ 1,012,000 $ 20,112,060 $ 10

$ 

New Distillate Unit 4 Industrial 90 25.3122861 > 10 Liquid No HAP APCD Control 582,930 $ 258,750 $ 5,142,288 $ 2

$ 

New Residual Unit 1 Commercial 95 5.94997049 <= 10 Liquid No HAP APCD Control 78,990,019 $ 28,173,707 $ 2,422,500 $ 

$ 

New Residual Unit 2 Commercial 45 17.5602083 > 10 Liquid No HAP APCD Control 47,363,088 $ 15,513,824 $ 1,777,500 $ 1

$ 

TOTALS 6779 TOTALS 342,633,171 $ 117,394,145 $ 386,746,973 $ 193

$ 
Appendix D-2: Emission Reductions from New Area Source Boilers - As Displayed in RIA/Preamble

SUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1N Emission REDUCTIONS SUMMARY - Option 2N Emission REDUCTIONS SUMMARY - Option 3N NEW Boilers at Area Sources NEW Boilers at Area Sources NEW Boilers at Area Sources NEW Boilers at Area SoFuel Category Pollutant

Baseline Emissions (tpy) Fuel Category Pollutant

Emission Reductions (tpy) Fuel Category Pollutant

Emission Reductions (tpy) Fuel Category Polluta

Biomass Hg 2.56E-02 Biomass Hg 1.75E-02 Biomass Hg 1.52E-02 Biomass Hg 200 boilers PM-filterable 2,858 200 boilers PM-filterable 2,715 200 boilers PM-filterable 1,900 200 boilers PM-filt

PM 2.5 2,172 PM 2.5 2,063 PM 2.5 1,444 PM 2.

HCl 159 HCl 2 HCl 2 HCl 

Total Hydrocarbons 365 Total Hydrocarbons 245 Total Hydrocarbons 213 Total H

VOC 209 VOC 141 VOC 122 VOC 

CO 7.29E+03 CO 4.90E+03 CO 4.24E+03 CO Dioxins/Furans 0 Dioxins/Furans 0 Dioxins/Furans 0 Dioxin

HF 4 HF 0 HF 0 HF 

SO2 1,296 SO2 13 SO2 13 SO2 

Non-Hg Metals 18 Non-Hg Metals 17 Non-Hg Metals 8 Non-H

Coal Hg 9.27E-02 Coal Hg 8.53E-02 Coal Hg 9.27E-04 Coal Hg 155 boilers PM-filterable 656 155 boilers PM-filterable 575 155 boilers PM-filterable 7 155 boilers PM-filt

PM 2.5 499 PM 2.5 437 PM 2.5 5 PM 2.

HCl 329 HCl 3 HCl 3 HCl 

Total Hydrocarbons 12 Total Hydrocarbons - Total Hydrocarbons - Total H

VOC 7 VOC - VOC - VOC 

CO 605 CO - CO - CO 

Dioxins/Furans 0 Dioxins/Furans 0 Dioxins/Furans 0 Dioxin

HF 9 HF 0 HF 0 HF 

SO2 2,572 SO2 26 SO2 26 SO2 

Non-Hg Metals 3 Non-Hg Metals 3 Non-Hg Metals 0 Non-H

Liquid Hg 2.82E-01 Liquid Hg 2.48E-01 Liquid Hg 5.76E-02 Liquid Hg 6,424 boilers PM-filterable 2,505 6,424 boilers PM-filterable 2,453 6,424 boilers PM-filterable 632 6,424 boilers PM-filt

PM 2.5 1,904 PM 2.5 1,865 PM 2.5 481 PM 2.

HCl 338 HCl 3 HCl 3 HCl 

Total Hydrocarbons 271 Total Hydrocarbons 260 Total Hydrocarbons 62 Total H

VOC 156 VOC 149 VOC 36 VOC 

CO 2,252 CO 2,159 CO 506 CO 

Dioxins/Furans 0 Dioxins/Furans 0 Dioxins/Furans 0 Dioxin

HF 30 HF 0 HF 0 HF 

SO2 11,148 SO2 111 SO2 111 SO2 

Non-Hg Metals 1,962 Non-Hg Metals 1,940 Non-Hg Metals 451 Non-H

TOTAL Hg 0 TOTAL Hg 0 TOTAL Hg 7.37E-02 TOTAL Hg 

6,779 boilers PM-filterable 6,018 6,779 boilers PM-filterable 5,743 6,779 boilers PM-filterable 2,539 6,779 boilers PM-filt

PM 2.5 4,574 PM 2.5 4,365 PM 2.5 1,929 PM 2.

HCl 825 HCl 8 HCl 8 HCl 

Total Hydrocarbons 648 Total Hydrocarbons 505 Total Hydrocarbons 274 Total H

VOC 372 VOC 290 VOC 158 VOC 

CO 10,145 CO 7,056 CO 4,750 CO 

Dioxins/Furans 0 Dioxins/Furans 0 Dioxins/Furans 0 Dioxin

HF 44 HF 0 HF 0 HF 

SO2 15,015 SO2 150 SO2 150 SO2 

Non-Hg Metals 1,983 Non-Hg Metals 1,960 Non-Hg Metals 459 Non-H

PROPO
Appendix D-3: Secondary Impacts for New Area Source Boilers for Option 3N - As Displayed in RIA/Preamble

Electricity (kWh/yr) Solid Waste (tpy) Electricity (kWh/yr) Solid Waste (tpy) Electri

New Biomass Unit 1 70 7.45 <= 10 Biomass - - 1,905,866 403 

 

New Biomass Unit 2 70 7.45 <= 10 Biomass - - 1,905,866 403 

 

New Biomass Unit 4 11 21.04 > 10 Biomass - - 579,630 179 

 

New Biomass Unit 3 49 131.00 > 10 Biomass - - - - 

 

New Coal Unit 1 62 6.68 <= 10 Coal 4,048,641 220 - - 

 

New Coal Unit 2 93 6.68 <= 10 Coal 6,072,962 330 - - 

 

New Distillate Unit 1 5,435 6.76 <= 10 Liquid - - - - 

 

New Distillate Unit 2 407 6.76 <= 10 Liquid - - - - 

 

New Distillate Unit 3 352 25.31 > 10 Liquid - - - - 

 

New Distillate Unit 4 90 25.31 > 10 Liquid - - - - 

 

New Residual Unit 1 95 5.95 <= 10 Liquid 3,594,132 91 - - 

 

New Residual Unit 2 45 17.56 > 10 Liquid 4,038,517 127 - - 

 

Totals 

 

Total Energy Savin

Electrostatic Precipitator

Model Unit

Number of Boilers 

Represented by 

Model

Design 

Capacity 

(mmBtu/hr)

Size 

Category

Fuel 

Category

Fabric Filter