# 1 MEMORANDUM



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

FROM: Graham Gibson, Susan McClut chey, and Amanda Singleton, ERG

DATE: April 2010

SUBJECT: Methodology for Estimating Impacts fr om Industrial, Commercial, Institutional

Boilers at Area Sources of H azardous Air Pollutant Emissions



# 1.0 INTRODUCTION

The purpose of this memorandum is to disc uss the methodology used to estimate the

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

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

existing units and new units projected to be ope rational 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 ach ievable control technol ogy (MACT) floor and

Generally Achievable Control Technology (GACT) le vel of control, projection of new units, and

a detailed description of the cost equations used to estimate cost s 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

# 2 

# 2.0 OVERVIEW OF REGULATORY OPTIONS

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

description of the three op tions is described below.



# 2.1 Existing Units

 Option 1E represents the option where all boilers, rega rdless 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 stan dard of a biennial tune -up. All facilities are required to conduct an energy audit.

 Option 3E represents the primary proposed opt ion 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. A ll 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 pol lutants, but are required to meet a work practice standard of a bienni al tune-up. There are no numeri cal 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 thre e options is described below.

 Option 1N represents the option where all boilers, rega rdless 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 Boile rs (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.

# 3  Option 3N represents the primary proposed opt ion 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 ba seline emissions for the model unit exceeded the

MACT floor emission limit applicable to each m odel. A detailed descripti on of the three options

is described below. A summary table compari ng the overall capital a nd annualized costs of

option 3E for existing units and op tion 3N for new units is presen ted in Table 1. The equations

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

memorandum. 3 

# The following logic was used to apply c ontrol, testing, and m onitoring 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 we re found to be greater than the MACT floor,

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

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

meeting the MACT floor for Hg was estimated. Fo r 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 estima ted 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 wa s 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

# 4 that would require a fabric filt er 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 instal ling 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 desi gned 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% O 2 

# . The combustor design of the boilers in the area

source inventory is not known and this impacts an alysis 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 inventor y. The baseline emissions for ar ea source boilers in all fuel

categories are less than 400 ppm, and so it is a ssumed that combustion co ntrols, either a basic

tune-up or a more advanced burner replacemen t 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 calcu late the MACT floor for CO, 29 percent of

units burning coal are meeting the MACT floor a nd 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 fl oor emission limits, and so 72 percent of the

units are estimated to install a linkageless boile r 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 pr oposed CO limit overtime.

# 5 Particulate Matter Control

For all units that were not expected to insta ll a fabric filter for me rcury control, the cost

impacts analysis for this option assumes that th e 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 in stall 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 de sign 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 stac k tests for these three pollutants was estimated

to be $15,000 per year. Boilers greater than 100 mmB tu/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 e xpected 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 fu el analyses received from a fu el supplier for chlorine and Hg.

Conducting stack tests for PM and CO was estim ated 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 analys is for Hg was estimated to be $8,600 per year.

Although solid fuels are eligible to comply with the proposed rule thr ough fuel analysis in lieu of

stack testing, when the mercury content of the fu el is below the MACT floor emission limit, this

cost estimate conservatively assumed that only un its designed to fire liquid fuels would use this

compliance alternative. The methods and data s ources used to estimate testing and monitoring

# 6 costs are discussed in other memoranda. 3



# Monitoring Costs

Various monitor configurations were inst alled based on the size of the unit and the

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

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

monitor was included in the cost analysis. For units greater than 100 mm Btu/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 condu ct an annual tune-up or energy audit. The

Department of Energy has conducted energy assessm ents at selected manuf acturing facilities and

reports that facilities can redu ce fuel/energy use by 10 to 15 per cent by using best practices to

increase their energy efficiency. Many best practices are consider ed pollution prevention

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

emissions from the fuel combustion. Further boil er 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 combus tion controls such as upgrading burners and

installation of an LBMS are also expected to improve the effici ency 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 * Op hours 

# * EG (Equation 1)

Where: DC = unit design capacity (mmBtu/hr) Op hours 

# = 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 fu el oil, and #6 residual fuel oil were obtained from the EIA. 3 

# The

# 7 EIA data reported fuel prices as $/ton for co al, 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, th e model units were distributed to an industrial or commercial

sector, and then the appropriate fuel price wa s 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 fo r units in the biomass fuel cate gory 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 sma ll 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 sma ll units. Option 2E also includes the cost of

an energy audit at every area source facility, appr oximately 91,339 facilities. As discussed in the

memorandum for Estimating Control Costs from Ma jor 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 institu tional and commercial-scale audits. 4 

# The facility’s

classification of either an industr ial or commercial facility was a ssigned using the distribution of

SIC codes in the 13-state boiler inspector inve ntory. 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 devi ce and testing/monitoring cost estimation

for mercury and CO from large coal units. As me ntioned in option 1E, 56 percent of large coal

units, or 321 boilers are expected to install a fabr ic filter in order to meet the mercury limit. In

addition, 29 percent of large coal units are expected to install a dvanced 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 combus tion 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 mercur y, as well as a bag leak detection system for the

# 8 321 boilers that are expected to install a fabric filter. Ther e are no proposed numerical PM

emission limits under this option, and so no additio nal 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 ar e not subject to nume rical 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. Th is cost impacts analysis estimates that all the biomass and

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

units must also conduct testing and monitoring acti vities 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 co st impacts analysis does not

include any additional testing and monito ring requirements for these small boilers.

Finally, option 3E proposes that all facilities with large boilers c onduct 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 N SPS 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 ES P 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 a ll liquid boilers greater than 30 will have an FF

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

# 9 Mercury Control

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

proposed rule. Where baseline mercury emissions we re found to be greater than the MACT floor,

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

All new boilers, regardless of size or fuel, were exp ected to install a fabric filter in order to meet

the mercury limits under this option. Compari ng 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 e qual 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 th e CO numeric emission limit for all sizes and

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

for new boilers. As mentioned under 1E, the contro l 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 inst all 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 estima ted 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 de sign 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 stac k tests for these three pollutants was estimated

# 10 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 e xpected 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 fu el analyses received from a fu el supplier for chlorine and Hg.

Conducting stack tests for PM and CO was estim ated 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 analys is for Hg was estimated to be $8,600 per year.

Although solid fuels are eligible to comply with the proposed rule thr ough fuel analysis in lieu of

stack testing, when the mercury content of the fu el is below the MACT floor emission limit, this

cost estimate conservatively assumed that only un its designed to fire liquid fuels would use this

compliance alternative. The methods and data s ources used to estimate testing and monitoring

costs are discussed in other memoranda. 3



# Monitoring Costs

Various monitor configurations were inst alled based on the size of the unit and the

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

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

monitor was included in the cost analysis. For units greater than 100 mm Btu/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 sma ll 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

# 11 

# 3.5 Option 3N

The proposed option 3N includes identical re quirement for coal units as outlined under

option 1N. Under option 3N liquid and biomass bo ilers are not subject to numerical emission

limits for mercury and there are no co sts included in the impacts analysis to install fabric filters

for mercury control or conduct mercury fuel analys is 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 m onitoring activities for CO to demonstrate

compliance with the numerical emission limits.

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

boilers, based on the NSPS limits app licable to each of these categor ies. Since all coal units are

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

lb/mmBtu without any additional control requi rements. 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 alre ady subject to this limit under the NSPS, this

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

PM limit for liquids is also 0.03 lb/mmBtu. Base d on the calculated aver age baseline emission

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



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

Under option 3N, all boilers le ss 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 test ing costs under the NSPS. Coal boi lers 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 existi ng boilers and option 3N is the proposed

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

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

summarizes the costs of the proposed option for new and existing boile rs at area sources of HAP.

Appendix A of this memorandum provides a detaile d summary of the costs for each model unit.

# 12 Table 1: Summary of Costs of Proposed Options

Costs shown in $10 6 

# (2008) with capital reco very 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 facilitie s 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 ba seline emissions based on the calculated

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

subcategory. The development of area source mode l 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 ca lculated on a ton per year basis. Emission

reductions of Hg and CO were calculated by subtra cting the baseline emissi ons assigned to each

model unit from the MACT floor (or GACT) emi ssion 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 f ilter to meet the mercury MACT floor emission

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

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

# 13 filter, the baseline emissions assigned to each m odel boiler were subtracted from the calculated

average baseline emission factor co rresponding to a fabric fi lter 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 calc ulated 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 exp ected to install a multiclone

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

control efficiency of a multicl one, a 75 percent reduction. These c ontrol 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 alre ady have a multiclone in stalled 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 pe rcent 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 lim it, a 10 percent reduction was estimated for nonmercury metallic HAP.

PM2.5 emissions comprise a fraction of tota l 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 m odel boiler, the emission reductions for PM

were multiplied by the applicable PM2.5 fraction.

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

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

# 14 efficiency was estimated, resulting in an es timated one percent emissions reduction of all

pollutants. Efficiency gains reduce fuel use, a nd 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 emissi on rate on a heat input basis to an annual

emission rate, Equation 2 was used:

Annual Emission Rate (tpy) = ER HI 

# * 0.0005 * Op hours 

# * CF (Equation 2)

Where:

ER HI 

# = emission rate (lb/mmBtu) 0.0005 = conversion factor, lbs per ton Op hours 

# = 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 concen tration basis to an annual emission rate,

Equations 3 and 4 were used:

Annual Emission Rate (tpy) = ER C 

# * 0.000001 * ρ air 

# * Q S 

# * 60 * Op hours 

# * 0.0005 * (20.946 – O 2 

# ) / (20.946 – Std O 2 

# ) * CF (Equation 3)

Where:

ER C 

# = emission concentration (ppm @ 3% O 2 

# ) 0.000001 = conversion factor, ppm to parts

ρ air 

# = density of air, 0.0749 lb/dscf Q S 

# = exhaust flowrate (dscfm) 60 = conversion factor, minutes to hours Op hours 

# = annual operating hours reported in 2008 survey (hours/year) 0.0005 = conversion factor, lb per ton 20.946 = percentage of oxygen in ambient air

O 2 

# = percentage of oxygen assumed in exhaust gas

Std. O 2 

# = 3 percent oxygen in standardized em ission concentration for proposed rule. CF = annual average capacity factor, 0.5 for liquid and 0.65 for coal and biomass

Annual Emission Rate (tpy) = ER C 

# * 0.0283 * Q S 

# * 60 * Op hours 

# * 0.000000001 * 0.0022 * 0.0005 * (20.946 – O 2 

# ) / (20.946 – Std O 2 

# ) * CF (Equation 4)

Where:

ER C 

# = emission concentration (ng/dscm @ 7% O 2 

# ) 0.0283 = conversion factor, dscm to dscf Q S 

# = exhaust flowrate (dscfm) 60 = conversion factor, minutes to hours Op hours 

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

# 15 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

O 2 

# = percentage of oxygen assumed in exhaust gas

Std O 2 

# = 7 percent oxygen in standardized em ission 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 em ission 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 estima ting emission reductions for option 1E were

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

one percent gain in efficiency expected from th e 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 numeri cal emission limits for PM or H g. Instead, a similar one percent

gain in efficiency is expected to occur as a result of conducting an a nnual 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 wa s 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 cons umption projections from the EIA and a

history of boiler installation da tes in the boiler inspector i nventory, 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 aver age (mean) design capacity of area source boilers

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

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

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

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

and results of the baseline emissions an alysis 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/h r 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 mm Btu/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 li quid fuels were expected to install a fabric

filter. All new boilers less than 30 mmBtu/hr w ould 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 a nd 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 cont rol was determined for each model unit, an

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

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

and SO2 limits for new solid- and liquid-fired co mbustion 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 as suming 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 us ed to estimate the reductions for new units.

# 17 Emission Reductions for Option 3N

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

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

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

emission factor representing uncontro lled units. Since an ESP is not expected to be very effective

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

estimated based on a one percent efficiency im provement, 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 comp liance 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 filt er is effective at captu ring 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 base d on a one percent efficiency improvement,

resulting from annual tune-ups or other combus tion 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 Ener gy 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 refe rences of a 10 to 15 percent improvement in

efficiency, a range of incremental emission re ductions was estimated considering efficiency

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

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

identify the potential for additi onal emission reductions if the fi ndings of an energy audit were

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

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

payback. The fuel savings were estimated using E quation 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 estim ated incremental emission reduction and fuel

savings is shown in Table 3.

A summary of the estimated emission reduc tions 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 op tions 1N, 2N, and the proposed

option 3N are located in Appendix B-2

.

# 19 Table 3 Emission Reductions and Energy Savings Resultin g from Implementing Cost Effective Findings of an Energy Audit at Facilities with Large ( ≥ 10 mmBtu/hr) Boilers

Assuming a Five Percent Efficiency Ga in 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 el ectricity required to operate air pollution

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

controls or work practices re quired 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 ne w 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 sec ondary 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 exceed ed 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 an d fly ash in fabric filters or ESP control

devices. Solid waste impacts were estimated for ev ery unit expected to inst all 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 es timate the solid waste contribution from each of

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

model unit. The calculations used to estimate each variable and the qua ntity 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 particulat e matter to the control device (g r/acfm); operating hours (hr/year)

and the efficiency of the contro l 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 me rcury. The calculation required the use of three

variables, including: ex haust 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 opera te a control device was calculated for an

electrostatic precipitator and fabric filter. Th ese 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 addi tional calculations were necessary. For some

units, an electrical demand from multiple c ontrol 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 calcul ated based on characteristics assigned to each

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

electricity demand to operate the control de vices 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 pa yback can improvements in efficiency, thereby

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

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

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

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

# 22 gains in efficiency from each of these work pr actice standards is difficult, and may depend on the

baseline operating efficiency of each unit.

Section 3.1 discusses the fuel sa vings impacts in terms of annu alized 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 refl ect the savings from bo ilers 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 fo r new units are both described in detail in

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

3E, the waste and electricity impacts were only as sessed for large units (those greater than or

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

electricity were not assessed fo r the liquid and biomass subcategor ies because these boilers were

not subject to PM or Hg nume rical 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 co mbustion 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 im pacts 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 anal ysis that were inco rrectly based on the PM NSPS limits for

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

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

values used in the RIA. The cost, emission, and s econdary 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 exp ected to be needed for new biomass boilers.



# 7.0 REFERENCES

1. Singleton, A., ERG. MACT Floor Analysis fo r the Industrial, Comm ercial, Institutional

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

2010.

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

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

3. Singleton, A., ERG. Methodology for Estimating Control Costs for Industrial, Commercial, Institutional Boilers Nationa l 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 Pro cess Heaters National Emission Standards for Hazardous Air Pollutants – Major Source. April, 2010.

5. Gibson, G. and A. Singleton, ERG. Devel opment of Baseline Emission Factors for Boilers and Process Heaters at Commercial, Indu strial and Institutional Facilities. April,

2010.

6. Singleton, A., ERG. Methodology for Devel oping Model Units for Industrial, Commercial, and Institutional Boilers Nati onal Emission Standards for Hazardous Air Pollutants – Area Source. April, 2010.

7. U.S. Department of Energy. Energy Inform ation 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 Conserva tion Among Industrial Boilers. July 2002. Located

online at http://www.delta-institute.org/publ ications/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 4 5,222,285 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 3,267,404 142,6 75,975 132,026,007 10,649,968

81 - - - - - - - 82 68,103 198,885,995 578,352,776 34,052 1,278,438 200,1 64,433 103,865,356 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)

T O TAL 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 co mbustion controls
or a tune-up.Appendix A-3: Control, Testing and Monitoring Costs for Option 1N at New Area Source BoilersModel Unit SectorNumber ofBoilersRepresentedby ModelDesignCapacity(mmBtu/hr)SizeCategoryFuelCategory Baseline ControlTCI - Control Only($)TAC - Control Only($/yr) TCI - T&M ($) TAC - T&M ($/yr) TOTAL - TCI ($)TOTAL - TAC($/yr)Fuel Savings($/yr)Total TACConsidering FuelSavings ($/yr)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$ 24,118,735$ -$ 24,118,735$New Biomass Unit 2 Industrial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 64,340,788$ 22,109,735$ 3,115,000$ 2,009,000$ 67,455,788$ 24,118,735$ -$ 24,118,735$New Biomass Unit 4 Commercial 11 21.0354469 > 10 Biomass Cyclone or Multiclone 14,143,051$ 4,356,757$ 489,500$ 315,700$ 14,632,551$ 4,672,457$ -$ 4,672,457$New Biomass Unit 3 Industrial 49 131 > 10 Biomass Electrostatic Precipitator 209,047,426$ 51,241,589$ 9,519,377$ 3,381,147$ 218,566,803$ 54,622,736$ -$ 54,622,736$New Coal Unit 1 Commercial 62 6.68176984 <= 10 Coal Cyclone or Multiclone 58,804,640$ 19,965,091$ 2,759,000$ 1,779,400$ 61,563,640$ 21,744,491$ 57,436$ 21,687,055$New Coal Unit 2 Industrial 93 6.68176984 <= 10 Coal Cyclone or Multiclone 88,206,961$ 29,947,636$ 4,138,500$ 2,669,100$ 92,345,461$ 32,616,736$ 86,154$ 32,530,583$New Distillate Unit 1 Commercial 5435 6.76086488 <= 10 Liquid No HAP APCD Control 4,610,126,467$ 1,630,788,657$ 217,943,500$ 132,070,500$ 4,828,069,967$ 1,762,859,157$ 36,469,072$ 1,726,390,085$New Distillate Unit 2 Industrial 407 6.76086488 <= 10 Liquid No HAP APCD Control 345,229,342$ 122,121,616$ 16,320,700$ 9,890,100$ 361,550,042$ 132,011,716$ 2,799,982$ 129,211,734$New Distillate Unit 3 Commercial 352 25.3122861 > 10 Liquid No HAP APCD Control 424,131,187$ 132,826,851$ 14,115,200$ 8,553,600$ 438,246,387$ 141,380,451$ 8,842,945$ 132,537,505$New Distillate Unit 4 Industrial 90 25.3122861 > 10 Liquid No HAP APCD Control 108,442,633$ 33,961,411$ 3,609,000$ 2,187,000$ 112,051,633$ 36,148,411$ 2,318,101$ 33,830,309$New Residual Unit 1 Commercial 95 5.94997049 <= 10 Liquid No HAP APCD Control 78,990,019$ 28,173,707$ 3,809,500$ 2,308,500$ 82,799,519$ 30,482,207$ 320,861$ 30,161,346$New Residual Unit 2 Commercial 45 17.5602083 > 10 Liquid No HAP APCD Control 47,363,088$ 15,513,824$ 1,804,500$ 1,093,500$ 49,167,588$ 16,607,324$ 448,561$ 16,158,763$Total 6779TOTALS:6,113,166,390$ 2,113,116,609$ 280,738,777$ 168,266,547$ 6,393,905,167$ 2,281,383,156$51,343,112$ 2,230,040,044$Appendix A-4: Control, Testing and Monitoring Costs for Option 3N at New Area Source Boilers through 2013Model Unit SectorNumber ofBoilersRepresentedby ModelDesignCapacity(mmBtu/hr)SizeCategoryFuelCategory Baseline ControlTCI - ControlOnly ($)TAC - ControlOnly ($/yr) TCI - T&M ($) TAC - T&M ($/yr) TOTAL - TCI ($)TOTAL - TAC($/yr)Fuel Savings($/yr)Total TACConsidering FuelSavings ($/yr)New Biomass Unit 1 Commercial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 32,014,034$ 5,314,187$ 3,999,557$ 2,006,236$ 36,013,592$ 7,320,423$ -$ 7,320,423$New Biomass Unit 2 Industrial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 32,014,034$ 5,296,718$ 3,999,557$ 2,006,236$ 36,013,592$ 7,302,954$ -$ 7,302,954$New Biomass Unit 4 Commercial 11 21.0354469 > 10 Biomass Cyclone or Multiclone 9,435,709$ 1,489,288$ 628,502$ 315,266$ 10,064,211$ 1,804,554$ -$ 1,804,554$New Biomass Unit 3 Industrial 49 131 > 10 Biomass Electrostatic Precipitator 317,373$ 140,875$ 7,975,877$ 2,611,847$ 8,293,250$ 2,752,722$ -$ 2,752,722$New Coal Unit 1 Commercial 62 6.68176984 <= 10 Coal Cyclone or Multiclone 58,804,640$ 19,965,091$ 2,759,000$ 1,779,400$ 61,563,640$ 21,744,491$ 57,436$ 21,687,055$New Coal Unit 2 Industrial 93 6.68176984 <= 10 Coal Cyclone or Multiclone 88,206,961$ 29,947,636$ 4,138,500$ 2,669,100$ 92,345,461$ 32,616,736$ 86,154$ 32,530,583$New Distillate Unit 1 Commercial 5435 6.76086488 <= 10 Liquid No HAP APCD Control 35,202,495$ 15,625,625$ 310,537,062$ 155,769,885$ 345,739,557$ 171,395,510$ 36,469,072$ 134,926,438$New Distillate Unit 2 Industrial 407 6.76086488 <= 10 Liquid No HAP APCD Control 2,636,139$ 1,170,125$ 23,254,569$ 11,664,829$ 25,890,708$ 12,834,954$ 2,799,982$ 10,034,972$New Distillate Unit 3 Commercial 352 25.3122861 > 10 Liquid No HAP APCD Control 2,279,904$ 1,012,000$ 20,112,060$ 10,088,500$ 22,391,964$ 11,100,500$ 8,842,945$ 2,257,555$New Distillate Unit 4 Industrial 90 25.3122861 > 10 Liquid No HAP APCD Control 582,930$ 258,750$ 5,142,288$ 2,579,446$ 5,725,218$ 2,838,196$ 2,318,101$ 520,095$New Residual Unit 1 Commercial 95 5.94997049 <= 10 Liquid No HAP APCD Control 78,990,019$ 28,173,707$ 2,422,500$ 921,500$ 81,412,519$ 29,095,207$ 320,861$ 28,774,346$New Residual Unit 2 Commercial 45 17.5602083 > 10 Liquid No HAP APCD Control 47,363,088$ 15,513,824$ 1,777,500$ 1,066,500$ 49,140,588$ 16,580,324$ 448,561$ 16,131,763$TOTALS 6779 TOTALS 387,847,327$ 123,907,827$ 386,746,973$ 193,478,745$774,594,300$ 317,386,572$ 51,343,112$ 266,043,460$Appendix B-1: Emission Reductions from Existing Area Source BoilersSUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1E Emission REDUCTIONS SUMMARY - Option 2E Emission REDUCTIONS SUMMARY- Option 3E Emission REDUCTIONSExisting Boilers at Area Sources Existing Boilers at Area Sources Existing Boilers at Area Sources Existing Boilers at Area SourcesFuel Category PollutantBaselineEmissions(tpy) Fuel Category PollutantEmissionReductions(tpy) Fuel Category PollutantEmissionReductions(tpy) Fuel Category PollutantEmissionReductions(tpy)Biomass Hg 3.44E-01 Biomass Hg 1.19E-01 Biomass Hg 9.13E-02 Biomass Hg 3.44E-0310,958 boilers PM-filterable 76,18310,958 boilers PM-filterable 40,82010,958 boilers PM-filterable 28,34210,958 boilers PM-filterable 762PM 2.5 23,240PM 2.5 14,128PM 2.5 4,645PM 2.5 232HCl 2,126HCl 21HCl 21HCl 21Total Hydrocarbons 1,802Total Hydrocarbons 558Total Hydrocarbons 428Total Hydrocarbons 428VOC 1,034VOC 320VOC 246VOC 246CO 97,695CO 30,261CO 23,187CO 23,187Dioxins/Furans 2.40E-04 Dioxins/Furans 2.40E-06 Dioxins/Furans 2.40E-06 Dioxins/Furans 2.40E-06HF 59HF 1HF 1HF 1SO2 17,368SO2 174SO2 174SO2 174Non-Hg Metals 956Non-Hg Metals 245Non-Hg Metals 179Non-Hg Metals 10Coal Hg 2Coal Hg 1Coal Hg 6.34E-01 Coal Hg 6.34E-013,710 boilers PM-filterable 15,3883,710 boilers PM-filterable 10,7133,710 boilers PM-filterable 5,3513,710 boilers PM-filterable 5,353PM 2.5 3,017PM 2.5 1,809PM 2.5 1,433PM 2.5 1,434HCl 6,784HCl 68HCl 68HCl 68Total Hydrocarbons 250Total Hydrocarbons 2Total Hydrocarbons 2Total Hydrocarbons 2VOC 144VOC 1VOC 1VOC 1CO 12,465CO 89CO 102CO 102Dioxins/Furans 2.56E-05 Dioxins/Furans 2.56E-07 Dioxins/Furans 2.56E-07 Dioxins/Furans 2.56E-07HF 183HF 2HF 2HF 2SO2 53,031SO2 530SO2 530SO2 530Non-Hg Metals 69Non-Hg Metals 22Non-Hg Metals 14Non-Hg Metals 24Liquid Hg 3Liquid Hg 0Liquid Hg 2.52E-02 Liquid Hg 2.52E-02168,003 boilers PM-filterable 23,243168,003 boilers PM-filterable 16,484168,003 boilers PM-filterable 4,485168,003 boilers PM-filterable 232PM 2.5 3,416PM 2.5 2,618PM 2.5 595PM 2.5 34HCl 2,973HCl 39HCl 30HCl 30Total Hydrocarbons 2,557Total Hydrocarbons 2,626Total Hydrocarbons 1,118Total Hydrocarbons 1,118VOC 1,468VOC 1,507VOC 642VOC 642CO 20,092CO 20,640CO 8,832CO 8,832Dioxins/Furans 2.48E-04 Dioxins/Furans 3.22E-06 Dioxins/Furans 2.48E-06 Dioxins/Furans 2.48E-06HF 270HF 4HF 3HF 3SO2 68,541SO2 891SO2 685SO2 685Non-Hg Metals 17,521Non-Hg Metals 3,966Non-Hg Metals 2,262Non-Hg Metals 175TOTAL Hg 5TOTAL Hg 1TOTAL Hg 1TOTAL Hg 1182,671 boilers PM-filterable 114,813182,671 boilers PM-filterable 68,016182,671 boilers PM-filterable 38,178182,671 boilers PM-filterable 6,348PM 2.5 29,673PM 2.5 18,555PM 2.5 6,674PM 2.5 1,701HCl 11,882HCl 128HCl 119HCl 119Total Hydrocarbons 4,610Total Hydrocarbons 3,186Total Hydrocarbons 1,548Total Hydrocarbons 1,548VOC 2,646VOC 1,829VOC 889VOC 889CO 130,252CO 50,989CO 32,122CO 32,122Dioxins/Furans 5.13E-04 Dioxins/Furans 5.88E-06 Dioxins/Furans 5.13E-06 Dioxins/Furans 5.13E-06HF 513HF 6HF 5HF 5SO2 138,940SO2 1,595SO2 1,389SO2 1,389Non-Hg Metals 18,547Non-Hg Metals 4,233Non-Hg Metals 2,455Non-Hg Metals 209PROPOSED OPTIONAppendix B-2: Emission Reductions from New Area Source BoilersSUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1N Emission REDUCTIONS SUMMARY - Option 2N Emission REDUCTIONS SUMMARY- Option 3N Emission REDUCTIONSNEW Boilers at Area Sources NEW Boilers at Area Sources NEW Boilers at Area Sources NEW Boilers at Area SourcesFuel Category PollutantBaselineEmissions(tpy) Fuel Category PollutantEmissionReductions(tpy) Fuel Category PollutantEmissionReductions(tpy) Fuel Category PollutantEmissionReductions(tpy)Biomass Hg 2.56E-02 Biomass Hg 1.75E-02 Biomass Hg 1.52E-02 Biomass Hg 2.56E-04200 boilers PM-filterable 1,578200 boilers PM-filterable 1,436200 boilers PM-filterable 621200 boilers PM-filterable 927PM 2.5 1,199PM 2.5 1,091PM 2.5 472PM 2.5 704HCl 159HCl 2HCl 2HCl 2Total Hydrocarbons 365Total Hydrocarbons 245Total Hydrocarbons 213Total Hydrocarbons 245VOC 209VOC 141VOC 122VOC 141CO 7.29E+03 CO 4.90E+03 CO 4.24E+03 CO 4.90E+03Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0HF 4HF 0HF 0HF 0SO2 1,296SO2 13SO2 13SO2 13Non-Hg Metals 18Non-Hg Metals 16Non-Hg Metals 7Non-Hg Metals 11Coal Hg 9.27E-02 Coal Hg 8.53E-02 Coal Hg 9.27E-04 Coal Hg 8.53E-02155 boilers PM-filterable 656155 boilers PM-filterable 575155 boilers PM-filterable 7155 boilers PM-filterable 568PM 2.5 499PM 2.5 437PM 2.5 5PM 2.5 431HCl 329HCl 3HCl 3HCl 3Total Hydrocarbons 12Total Hydrocarbons -Total Hydrocarbons -Total Hydrocarbons -VOC 7VOC -VOC -VOC -CO 605CO -CO -CO -Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0HF 9HF 0HF 0HF 0SO2 2,572SO2 26SO2 26SO2 26Non-Hg Metals 3Non-Hg Metals 3Non-Hg Metals 0Non-Hg Metals 3Liquid Hg 2.82E-01 Liquid Hg 2.48E-01 Liquid Hg 5.76E-02 Liquid Hg 4.94E-036,424 boilers PM-filterable 2,5056,424 boilers PM-filterable 2,4536,424 boilers PM-filterable 6326,424 boilers PM-filterable 162PM 2.5 1,904PM 2.5 1,865PM 2.5 481PM 2.5 123HCl 338HCl 3HCl 3HCl 3Total Hydrocarbons 271Total Hydrocarbons 260Total Hydrocarbons 62Total Hydrocarbons 260VOC 156VOC 149VOC 36VOC 149CO 2,252CO 2,159CO 506CO 2,159Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0HF 30HF 0HF 0HF 0SO2 11,148SO2 111SO2 111SO2 111Non-Hg Metals 1,962Non-Hg Metals 1,940Non-Hg Metals 451Non-Hg Metals 35TOTAL Hg 0TOTAL Hg 0TOTAL Hg 7.37E-02 TOTAL Hg 9.05E-026,779 boilers PM-filterable 4,7396,779 boilers PM-filterable 4,4646,779 boilers PM-filterable 1,2596,779 boilers PM-filterable 1,656PM 2.5 3,602PM 2.5 3,393PM 2.5 957PM 2.5 1,258HCl 825HCl 8HCl 8HCl 8Total Hydrocarbons 648Total Hydrocarbons 505Total Hydrocarbons 274Total Hydrocarbons 505VOC 372VOC 290VOC 158VOC 290CO 10,145CO 7,056CO 4,750CO 7,056Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0HF 44HF 0HF 0HF 0SO2 15,015SO2 150SO2 150SO2 150Non-Hg Metals 1,983Non-Hg Metals 1,959Non-Hg Metals 458Non-Hg Metals 48PROPOSED OPTIONAppendix C-1: Secondary Impacts for Existing Area Source Boilers for Option 3EElectricity (kWh/yr) Solid Waste (tpy) Electricity (kWh/yr) Solid Waste (tpy)Biomass Unit 1 560.06<10 Biomass ----Biomass Unit 2 2550.28<10 Biomass ----Biomass Unit 3 2430.79<10 Biomass ----Biomass Unit 4 5,4142.46<10 Biomass ----Biomass Unit 5 1,5247.45<10 Biomass ----Biomass Unit 6 3,41821.04>=10 Biomass ----Biomass Unit 7 48131.00>=10 Biomass ----Coal Unit 1 1840.02<10 Coal ----Coal Unit 2 1530.25<10 Coal ----Coal Unit 3 1170.78<10 Coal ----Coal Unit 4 2,3012.26<10 Coal ----Coal Unit 5 3826.68<10 Coal ----Coal Unit 6 57323.49>=10 Coal 206,017,43314,309206,017,43314,309Distillate Unit 1 6,6320.06<10 Liquid ----Distillate Unit 2 73,5480.31<10 Liquid ----Distillate Unit 3 26,5370.74<10 Liquid ----Distillate Unit 4 41,6042.47<10 Liquid ----Distillate Unit 5 8,3926.76<10 Liquid ----Distillate Unit 6 9,01625.31>=10 Liquid ----Distillate Unit 7 137173.44>=10 Liquid ----Residual Unit 1 210.04<10 Liquid ----Residual Unit 2 1090.29<10 Liquid ----Residual Unit 3 910.74<10 Liquid ----Residual Unit 4 1,2462.68<10 Liquid ----Residual Unit 5 5945.95<10 Liquid ----Residual Unit 6 7417.56>=10 Liquid ----Residual Unit 7 2126.00>=10 Liquid ----Totals 206,017,40014,30019,621,853FuelCategoryFabric Filter TOTALSTotal Energy Savings (mmBtu/yr)Model UnitNumber of BoilersRepresented byModelDesignCapacity(mmBtu/hr)SizeCategoryAppendix C-2: Secondary Impacts for New Area Source Boilers for Option 3NElectricity (kWh/yr) Solid Waste (tpy) Electricity (kWh/yr) Solid Waste (tpy) Electricity (kWh/yr) Solid Waste (tpy)New Biomass Unit 1 707.45<= 10 Biomass --2,483,3585572,483,358557New Biomass Unit 2 707.45<= 10 Biomass --2,483,3585572,483,358557New Biomass Unit 4 1121.04> 10 Biomass --836,003247836,003247New Biomass Unit 3 49131.00> 10 Biomass ------New Coal Unit 1 626.68<= 10 Coal 4,048,641220--4,048,641220New Coal Unit 2 936.68<= 10 Coal 6,072,962330--6,072,962330New Distillate Unit 1 5,4356.76<= 10 Liquid ------New Distillate Unit 2 4076.76<= 10 Liquid ------New Distillate Unit 3 35225.31> 10 Liquid ------New Distillate Unit 4 9025.31> 10 Liquid ------New Residual Unit 1 955.95<= 10 Liquid 3,594,13291--3,594,13291New Residual Unit 2 4517.56> 10 Liquid 4,038,517127--4,038,517127Totals 23,557,0002,1002,338,300Total Energy Savings (mmBtu/yr)Electrostatic PrecipitatorModel UnitNumber of BoilersRepresented byModelDesignCapacity(mmBtu/hr)SizeCategoryFuelCategoryFabric FilterTOTALSAppendix D-1: Control, Testing and Monitoring Costs for Option 3N at New Area Source Boilers through 2013 - As displayed in RIA/PreambleModel Unit SectorNumber ofBoilersRepresentedby ModelDesignCapacity(mmBtu/hr)SizeCategoryFuelCategory Baseline ControlTCI - ControlOnly ($)TAC - ControlOnly ($/yr) TCI - T&M ($) TAC - T&M ($/yr) TOTAL - TCI ($)TOTAL - TAC($/yr)New Biomass Unit 1 Commercial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 12,368,958$ 2,486,961$ 3,999,557$ 2,006,236$ 16,368,515$ 4,493,197$New Biomass Unit 2 Industrial 70 7.44596641 <= 10 Biomass Cyclone or Multiclone 12,368,958$ 2,469,492$ 3,999,557$ 2,006,236$ 16,368,515$ 4,475,728$New Biomass Unit 4 Commercial 11 21.0354469 > 10 Biomass Cyclone or Multiclone 3,511,707$ 630,059$ 628,502$ 315,266$ 4,140,209$ 945,324$New Biomass Unit 3 Industrial 49 131 > 10 Biomass Electrostatic Precipitator 317,373$ 140,875$ 7,975,877$ 2,611,847$ 8,293,250$ 2,752,722$New Coal Unit 1 Commercial 62 6.68176984 <= 10 Coal Cyclone or Multiclone 58,804,640$ 19,965,091$ 2,759,000$ 1,779,400$ 61,563,640$ 21,744,491$New Coal Unit 2 Industrial 93 6.68176984 <= 10 Coal Cyclone or Multiclone 88,206,961$ 29,947,636$ 4,138,500$ 2,669,100$ 92,345,461$ 32,616,736$New Distillate Unit 1 Commercial 5435 6.76086488 <= 10 Liquid No HAP APCD Control 35,202,495$ 15,625,625$ 310,537,062$ 155,769,885$ 345,739,557$ 171,395,510$New Distillate Unit 2 Industrial 407 6.76086488 <= 10 Liquid No HAP APCD Control 2,636,139$ 1,170,125$ 23,254,569$ 11,664,829$ 25,890,708$ 12,834,954$New Distillate Unit 3 Commercial 352 25.3122861 > 10 Liquid No HAP APCD Control 2,279,904$ 1,012,000$ 20,112,060$ 10,088,500$ 22,391,964$ 11,100,500$New Distillate Unit 4 Industrial 90 25.3122861 > 10 Liquid No HAP APCD Control 582,930$ 258,750$ 5,142,288$ 2,579,446$ 5,725,218$ 2,838,196$New Residual Unit 1 Commercial 95 5.94997049 <= 10 Liquid No HAP APCD Control 78,990,019$ 28,173,707$ 2,422,500$ 921,500$ 81,412,519$ 29,095,207$New Residual Unit 2 Commercial 45 17.5602083 > 10 Liquid No HAP APCD Control 47,363,088$ 15,513,824$ 1,777,500$ 1,066,500$ 49,140,588$ 16,580,324$TOTALS 6779 TOTALS 342,633,171$ 117,394,145$ 386,746,973$ 193,478,745$729,380,144$ 310,872,890$Appendix D-2: Emission Reductions from New Area Source Boilers - As Displayed in RIA/PreambleSUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1N Emission REDUCTIONS SUMMARY - Option 2N Emission REDUCTIONS SUMMARY- Option 3N Emission REDUCTIONSNEW Boilers at Area Sources NEW Boilers at Area Sources NEW Boilers at Area Sources NEW Boilers at Area SourcesFuel Category PollutantBaselineEmissions(tpy) Fuel Category PollutantEmissionReductions(tpy) Fuel Category PollutantEmissionReductions(tpy) Fuel Category PollutantEmissionReductions(tpy)Biomass Hg 2.56E-02 Biomass Hg 1.75E-02 Biomass Hg 1.52E-02 Biomass Hg 2.56E-04200 boilers PM-filterable 2,858200 boilers PM-filterable 2,715200 boilers PM-filterable 1,900200 boilers PM-filterable 686PM 2.5 2,172PM 2.5 2,063PM 2.5 1,444PM 2.5 521HCl 159HCl 2HCl 2HCl 2Total Hydrocarbons 365Total Hydrocarbons 245Total Hydrocarbons 213Total Hydrocarbons 245VOC 209VOC 141VOC 122VOC 141CO 7.29E+03 CO 4.90E+03 CO 4.24E+03 CO 4.90E+03Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0HF 4HF 0HF 0HF 0SO2 1,296SO2 13SO2 13SO2 13Non-Hg Metals 18Non-Hg Metals 17Non-Hg Metals 8Non-Hg Metals 8Coal Hg 9.27E-02 Coal Hg 8.53E-02 Coal Hg 9.27E-04 Coal Hg 8.53E-02155 boilers PM-filterable 656155 boilers PM-filterable 575155 boilers PM-filterable 7155 boilers PM-filterable 506PM 2.5 499PM 2.5 437PM 2.5 5PM 2.5 384HCl 329HCl 3HCl 3HCl 3Total Hydrocarbons 12Total Hydrocarbons -Total Hydrocarbons -Total Hydrocarbons -VOC 7VOC -VOC -VOC -CO 605CO -CO -CO -Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0HF 9HF 0HF 0HF 0SO2 2,572SO2 26SO2 26SO2 26Non-Hg Metals 3Non-Hg Metals 3Non-Hg Metals 0Non-Hg Metals 3Liquid Hg 2.82E-01 Liquid Hg 2.48E-01 Liquid Hg 5.76E-02 Liquid Hg 4.94E-036,424 boilers PM-filterable 2,5056,424 boilers PM-filterable 2,4536,424 boilers PM-filterable 6326,424 boilers PM-filterable 99PM 2.5 1,904PM 2.5 1,865PM 2.5 481PM 2.5 75HCl 338HCl 3HCl 3HCl 3Total Hydrocarbons 271Total Hydrocarbons 260Total Hydrocarbons 62Total Hydrocarbons 260VOC 156VOC 149VOC 36VOC 149CO 2,252CO 2,159CO 506CO 2,159Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0HF 30HF 0HF 0HF 0SO2 11,148SO2 111SO2 111SO2 111Non-Hg Metals 1,962Non-Hg Metals 1,940Non-Hg Metals 451Non-Hg Metals 28TOTAL Hg 0TOTAL Hg 0TOTAL Hg 7.37E-02 TOTAL Hg 9.05E-026,779 boilers PM-filterable 6,0186,779 boilers PM-filterable 5,7436,779 boilers PM-filterable 2,5396,779 boilers PM-filterable 1,291PM 2.5 4,574PM 2.5 4,365PM 2.5 1,929PM 2.5 981HCl 825HCl 8HCl 8HCl 8Total Hydrocarbons 648Total Hydrocarbons 505Total Hydrocarbons 274Total Hydrocarbons 505VOC 372VOC 290VOC 158VOC 290CO 10,145CO 7,056CO 4,750CO 7,056Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0Dioxins/Furans 0HF 44HF 0HF 0HF 0SO2 15,015SO2 150SO2 150SO2 150Non-Hg Metals 1,983Non-Hg Metals 1,960Non-Hg Metals 459Non-Hg Metals 38PROPOSED OPTIONAppendix D-3: Secondary Impacts for New Area Source Boilers for Option 3N - As Displayed in RIA/PreambleElectricity (kWh/yr) Solid Waste (tpy) Electricity (kWh/yr) Solid Waste (tpy) Electricity (kWh/yr) Solid Waste (tpy)New Biomass Unit 1 707.45<= 10 Biomass --1,905,8664031,905,866403New Biomass Unit 2 707.45<= 10 Biomass --1,905,8664031,905,866403New Biomass Unit 4 1121.04> 10 Biomass --579,630179579,630179New Biomass Unit 3 49131.00> 10 Biomass ------New Coal Unit 1 626.68<= 10 Coal 4,048,641220--4,048,641220New Coal Unit 2 936.68<= 10 Coal 6,072,962330--6,072,962330New Distillate Unit 1 5,4356.76<= 10 Liquid ------New Distillate Unit 2 4076.76<= 10 Liquid ------New Distillate Unit 3 35225.31> 10 Liquid ------New Distillate Unit 4 9025.31> 10 Liquid ------New Residual Unit 1 955.95<= 10 Liquid 3,594,13291--3,594,13291New Residual Unit 2 4517.56> 10 Liquid 4,038,517127--4,038,517127Totals 22,145,6001,8002,338,300Total Energy Savings (mmBtu/yr)Electrostatic PrecipitatorModel UnitNumber of BoilersRepresented byModelDesignCapacity(mmBtu/hr)SizeCategoryFuelCategoryFabric FilterTOTALS