# MEMORANDUM



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

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

DATE: April 2010

SUBJECT: Methodology for Estimating Cost and Emissions Impacts for Industrial,

Commercial, Institutional Boilers an d Process Heaters National Emission

Standards for Hazardous Air Pollutants – Major Source



# 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 major sources of hazardous air polluta nts (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 achieva ble control technology (M ACT) floor level of

control, projection of new units, and a detailed descripti on of the cost equations used to estimate

costs for various control technologie s is presented in other memoranda. 1,2,3 

# This memorandum is

organized as follows:

1.0 Introduction

2.0 Overview of Regulatory Options

3.0 Estimating Cost Impacts

4.0 Methodology for Estimating Emission Reductions

5.0 Methodology for Estimating Secondary Impacts

6.0 References

# 2.0 OVERVIEW OF REGULATORY OPTIONS

Five control options were considered for existing boilers and pro cess heaters at major

sources of HAP. A description of the si x options is include d in this section.



# 2.1 Existing Units

 Option 1E represents the option where all boilers, rega rdless of fuel type or size, must

meet PM, HCl, mercury, CO, a nd D/F numerical emission limits.

 Option 2E uses the same control device and testing, and monitoring cost estimation logic

outlined above for option 1E, except that it doe s not estimate ACI for units exceeding the

MACT floor emission limit for dioxin/furan. Inst ead, it is estimated that most units, when

testing for dioxin/furan will be below detecti on levels without installing any additional

control devices.

 Option 3E uses the same control device and testing, and monitoring cost estimation logic

outlined above for option 4E below, but it does not include the cost of an annual energy

audit.

 Option 4E represents the primary proposed opt ion discussed in the preamble. In this

option all boilers and process e qual to or greater than or e qual to 10 mmBtu/hr must meet

PM, HCl, mercury, CO, and D/F numerical emi ssion limits, except for units in the natural

gas/refinery gas and Metallurgical Process Furnace subcategories. All boilers and

process heaters less than 10 mmB tu/hr must meet a work practice standard of a biennial

boiler tune-up. All large units greater than or equal to 10 mmBtu/hr in the natural

gas/refinery gas and Metallurgical Process Furnace subcategories must meet a work

practice standard of an annual boiler tune-up. All major source facilities with a boiler or

process heater must conduct an energy audit.

 Option 5E uses the same control device and testing, and monitoring cot estimation logic

outlined above for option 4E above for all units except for refinery gas units. Units firing

refinery gas will have a separate numerical emission limit for mercury.

 A revised definition of solid waste is be ing proposed parallel w ith this proposed

rulemaking effort. The solid waste definitional rulemaking proposal includes both a

primary and alternative definition of solid waste for consideration during the public

comment period. Options 1E through 5E analy ze the regulatory imp acts with respect to

the primary proposed definition of solid waste. However, to compare the impacts of both

definitions of solid waste, the cost and emission impacts of regulatory option 4E

discussed above were applied to the inventory of units that were not classified as waste

burning units under the alternativ e solid waste definition.

# 2.2 New Units

Three control options were considered for ex isting boilers and process heaters at major

sources of HAP. A description of the thr ee options is included in this section.

 Option 1N represents the opti on where all new boile rs, regardless of fuel type or size,

must meet PM, HCl, mercury, CO, and D/F numerical emission limits.

 Option 2N uses the same control device and testing, and monitoring cost estimation logic

outlined above for option 1N, except that it doe s not estimate ACI for units exceeding the

MACT floor emission limit for dioxin/furan. Inst ead, it is estimated that most units, when

testing for dioxin/furan will be below detecti on levels without installing any additional

control devices.

 Option 4N represents the primary proposed opt ion discussed in the preamble. In this

option all boilers and process, regardless of size, meet PM , HCl, mercury, CO, and D/F

numerical emission limits, except for units in the natural ga s/refinery gas and

Metallurgical Process Furnace subcategories. A ll units in the natural gas/refinery gas and

Metallurgical Process Furnace subcategories mu st meet a work practice standard of an

annual boiler tune-up.



# 3.0 ESTIMATING COST IMPACTS

For each option, the cost impacts analysis compar es the baseline emissions for each unit to the

corresponding MACT floor emission limit for th e unit’s subcategory. A control device was

applied to the unit if its baseline emissions exce eded their applicable MACT floor emission limit.

A comparison of the overall capita l and annualized costs of the proposed options 4E and Option

4N are presented in Table 1. The detailed equa tions used to estimate the control, testing,

monitoring, and work practice costs ar e discussed in another memorandum. 2 

# The following logic

was used to apply control, te sting, and monitoring costs to each boiler or process heater:



# 3.1 Option 1E/1N

Control Cost Impacts

Mercury Control

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

proposed rule. Where baseline Hg emissions were found to be grea ter than the MACT

# floor, the cost of a fabric filter was estimated for an individual boiler or process heater,

unless the unit already had a fabric filter installe d. A new fabric filter was estimated to be

installed at 12,138 existi ng boilers and process heaters. In the case of a unit with a fabric

filter emitting Hg above the MACT floor emi ssion limit, the incremental Hg removal

efficiency required to meet the MACT floor was calculated, and then the costs to install

activated carbon injection (A CI) technology on the boiler were estimated. If the unit had

a packed bed scrubber and did not meet th e MACT floor for Hg, a fabric filter was

installed if no other control was in place. Incremental ACI equipment was installed for

155 existing boilers a nd process heaters.

 Wet scrubbers—the technology selected for th e cost analysis to reduce emissions of

hydrogen chloride (HCl)—are also capable of achieving modest reductions in Hg.

Literature suggests that these scrubbers can achieve a 10-percent reduction in Hg

emissions. If a scrubber was be ing installed for HCl, and baseline Hg emissions were

within 10 percent of the MACT floor, the wet scrubber was expected to achieve this level

of emission reduction without installing a fabric filter.

Particulate Matter Control

 When baseline particulate (PM) emissions ex ceeded the MACT floor, the cost of an ESP

was estimated, unless a fabric filter had alrea dy been included in the cost analysis for Hg

reduction. ESP technology was estimated to be installed at 397 existing boilers and

process heaters.

 Wet scrubbers are also capable of achievi ng a modest reduction in PM. Literature

suggests that these scrubbers can achieve an 85-percent reduction in PM emissions. If a

scrubber was being installed for HCl, and base line PM emissions were within 85 percent

of the MACT floor for PM, the wet scrubber was expected to achieve this level of

emission reduction without installing an ESP.

Hydrogen Chloride Control

 When HCl baseline emissions were greater than the MACT floor, the cost of adding a

packed bed scrubber was estimated. If the boi ler already reported to have a scrubber

installed and the baseline emissions still exceed ed the floor, the incremental required HCl

# removal efficiency was calculated and the then the cost to increase the sorbent injection

rate in the scrubber was estimated in the cost analysis. Wet scrubbers were identified to

be necessary to control HCl emissions at 13,269 existing boilers and process heaters

Dioxin/Furan Control

 Where dioxin/furans exceeded the MACT fl oor, the required removal efficiencies of

dioxin/furans was calculated, and the costs to install ACI were included in the cost

analysis. If ACI had was previously included in the cost analysis for incremental Hg

control, the ACI costs based on the highest required removal e fficiency were used in the

cost analysis. For example, if a boiler requi red 90 percent reduction in Hg and 98 percent

reduction in dioxin/furan, the higher ACI cost s associated with the 98 percent reduction

of dioxin/furan were used in the cost anal ysis. ACI technology was estimated to be

required at 2,538 existing boilers and proce ss heaters for either Hg or dioxin/furan

control.

Carbon Monoxide and 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 necessa ry to meet the MACT floor emission limit

will vary depending on the magnitude between the baseline emissions and the CO MACT

floor. A step function was used to delineat e what type of control strategy should be

analyzed in the cost impacts analysis:

o Most boilers (other than Dutch ovens a nd PC-coal boilers discussed below) 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 m onoxide (CO), but were less than or

equal to 400 ppm @ 3% O 2



# .

o If the baseline CO emissions we re between 400 and 1000 ppm @ 3% O 2 

# for

boilers and process heaters designed to burn liquid and gaseous fuels, the cost of a

replacement low-NOx burner was estimated to achieve the MACT floor emission

limits.

# o Since stokers, fuel cells, or fluidized bed unit do not have replaceable burners, a

linkageless boiler management system (L BMS) was the technology estimated to

achieve the MACT floor when baseline CO emissions exceeded the floor and

were between 400 and 1000 ppm @ 3% O 2



# .

o For boilers and process heaters designed to burn gas and liquids, as well as

stokers, fuel cells, and fluidized bed bo ilers and process he aters design to burn

solid fuels, the cost impacts analysis estimated that a CO Oxidation catalyst

would be required to meet MACT floor limits if a unit’s baseline CO emissions

were above 1,000 ppm @ 3% O 2 

# and exceeded the MACT floor.

o Similar to stokers, Dutch oven and suspen sion-fired boilers and process heaters do

not have replaceable burners. The desi gn of the Dutch oven/suspension burner

combustion system and the high moisture content of the fuels used in Dutch ovens

typically cause elevated CO levels comp ared to other combustor designs. A tuneup was estimated in the cost analysis for any Dutch oven/suspension burner with a

baseline of less than 5,000 ppm @ 3% O 2



# . LBMS costs were estimated for any

Dutch oven boiler with baseline CO between 5,000 – 12,500 ppm @ 3% O 2. 

# If the

baseline CO emissions at Dutch oven/ suspension-fired units exceeded 12,500

ppm @ 3% O 2 

# , the cost of adding catalytic oxidation was estimated for the cost

impacts analysis.

o For PC-boilers, a tune-up was estimated in the cost analysis for any unit with a

baseline of less than 1200 ppm @ 3% O 2 

# . The cost of a replacement LNB was

estimated if CO emissions were between 1200 – 3000 ppm @ 3% O 2 

# and catalytic

oxidation was estimated if CO baseline was greater than 3000 ppm @ 3% O 2.



# Option 1E of the cost impacts analysis estimated 11,013 existing boilers and process

heaters would meet the CO MACT floor with a tune-up, an additional 1,073 existing units would

install a LBMS, 1 existing boiler would replace their existing burner with a LNB, and 482

existing units would install a CO oxidation catalyst.

# 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 unit, and th e fuel category the unit was

assigned to.

Testing Costs

All boilers and process heaters designed to burn solid and gaseous fuels were expected to

conduct an annual compliance test for PM, HCl, Hg, D/F, and CO. The cost to conduct stack

tests for these five pollutant s was estimated to be $44,000 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, HCl, Hg, a nd D/F was estimated to be $37,000 per year.

Boilers and process heaters designed to burn liquid fuels were expected to conduct an

annual compliance test for PM, D/F, and CO. In lieu of a stack test bo ilers 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 test s for PM, D/F, and CO and fuel analysis for

chlorine and Hg was estimated to be $16,000 per year. Combustion units greater than 100

mmBtu/hr were expected to install CO CEMS in lieu of conducting a CO st ack test and the cost

to conduct tests on PM and D/F a nd fuel analysis for chlorine and Hg was estimated to be

$10,000 per year. Although other fuels are eligible to comply with the proposed rule through fuel

analysis in lieu of stack testing, this cost estimate conservatively assumed that only units

designed to fire liquid fuels woul d use this compliance alternative. The methods and data sources

used to estimate testing and monitoring costs are discussed in other memoranda. 2



# Small boilers often exhaust to small diameter st acks that do not have a ny test ports or test

platforms installed. For these small units, we es timated the additional costs to these costs to

construct or rent scaffolding and install test ports. The costs incl ude installation of 4 test ports, 90

degrees opposed to each other, and five weeks rental of temporary scaffolding. EPA estimates

that these small sources would incur an additi onal $185 million to install test ports and rent

temporary scaffolding. Many establishments in each industry, commercial, or institutional sector

# are associated with multiple (as many as a 700) small units. A summary of the costs by fuel

category is shown in Table 1 below.

Table 1 Cost Estimate for Renting Scaffolding and Constructing Test Ports at Small Boilers and Process

Heaters

Fuel

Category Number of Small Boilers and Process

Heaters (less than 10 mmBtu/hr) Port Costs ($2008) Renting

Temporary

Scaffolding

($2008) Total Costs

($2008)

Coal 3 32,944 42,000 74,944

Biomass 26 285,517 364,000 649,517

Natural

Gas/

Refinery

Gas 7138 78,385,476 99,932,000 178,317,476

Other

Process

Gases 2 21,963 28,000 49,963

Liquid 238 2,613,581 3,332,000 5,945,581

Total 7,407 81,339,482 103,698,000 185,037,482



# 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 pack ed bed wet scrubbers, an annualized cost of $5,600 for a scrubber

parametric monitor was included in the cost analysis. For units expected to install a fabric filter,

an annualized cost of $9,700 for a bag leak detecti on monitor was included in the cost analysis.

If a unit was expected to install ACI, the cost to monitor the car bon injection rate was included in

the analysis, based on the unit’s hours of opera tion. For units greater than 100 mmBtu/hr, an

annualized cost of $53,300 for a CO CEMS was in cluded in the cost analysis, and for units

greater than 250 mmBtu/hr an annua lized cost of $56,100 was used in the cost analysis. For units

that did not install a PM CEMS and did not inst all a scrubber to meet HCl limits, an annualized

cost of $14,660 for an opacity monitor was includ ed in the cost analysis. No PM CEMS or

opacity monitors were assumed for boilers and process heaters designed to gaseous fuels.



# 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 manufacturing 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 the Equation 1:

Annual Fuel Savings (mmBtu/yr) = DC * CF * Op hours 

# * EG (Equation 1)

Where:

DC = unit design capacity (mmBtu/hr)

CF = capacity factor, 90% of design capacity

Op hours 

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

EG = Efficiency gain, estimated to be 1%

After the fuel savings for each boiler a nd process heater was calculated, the both

industrial and commercial prices fo r coal, #2 distillate fuel oil, #6 residual fuel oil, and natural

gas were obtain from the EIA. 3 

# The EIA data reported fuel prices as $/ton for coal, $/thousand

cubic feet for natural gas, 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 NAICS code reported by each facility and the fuel category assigned to each

combustion unit, the appropriate fuel price was multiplied by the calculated fuel savings. This

cost analysis only estimates the fuel savings fr om units in the coal, liquid and natural gas and

other gaseous fuel categories. A fuel savings wa s not estimated for units in the biomass fuel

category since the price of biomass fuels is vari able, and often biomass is an on-site industrial

byproduct instead of a purchased fuel.



# 3.2 Option 2E/2N

Option 2E uses the same control device and testing, and monitoring cost estimation logic

outlined above for option 1E, except that it does not estimate ACI for units exceeding the MACT

floor emission limit for dioxin/fura n. Instead, it is estimated that most units, when testing for

dioxin/furan will be below detection levels with out installing any additional control devices.

# 3.3 Option 3E

Option 3E follows the same logic for estimating control costs as option 2E outlined

above, with the exception of sm all units (less than 10 mmBtu/ hr) and units in the natural

gas/refinery gas and natural gas-fired metallurgi cal process furnace subcategories. In option 3E,

the only cost estimated for small units is the cost of an annual tune-up fo r each boiler or process

heater. For all units firing natural gas or refinery gas, regardless of the si ze of the unit, the only

cost estimated is the cost of an annual tune-up for each boiler or process heater.

Unlike option 2E, there are no testing and m onitoring costs are associated with small

units or units of any size desi gned to burn natural gas, refine ry gas, or natural gas-fired

metallurgical process furnaces.



# 3.4 Option 4E

Option 4E includes control device and testing/ monitoring cost estimation logic identical

to Option 3E outlined above, except for the additi on of the estimated cost of one facility-wide

energy audit for each facility, annualized over 5 years. 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. 2 

# The cost of each type of audit was

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

analysis, 1,608 facilities are expected to conduct an audit, 197 facilities are commercial or

institutional and 1,411 faci lities are industrial.



# 3.5 Option 5E

For refinery gas units, option 5E includes a co st estimate to install a carbon adsorption

system to filter the refinery ga s prior to combustion. Carbon adsorption is expected to remove

trace contaminants in the gas, such as Hg. When this option was initially considered, the baseline

emission factor for mercury from refinery gas units was estimated to be 1.07E-07 lb per mmBtu.

Since that analysis was completed, the baseline em issions from refinery gas units were reviewed

and an outlier from a 1990 test, on the order of 10 -5 

# was identified to be biasing the baseline

emission averages toward a higher average. This test occurred at F acility ID: CAExxonMobilTorrance (unit ID 75-F-1) and only one test run wa s available. Several additional mercury tests at

other units firing refinery gas at the same facility in the same year were reported two be two

# orders of magnitude lower than the test re ported for 75-F-1. Afte r removing the outlier

emissions, the baseline emissions of mercury from refinery gas were comparable to those of

natural gas, and a combined average mercur y baseline emission factor of 7.28E-07 lb/mmBtu

was used for both refinery gas and natural gas. .

For analyzing the cost impacts of option 5E EPA estimated one carbon adsorption system

for each facility with refinery gas boilers and pr ocess heaters. EPA expected that a centralized

adsorption system would provide economies of s cale and would treat all the gas prior to the

refinery gas being used in the combustion equipment. The cost impacts assumption estimates that

73 different facilities would inst all a carbon adsorption sy stem to treat refinery gas. Since the

revised estimate of mercury baseline emissions es timated from refinery gas units had decreased

substantially as a resu lt of adjusting the baseline emissi on factor, the cost to install carbon

adsorption was no longer cost effective and th e beyond the floor mercury control option from

refinery gas units was not incl uded in the proposal. However, th e estimated costs of installing

carbon adsorbers at refineries are in cluded in Appendix A for reference.



# 3.6 Option 4N

Option 4N follows the same logic for estimating control costs as option 2E/2N outlined

above, with the exception of un its in the natural gas/refine ry gas and natural gas-fired

metallurgical process furnace subcategories. In op tion 4N, the only cost estimated for units firing

natural gas or refinery gas, regard less of the size of the unit, the onl y cost estimated is the cost of

an annual tune-up for each boiler or process heater.

Unlike option 2E/2N, there are no testing and monitoring costs are associated units of any

size designed to burn natural gas, refinery gas, or natural gas-fired metallurgical process

furnaces.



# 3.7 Impacts Considering the Al ternative Solid Waste Definition

The impacts of the alternative solid wast e definition follows the identical logic for

estimating control costs as option 4E discussed in Section 3.4 above. Unde r this option, there

are13,275 boilers identified as not burning waste materials, compar ed to a total of 13,555 boilers

and process heaters under the primar y definition of solid waste. The remainders of these units are

analyzed under the parallel rulemaking effort fo r Commercial Industrial So lid Waste Incinerators

if the units are located in the private sector. Should the alternative definition of solid waste

# become the final promulgated definition, the addi tional waste burning units located in the public

sector will be analyzed under the forthcom ing Other Solid Waste Incinerator rulemaking.



# 3.8 Summary of Cost Impacts

Option 4E is the proposed option for existing boilers and process heaters and option 4N is

the proposed option for new boilers and process h eaters. Tables 1 and 2 summarize the costs of

the proposed option for new and existing units . Appendix A of this memorandum provides a

detailed summary of the costs according to boiler size, boiler fuel category, and individual

control device costs. Appendix A also includes a summary of the costs on existing units under

the alternative definition of solid waste.

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 Units TAC TAC

considering

fuel savings Testing &

Monitoring

TAC Control TAC Control

TCI

New 4N 46 $7.9 $6.2 $0.6 $7.2 $17.3

Existing 4E 13,555 $3,248 $2,871 $136 $3,086 $9,489



# Table 2: Summary of Costs by Control Ty pe for Existing Units under Option 4E

Costs shown in $10 6 

# (2008) with capital reco very estimated at 7%

Fabric Filter ESP Wet Scrubber Increased

Caustic

Rate Combustion

Controls

and

Oxidation

Catalysts Activated Carbon

Injection Energy

Audit Number of

Boilers TCI TAC TCI TAC TCI TAC TAC TCI TAC TCI TAC TAC

13,555 5,154 1,198 953 161 3,281 1,630 2.4 13.9 2.9 9.5 56.9 26.0



# 4.0 METHODOLOGY FOR ESTIMATING EMISSION

REDUCTIONS

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

and process heaters at both exis ting and new facilities and it pr esents a summary of the results

for the regulatory options 1E/1N and 4E/4N.

# 4.1 Emission Reductions from Existing Boilers and Process Heaters

The emission reductions analysis for existi ng combustion units was done for each boiler

and process heater in the major source inventory. There are a total of 13,555 boilers and process

heaters at major sources that reported data in the 2008 quest ionnaire (ICR No. 2286.01). Each

combustion unit was assigned a unit-specific or av erage baseline emission factor, depending on

the availability of emission data reported for th e unit. A detailed discussion of the procedures

and results of the baseline emissions anal ysis is presented in another memorandum. 4



# Emission Reductions for Option 1E

Emission reductions for PM, HCl, Hg, CO, a nd dioxins/furans were calculated on a ton

per year basis by subtracting the baseline emi ssions assigned to each unit from the MACT floor

emission limits corresponding to each unit’s su bcategory. A detailed discussion of the

procedures and results of the MACT floor an alysis is presented in another memorandum. 1 

# For

each combustion unit, a percent reduction in CO was calculated. It was assumed that each

combustion unit would achieve an identical percent reduction fr om baseline emissions for THC

and VOC as was achieved for CO. Similarly, a per cent reduction was also cal culated for HCl. It

was assumed that each combustion unit would achieve an identical percent reduction from

baseline emissions for HF as was achieved for HC l. A combustion unit is required to install a

scrubber for HCl control if it is not currently meeting the HCl floor limit, and if it doesn’t

already have a scrubber installed. For units required to install a scrubber, it was assumed that the

scrubber will achieve a 95 percent reduction fr om baseline for SO2. To calculate emission

reductions for SO2, baseline emissions were mu ltiplied by a factor of 0.95. A percent reduction

in PM was calculated in order to estimate tota l metals reductions. It was assumed that each

combustion unit would achieve an identical percent reduction from baseline emissions for each

non-Hg metallic HAP as was achieved for PM. PM2.5 emissions were assumed to be a fraction

of total filterable PM emissions based on fuel and control device confi guration installed on the

unit. The methods used to derive the contri bution of PM2.5 to overall filterable PM are

presented in other memoranda 4 

# To calculate emission reductions for PM2.5, the emission

reductions for PM were multiplied by the applic able PM2.5 fraction. Emission reductions for all

pollutants for which there was no floor value were calculated on a ton per year basis.

# 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 

# (Equation 2)

Where:

ER HI 

# = emission rate (lb/mmBtu)

0.0005 = conversion factor, lbs per ton

Op hours 

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

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 

# ) (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.

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 

# ) (Equation 4)

Where:

ER C 

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

# )

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

Q S 

# = exhaust flowrate (dscfm)

60 = conversion factor, minutes per hour

Op hours 

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

0.000000001 = conversion factor, ng to g

0.0022 = conversion factor, g per lb

0.0005 = conversion factor, lb per ton

20.946 = percentage of oxygen in ambient air

O 2 

# = percentage of oxygen assumed in exhaust gas

Std O 2 

# = 7 percent oxygen in standardized em ission concentration for proposed rule.

# 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 other memoranda. 2 

# All conversions required the

annual operating hours for each combustion unit reported in the 2008 survey. If no operating

hours were reported, the unit was assumed to ope rate for 8,400 hours per year (two weeks of

downtime).

Emission Reductions for Option 4E

The same calculations discussed for estima ting emission reductions for option 1E were

applied to all units except small units (less than 10 mmBtu/hr) a nd units of any size firing natural

gas or refinery gas. For small units firing any ty pe of fuel and units in the natural gas/refinery

gas and natural gas metallurgical process furnace subcategories, the emission reductions were

based on a one percent gain in efficiency e xpected from the annual tune-up work practice

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

one percent reduction in all types of emissi ons was estimated by multiplying the baseline

emissions for each unit by a factor of 0.01.

Emission Reductions under the Alte rnative Solid Waste Definition

The same calculations discussed for estima ting emission reductions for option 4E were

applied to all units that were identified as not burning waste under the alternative solid waste

definition. In this case, the base line emissions were compared to the MACT floor emission limits

calculated for units not burning so lid waste under the alternative definition. A discussion of the

methodology used to calculate the MACT floor em ission limits under the a lternative solid waste

definition is discussed in another memorandum. 1



# Incremental Emission Reductions if Ener gy Audit Findings are Implemented

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

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

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 Equation 1 described in 3.1 of this memo was

used to estimate fuel savings. In this case the e fficiency gain term was modified to be between 5

and 10 percent.

A summary of the estimated emission reducti ons at existing units for options 1E, the

proposed option 4E, as well as the reductions fr om units considering the alternative proposed

solid waste definition are located in Appendix B

.

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

Energy Audit

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 1.23E-07 1.23E-06 1.49E-07 2.55E-10 2.13E-10 2.05E-01 $

-

Max 6.85E+00 2.02E+01 4.98E+ 00 2.95E-03 2.80E+01 6.31E+06 $

58,771,608

Average 1.76E-01 8.55E-01 5.07E-02 8.53E-05 2.84E-01 1.69E+05 $

1,290,803

Median 1.57E-02 1.95E-01 2.97E-03 1.68E-05 5.17E-02 4.50E+04 $

255,301

TOTAL

(all 1,608 facilities) 282 1,375 81 0 457 271,172,354 2,075,611,566



# 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 2.46E-07 2.46E-06 2.99E-07 5.09E-10 4.26E-10 4.10E-01 $

-

Max 1.37E+01 4.04E+01 9.97E+00 5.89E-03 5.60E+01 1.26E+07 $

117,543,216

Average 3.51E-01 1.71E+00 1.01E-01 1.71E-04 5.69E-01 3.37E+05 $

2,581,606

Median 3.14E-02 3.91E-01 5.93E-03 3.36E-05 1.03E-01 8.99E+04 $

510,601

TOTAL

(all 1,608 facilities) 565 2,749 163 0 914 542,344,709 4,151,223,131



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

units in the coal, liquid and gas 1 fuel types. Biomass and process gases are industrial byproducts and were not

assigned a purchase price.

# 4.2 Emission Reductions from New Boilers and Process Heaters

Based on industrial and commercial fuel consum ption projections from the EIA, there are

46 new boilers and process heater s expected to come on-line by 2013. 5 

# a discussion of the

methodology used to project new boilers and process heaters is di scussed in another

memorandum. 3



# The New Source Performance Standards for Industrial, Commercial and Institutional

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

baseline level of control for projected new units. It was determined that new boilers and process

heaters larger than 30 mmBtu/hr and combusting biomass would install an ESP. This technology

selection is based on the analysis used to esta blish the PM NSPS limit for biomass boilers. New

coal units larger than 75 mmBtu/h r would have a fabric filter and wet scrubber installed, while

coal new units between 30 and 75 mmBtu/hr would only have a fabric filt er installed and would

meet the SO 2 

# limits in the NSPS by using coals with a low sulfur content. New units larger than

30 mmBtu/hr and combusting liquid fuel would have a fabric filter installed. All new units less

than 30 mmBtu/hr would have no add-on controls and liquid fuels were expected to meet the

NSPS SO 2 

# limits using low sulfur fuel oils. Gas-fired units of all sizes were not expected to

install controls to meet any of the NSPS limits. For this impacts analysis, it was assumed that all

new solid fuel units would be stokers, since st oker boilers are the most common type of solid

fuel boilers and all new units would have NOx cont rol installed as a baseline control, regardless

of fuel.

Emission Reductions for Option 1N

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

average baseline emission factor calculated for ex isting 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 combusti on units based on heat input. It was assumed

that all new solid and liquid units would be constructed to meet thes e limits, so they were used as

baseline emission values where a pplicable. The baseline emissions for each unit were subtracted

from the new source MACT floor emission limit corresponding to each un it’s subcategory. The

same calculations discussed in Section 3.1 of this memo were used to estimate the reductions for

new units.

# Emission Reductions for Option 4N

Similar to the methods discussed in S ection 4.1 of this memorandum, the emission

reductions for new units under regulatory option 4N were calculated by subt racting the baseline

emissions assigned to each unit from the MA CT floor emission limits corresponding to each

unit’s subcategory, except for units firing natural gas or refinery gas. For any size natural gas or

refinery gas-fired units, the emission reductions were estimated base on a 1 percent reduction in

emissions, as a result of implementing a tune-up work practice. A summary of the estimated

emission reductions at existing units for both option 1 and option 4 are located in Appendix B-1

.

Correction for Baseline and Emissi on Reductions from New Units

The emission reductions for new units summarized in Appendix B-1 of this

memorandum were incorrectly ba sed on the NSPS PM limit for modified sources. The baseline

emission rates used were 0.1 lb/mmBtu for bi omass and 0.051 lb/mmBtu for coal and liquid,

compared to the NSPS limit for new boilers of 0.03 lb/mmBtu. The results of this analysis were

used as the basis for the RIA and are presented in the preamble. However, Appendix B-3

presents the corrected baseline emission and es timated emission reductions for both options 1N

and 4Ns, when using a baseline PM emission ra te of 0.03 for all units. The emission reductions

of PM and PM2.5 were reduced by a small amount as a result of correctin g the baseline rate to

0.03 lb/mmBtu. This change did not m odify the estimated control costs.



# 5.0 METHODOLOGY FOR ESTIMATING SECONDARY

IMPACTS

Secondary impacts include the solid waste, wate r, wastewater, and electricity required to

operate air pollution control devices, as well as the additional energy sa vings resulting from

improved combustion controls or work practic es required by the NESHAP. This section

documents the inputs and equations used to esti mate these secondary impacts, and it summarizes

the impacts at existing units under proposed re gulatory option 4 and new units under proposed

regulatory option 1. Table 4-1 su mmarizes the cost, emission, a nd secondary impacts of this

proposed NESHAP. Appendices C-1 and C-2 pres ent a detailed breakdown of the secondary

# waste, water, and energy impacts from each subc ategory of new and existing boilers and process

heaters, respectively.

Table 4-2 Summary of Secondary Impacts



# Impact New Units

(proposed regulatory Option 4N) 

# Existing Units

(proposed regulatory Option 4E)

Water (gal/yr) 197,200 2.4 billion

Wastewater (gal/yr) 142,300 730 million

Solid Waste (tons/yr) 149,800 81,400

Purchased Electricity (kW-hr/yr) 11.2 2.9 billion

Energy Savings* (trillion Btu/yr) 0.1 41.7

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



# The secondary impacts were calculated using algorithms and assumptions described in

another memorandum. 2 

# These algorithms and assumptions were applied to the existing boiler

and process heaters, where the baseline emissions for each unit exceeded the proposed MACT

floor emission limit except for small units (< 10 mmBtu/hr) and units firing natural gas or

refinery gas. A one percent energy savings was calculated for all units , including the small and

gas-fired units since these units are expected to conduct a tune -up. For new units, the algorithms

and assumptions were applied to model units repr esenting units expected to come online between

2010 and 2013, when the baseline emissions for each model exceeded the proposed MACT floor

emission limit for new units except for units firing natural gas and refinery gas. Natural gas and

refinery gas are not required to meet a numerical emission limit, and ther efore not expected to

incur any secondary waste, water, or electricity impacts from th ese controls. A 1 percent energy

savings from natural gas and refinery gas units are included in the energy savings estimate in

Table 4-1 since these units are expected to c onduct a tune-up. The methodology used to assign

baseline emission factors to new and existing units are discussed in another memorandum. 4



# 5.1 Wastewater and Water Impacts

The water required to create a slurry in the packed scrubber and the wastewater generated

by the effluent of a packed bed scrubber was ca lculated for every unit expected to install a

# scrubber to meet the HCl limits in the proposed rule . Both the water and wa stewater calculations

required the use of several constants and variable s. The constants including the density of gas,

moles of salt needed per mole of hydrogen chloride in the exhaust gas, the molecular weight of

the salt used, the fraction of the waste stream treated, operating hours per year and the molecular

weight of the gas. The data sources for th ese constants are provided in another memorandum. 2



# The variables used to estimate the quantity of water required and wast ewater generated were

calculated based on characteristics reported for each existing unit in the 2008 survey and for the

characteristics assigned to each new model unit. The variables included: exhaust flow rate from

the combustion unit to the control device in actua l cubic feet per minute, the inlet loading of

hydrogen chloride to the control device (mole fraction), and the efficiency of the control device

in removing hydrogen chloride from the exhaust gas (percent reduction). The calculations used

to estimate each variable are provided in another memorandum. 2 

# The total national water and

wastewater amounts in Table 4.1 were determined by adding the per unit water and wastewater

estimates for all new and existing units, respectively.



# 5.2 Solid Waste Impacts

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

devices, spent carbon associated with ACI or the installation of a carbon be d adsorber, or spent

caustic from increasing the caustic injection rate. Solid waste im pacts were estimated for every

unit expected to install a fabric filter, ACI or carbon bed adsorber to meet mercury emission

limits, or install an ESP to meet PM emission lim its. The total national solid waste amounts in

Table 4.1 were determined by adding the per unit solid waste estimates for all new and existing

units, respectively. To estimate the solid waste co ntribution from each of these control devices,

the variables were calculated based on characte ristics reported for each existing unit in the 2008

survey and for the characteristics assigned to ea ch new model unit. The calculations used to

estimate each variable and the quantity of solid waste generated are provided in another

memorandum. 2



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

calculated when an electrostatic precipitator wa s determined to be necessary to meet the

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

several variables including: exha ust flow rate from the combus tion unit to the control device

(acfm); the inlet loading of particulate matter to the contro l 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 merc ury. 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).

For this analysis, the spent carbon collected from units w ith ACI is assumed to be

disposed of instead of being re-generated. The amount of spent carbon created from ACI was

calculated when ACI was expected to be neces sary to meet the proposed NESHAP emission

limits for mercury or dioxin/furan. The calculation re quired the use of six va riables, including:

exhaust flow rate from the combustion unit to the control device (dscfm); operating hours

(hr/year), required removal efficiency for merc ury and dioxin/furan, and an adjustment factor

based required removal efficiency of mercury or dioxin /furan.

The solid waste generated by the use of incr eased caustic was calculated for those units

where additional caustic was expected to achie ve the proposed NESHAP emission limits for

HCl. The calculation required the use of three vari ables, including: exhaust flow rate from the

combustion unit to the control device (dscfm); operating hours (hr/year), and the required

removal efficiency for HCl.



# 5.3 Electricity Impacts

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

scrubber, electrostatic precipitato r, and fabric filter, CO oxidation catalyst and the fans for the

ductwork associated with this equipment. These impacts were assessed for every unit that was

estimated to require hydrogen chloride and/or particulate matter c ontrol. 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 de mand in Table 4.1 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 th ese control devices, a set of vari ables were calculated based on

characteristics reported for each existing unit in the 2008 survey and for the characteristics

# assigned to each new model unit. The constants, variables, and calculations used to estimate

each variable and the electricity demand to opera te the control devices are provided in another

memorandum. 2



# 5.4 Energy Savings Impacts

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

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

the energy audit findings with a short-term 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

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 or process heater, and th e national energy savings presente d in Table 4.1 of this section

follows the same methodology as was discussed in Section 3.1 and reflect the savings from

boilers in the coal, gas, a nd liquid fuel categories only.



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

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

Section 3 of this memorandum. For the secondary impacts analysis at ex isting units under option

4E, the water, wastewater, solid waste, and elec tricity impacts were only assessed for large units,

(those greater than or equal to 10 mmBtu/hr) that are in the coal, biomass, liquids, or other

process gas subcategories. Seconda ry impacts of water, wastewater , solid waste, and electricity

were not assessed for natural gas or refinery gas units or units in the natural gas metallurgical

process furnace subcategory. Energy savings were estimated for all units firing anything other

than biomass since all units were ex pected to conduct an energy audit.

For new units under option 4N, the water, wastewater, solid waste, and electricity

impacts were assessed for any size unit firing coal, biomass, liquid, or other process gases.

Secondary impacts of water, wastewater, solid wa ste, and electricity were not assessed for

# natural gas or refinery gas units or units in the natural gas metallurgical process furnace

subcategory. A one percent energy savings was estimated for all units firing coal, liquids or

gases that were estimated to require a tune -up or the installation of combustion control

equipment to meet the CO limits from new bo ilers. Both tune-ups and combustion controls

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



# 6.0 REFERENCES

1. Singleton, Amanda. ERG. MACT Floor Met hodology for Major Source Boilers and

Process Heaters. April 2010.

2. Singleton, Amanda and S. McClutchey. ERG. Methodology for Estimating Control Costs

for the Major Source Industrial, Commercial and Institutional Boilers and Process

Heaters National Emission Standards fo r Hazardous Air Pollutants. April 2010.

3. Gibson, Graham. ERG. New Unit Analysis for Industrial, Commercial, and Institutional

Boilers and Process Heaters at Major Sources. April 2010.

4. U.S. Department of Energy, EIA. 2008 Deliv ered Fuel Prices to Industrial and

Commercial Clients. http://www.eia.doe.gov/

5. Gibson, G. ERG. Development of Baseline Emission Factors for Boilers and Process

Heaters at Commercial, Industrial, an d Institutional Faci lities. April 2010.

6. U.S. Department of Energy, EIA. Annua l Energy Outlook 2009. Table 2. Energy

Consumption by Sector and Source. http://www.eia.doe.gov/Appendix A-1 Existing Major Source Boilers Cost Summary by Subcategory for Option 1EFor units with ascrubberalready installedbut not meetingHCl floor, noTCI, only TACSizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-On andCombustion ControlCosts - TCITesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 Biomass 3,300,263 1,032,962 6,489,630 1,087,1011,709,522 3,810,588 - 478,175 52,501132,142 622,215 12,109,732 6,605,3681,555,400 8,160,768 - 8,160,768>=10 to 100 Biomass 181,037,995 48,778,404 100,286,013 15,412,05971,252,936 37,379,018 - 21,373,493 7,851,9174,752,661 37,021,350 378,703,097 146,442,747 13,363,031 159,805,779 - 159,805,779>100 to 250 Biomass 240,585,110 57,125,423 55,697,832 10,225,50776,093,682 28,469,564 - 15,076,277 6,653,5454,007,498 43,499,661 391,460,399 145,973,700 8,581,933 154,555,633 186,864 154,368,769>250 Biomass 985,562,507 229,318,420 51,095,944 9,042,247237,522,306 139,887,264 - 15,462,381 6,322,647 10,006,008 171,323,230 1,299,649,146 555,893,807 16,703,394572,597,201 4,214,074 568,383,127SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 Coal - - 98,787 422,041- 57,381 6,300 2,784 7,521158,952 435,862 151,300 587,162 148 587,015>=10 to 100 Coal 158,883,020 37,100,785 5,059,951 770,78590,885,691 33,254,201 17,227 1,978,682 264,8544,475,792 30,999,993 261,283,137 102,407,845 7,648,326 110,056,171 1,037,322 109,018,848>100 to 250 Coal 852,136,257 192,999,256 10,136,769 1,685,703544,846,026 220,720,401 1,546,439 3,808,521 849,357 16,618,399 174,307,762 1,427,545,971 592,108,918 27,413,537619,522,456 4,600,582 614,921,874>250 Coal 1,786,804,872 405,382,675 25,057,227 4,211,481979,190,605 617,365,416 834,533 7,205,580 2,609,877 21,761,031398,351,302 2,820,019,315 1,428,755,284 30,778,234 1,459,533,518 7,429,324 1,452,104,194SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 Gas 1 5,671,599,945 2,037,647,704 - -547,692,492 1,058,737,518 - 51,029,151 20,024,9922,775,136 5,326,946 6,273,096,723 3,121,737,159 190,621,2383,312,358,398 27,513,688 3,284,844,710>=10 to 100 Gas 1 4,601,847,886 1,249,220,882 -- 931,624,816 582,653,373 386 23,991,798 9,709,7252,574,011 15,535,530 5,560,038,511 1,857,119,897 82,443,059 1,939,562,955 67,665,732 1,871,897,223>100 to 250 Gas 1 3,364,410,262 790,335,946 -- 900,631,346 298,791,997 - 6,873,770 3,035,277546,828 4,562,134 4,272,462,206 1,096,725,35463,500,317 1,160,225,671 68,077,453 1,092,148,218>250 Gas 1 3,522,770,560 824,542,794 - -1,245,538,173 547,385,698 - 1,837,594 777,350542,854 8,142,630 4,770,689,181 1,380,848,473 24,843,555 1,405,692,028 66,580,424 1,339,111,604<10 Gas 2 1,617,229 430,773 -- 338,720 328,051 - 12,9545,750 - - 1,968,903764,574 52,062 816,637 3,617813,020>=10 to 100 Gas 2 111,191,736 30,293,298 -- 44,278,545 18,332,983 - 4,622,243 1,730,721 - - 160,092,524 50,357,0021,942,639 52,299,642 1,509,388 50,790,254>100 to 250 Gas 2 197,695,488 46,916,432 -- 95,266,854 27,937,056 - 2,051,439 778,649 45,738 113,630 295,059,519 75,745,7663,314,139 79,059,905 3,909,103 75,150,802>250 Gas 2 633,123,968 148,571,975 - -471,401,765 196,344,892 5,606 375,655 166,750228,009 2,116,086 1,105,129,397 347,205,309 5,132,193 352,337,502 16,777,853 335,559,649SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 Liquid - - 1,791,243 293,893 14,105,316 34,446,590 - 60,609,423 42,245,863830,693 4,355,232 77,336,676 81,341,5796,608,561 87,950,140 224,875 87,725,265>=10 to 100 Liquid - - 181,738,16327,872,171 118,150,867 67,283,063 - 127,428,537 56,617,3266,696,466 34,792,927 434,014,033 186,565,4869,985,605 196,551,091 7,675,839 188,875,252>100 to 250 Liquid - - 236,655,79243,365,475 182,018,521 58,546,443 - 49,744,853 20,260,8407,064,577 43,188,716 475,483,744 165,361,47511,102,402 176,463,876 11,538,015 164,925,862>250 Liquid 7,974,695 1,546,299 287,073,394 49,043,967370,607,939 185,168,220 3,037 18,229,829 7,358,640 6,568,301 70,504,018 690,454,159 313,624,181 9,859,322323,483,503 23,591,680 299,891,82322,320,541,7936,101,244,027961,081,957163,010,3906,923,254,9104,157,264,3782,407,228412,247,735########## 89,628,9281,044,770,88330,706,755,32311,656,019,788515,600,24812,171,620,036312,535,98311,859,084,053Combustion Controls and COOxidation CatalystsActivated Carbon for D/F and IncrementalHg ControlTOTALSFabric Filter ESP Wet ScrubberAppendix A-2 Existing Major Source Boilers Cost Summary by Subcategory for Option 4E (proposed option)For units with ascrubberalready installedbut not meetingHCl floor, noTCI, only TACSizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 Biomass - - -- - - - -- 168,402 74,750 -74,750 - 74,750>=10 to 100 Biomass 100,286,013 15,412,059 71,252,936 37,379,018- 2,059,846 236,979 31,146 115,737354,667,935 101,922,197 11,693,931 113,616,128- 113,616,128>100 to 250 Biomass 55,697,832 10,225,507 76,093,682 28,469,564- 854,542 98,152 - -373,231,165 95,918,646 7,932,633 103,851,279186,864 103,664,415>250 Biomass 51,095,944 9,042,247 237,522,306 139,887,264- 740,386 98,602 94,014 1,221,102 1,275,015,157 379,567,634 15,859,394 395,427,028 4,214,074 391,212,954SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 Coal19,431 8,625 -8,625 148 8,477>=10 to 100 Coal 158,883,020 37,100,785 5,059,951 770,78590,885,691 33,254,201 17,227 1,978,682 264,8541,604,496 5,889,425 258,411,841 77,297,277 7,097,626 84,394,903 1,037,322 83,357,581>100 to 250 Coal 852,136,257 192,999,256 10,136,769 1,685,703544,846,026 220,720,401 1,546,439 2,969,237 423,381 4,778,569 23,831,263 1,414,866,856 441,206,443 25,976,337467,182,781 4,600,582 462,582,199>250 Coal 1,786,804,872 405,382,675 25,057,227 4,211,481979,190,605 617,365,416 834,533 954,121 193,477 2,704,55123,496,077 2,794,711,376 1,051,483,658 29,319,9341,080,803,592 7,429,324 1,073,374,268SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 Gas 1 - - -- - - -- - - - 46,232,826 20,521,750 - 20,521,750 27,739,524 (7,217,774)>=10 to 100 Gas 1 - - -- - - -- - - -20,175,855 8,955,625 - 8,955,62577,072,746 (68,117,121)>100 to 250 Gas 1 - - -- - - -- - - -5,777,484 2,564,500 - 2,564,50083,743,594 (81,179,094)>250 Gas 1 - - -- - - -- - - - 2,454,783 1,089,625 - 1,089,625 104,368,055 (103,278,430)<10 Gas 212,954 5,750 -5,750 3,617 2,133>=10 to 100 Gas 2 111,191,736 30,293,298 -- 44,278,545 18,332,983 - 375,655 166,750 - - 155,845,936 48,793,031 1,942,639 50,735,670 1,509,388 49,226,282>100 to 250 Gas 2 197,695,488 46,916,432 -- 95,266,854 27,937,056 - 252,596 112,125 - - 293,214,938 74,965,613 3,304,039 78,269,651 3,909,103 74,360,548>250 Gas 2 633,123,968 148,571,975 - -471,401,765 196,344,892 5,606 375,655 166,750228,009 2,116,086 1,105,129,397 347,205,309 5,132,193 352,337,502 16,777,853 335,559,649SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 liquid25,908 11,500 -11,500 12,101 (601)<10 liquid1,515,618 672,750 -672,750 769,068 (96,318)>=10 to 100 liquid - - 177,080,32327,151,707 54,727,522 27,775,972 - 1,953,470 516,632 31,073 177,427 233,792,388 55,621,7373,155,524 58,777,261 5,176,491 53,600,770>=10 to 100 liquid - - 4,657,840720,464 63,423,345 39,507,090 - 349,748155,250 - - 68,430,933 40,382,804 4,563,503 44,946,307 2,552,983 42,393,324>100 to 250 liquid - - 236,655,79243,365,475 96,972,973 31,610,955 - 518,145 230,000 - - 334,146,911 75,206,430 5,461,412 80,667,842 8,215,011 72,452,831>100 to 250 liquid - - -- 85,045,548 26,935,489 - 155,44369,000 - - 85,200,99127,004,489 4,794,604 31,799,093 3,323,00328,476,089>250 liquid - - 287,073,394 49,043,967 251,906,908 129,338,957 - 284,980 126,500- - 539,265,282 178,509,4255,387,926 183,897,351 16,339,483 167,557,867>250 liquid 7,974,695 1,546,299 -- 118,701,031 55,829,262 3,037 90,675 40,250- - 126,766,401 57,418,8484,004,196 61,423,044 7,252,197 54,170,8473,747,810,036862,810,719952,801,085161,629,3953,281,515,7371,630,688,5212,406,84213,913,1812,898,7019,471,85856,847,1179,489,080,7703,086,408,416135,625,8913,222,034,308376,232,5342,845,801,773Notes:Annualized Energy AuditCosts25,978,250$Total Incl. Facility-levelCosts:3,248,012,558Total cons. FuelSavings:2,871,780,0231. Energy Audits are conducted once perfacility for all facilities.Combustion Controls and COOxidation CatalystsActivated Carbon for D/F and IncrementalHg ControlTOTALSFabric Filter ESP Wet ScrubberFor units with ascrubber alreadyinstalled but notmeeting HCl floor,no TCI, only TACModel FacilityIDAffectedSectorStandard FuelCategorySizeCategoryNumber ofProjectedBoilersOpHoursPerYearDesignCapacity TCI TAC TCI TAC TCI TACIncreased ScrubberCaustic TACIndCoalBlr1 Industrial Coal <=10 0 5,70010.0-------IndDryBmassBlr1 Industrial Dry Biomass <=10 0 7,3193.8-------ComGas1Blr1 Commercial Gas 1 <=10 27 7,9104.915,447,0186,440,754--2,056,5924,004,044-IndGas1Blr1 Industrial Gas 1 <=10 0 8,1965.1-------IndGas2Blr1 Industrial Gas 2 <=10 0 4,4698.1-------ComHvyLiqBlr1 Commercial Heavy Liquid <=10 1 5006.0583,643107,760--120,038155,877-IndHvyLiqBlr1 Industrial Heavy Liquid <=10 0 5,1335.3-------ComLtLiqBlr1 Commercial Light Liquid <=10 0 5,1452.3-------IndLtLiqBlr1 Industrial Light Liquid <=10 1 4,5544.3564,065176,581--86,350149,959-IndWetBmassBlr1 Industrial Wet Biomass <=10 0 6,4864.4-------ComCoalBlr1 Commercial Coal >10 to 100 0 5,16279.0-------IndCoalBlr2 Industrial Coal >10 to 100 0 5,94668.4-------IndDryBmassBlr2 Industrial Dry Biomass >10 to 100 0 7,18747.3-------ComGas1Blr2 Commercial Gas 1 >10 to 100 4 5,06434.73,847,7081,085,858--1,047,387725,223-IndGas1Blr2 Industrial Gas 1 >10 to 100 0 6,95543.7-------ComGas2Blr1 Commercial Gas 2 >10 to 100 1 7,59137.81,002,880331,933--546,850235,277-IndGas2Blr2 Industrial Gas 2 >10 to 100 0 6,65045.5-------ComHvyLiqBlr2 Commercial Heavy Liquid >10 to 100 2 4,73651.3----966,950447,317-IndHvyLiqBlr2 Industrial Heavy Liquid >10 to 100 0 6,32549.3-------ComLtLiqBlr2 Commercial Light Liquid >10 to 100 0 5,13237.1-------IndLtLiqBlr2 Industrial Light Liquid >10 to 100 3 4,86445.4----1,139,148610,167-ComBmassBlr1 Commercial Wet Biomass >10 to 100 0 8,76060.0-------IndWetBmassBlr2 Industrial Wet Biomass >10 to 100 0 8,20553.3-------IndBagasseBlr1 Industrial Bagasse >100 to 250 0 3,903229.0-------ComCoalBlr2 Commercial Coal >100 to 250 0 5,994163.7-------IndCoalBlr3 Industrial Coal >100 to 250 0 6,753187.6-------IndDryBmassBlr3 Industrial Dry Biomass >100 to 250 0 7,646166.5-------ComGas1Blr3 Commercial Gas 1 >100 to 250 1 4,291158.02,604,383601,373--936,617300,380-IndGas1Blr3 Industrial Gas 1 >100 to 250 0 6,855167.8-------ComGas2Blr2 Commercial Gas 2 >100 to 250 1 5,334146.32,445,960598,011--1,524,637428,612-IndGas2Blr3 Industrial Gas 2 >100 to 250 0 7,202177.7-------ComHvyLiqBlr3 Commercial Heavy Liquid >100 to 250 1 2,980196.0----1,489,478413,110-IndHvyLiqBlr3 Industrial Heavy Liquid >100 to 250 0 5,296174.1-------ComLtLiqBlr3 Commercial Light Liquid >100 to 250 0 5,150184.2-------IndLtLiqBlr3 Industrial Light Liquid >100 to 250 2 3,578177.7----2,381,734703,562-IndWetBmassBlr3 Industrial Wet Biomass >100 to 250 0 7,829186.6-------IndBagasseBlr2 Industrial Bagasse >250 0 4,668478.9-------ComCoalBlr3 Commercial Coal >250 0 7,832439.0-------IndCoalBlr4 Industrial Coal >250 0 7,721545.3-------IndDryBmassBlr4 Industrial Dry Biomass >250 0 8,421491.5-------ComGas1Blr4 Commercial Gas 1 >250 1 1,732318.24,892,926970,013--2,294,002906,720-IndGas1Blr4 Industrial Gas 1 >250 0 7,695423.6-------IndGas2Blr4 Industrial Gas 2 >250 0 8,094434.4-------IndHvyLiqBlr4 Industrial Heavy Liquid >250 0 5,367629.4-------ComLtLiqBlr4 Commercial Light Liquid >250 0 4,652776.4-------IndLtLiqBlr4 Industrial Light Liquid >250 1 5,246430.5----3,953,2871,354,866-IndWetBmassBlr4 Industrial Wet Biomass >250 0 8,218585.9-------TOTALS: 4631,388,58310,312,284--18,543,07110,435,116-Wet ScrubberModel Unit InputParametersAppendix A-3 New Major Source Boilers CostSummary in 2013 by Subcategory for Option 1NFabric Filter ESPModel FacilityIDAffectedSectorStandard FuelCategorySizeCategoryIndCoalBlr1 Industrial Coal <=10IndDryBmassBlr1 Industrial Dry Biomass <=10ComGas1Blr1 Commercial Gas 1 <=10IndGas1Blr1 Industrial Gas 1 <=10IndGas2Blr1 Industrial Gas 2 <=10ComHvyLiqBlr1 Commercial Heavy Liquid <=10IndHvyLiqBlr1 Industrial Heavy Liquid <=10ComLtLiqBlr1 Commercial Light Liquid <=10IndLtLiqBlr1 Industrial Light Liquid <=10IndWetBmassBlr1 Industrial Wet Biomass <=10ComCoalBlr1 Commercial Coal >10 to 100IndCoalBlr2 Industrial Coal >10 to 100IndDryBmassBlr2 Industrial Dry Biomass >10 to 100ComGas1Blr2 Commercial Gas 1 >10 to 100IndGas1Blr2 Industrial Gas 1 >10 to 100ComGas2Blr1 Commercial Gas 2 >10 to 100IndGas2Blr2 Industrial Gas 2 >10 to 100ComHvyLiqBlr2 Commercial Heavy Liquid >10 to 100IndHvyLiqBlr2 Industrial Heavy Liquid >10 to 100ComLtLiqBlr2 Commercial Light Liquid >10 to 100IndLtLiqBlr2 Industrial Light Liquid >10 to 100ComBmassBlr1 Commercial Wet Biomass >10 to 100IndWetBmassBlr2 Industrial Wet Biomass >10 to 100IndBagasseBlr1 Industrial Bagasse >100 to 250ComCoalBlr2 Commercial Coal >100 to 250IndCoalBlr3 Industrial Coal >100 to 250IndDryBmassBlr3 Industrial Dry Biomass >100 to 250ComGas1Blr3 Commercial Gas 1 >100 to 250IndGas1Blr3 Industrial Gas 1 >100 to 250ComGas2Blr2 Commercial Gas 2 >100 to 250IndGas2Blr3 Industrial Gas 2 >100 to 250ComHvyLiqBlr3 Commercial Heavy Liquid >100 to 250IndHvyLiqBlr3 Industrial Heavy Liquid >100 to 250ComLtLiqBlr3 Commercial Light Liquid >100 to 250IndLtLiqBlr3 Industrial Light Liquid >100 to 250IndWetBmassBlr3 Industrial Wet Biomass >100 to 250IndBagasseBlr2 Industrial Bagasse >250ComCoalBlr3 Commercial Coal >250IndCoalBlr4 Industrial Coal >250IndDryBmassBlr4 Industrial Dry Biomass >250ComGas1Blr4 Commercial Gas 1 >250IndGas1Blr4 Industrial Gas 1 >250IndGas2Blr4 Industrial Gas 2 >250IndHvyLiqBlr4 Industrial Heavy Liquid >250ComLtLiqBlr4 Commercial Light Liquid >250IndLtLiqBlr4 Industrial Light Liquid >250IndWetBmassBlr4 Industrial Wet Biomass >250TOTALS:Appendix A-3 New Major Source Boilers CostSummary in 2013 by Subcategory for Option 1NTCI TAC TCI TACTotal for all AddOn andCombustionControl Costs -TCITotal for all Addon andCombustionControl Costs -TACTesting andMonitoring -TACTotal TAC(Controls, Testingand Monitoring)SumOfFuelSavings ($/yr)Total TACConsidering FuelSavings--------------------174,87477,625--17,678,48410,522,423702,84211,225,265109,17811,116,087--------------------6,4772,8755,5934,862715,751271,37431,900303,274350302,924--------------------6,4772,8754,67321,257661,565350,67236,600387,2724,103383,169----------------------------------------25,90711,500--4,921,0031,822,581104,1251,926,70673,6931,853,013----------6,4772,875--1,556,207570,08526,031596,11630,107566,009----------12,9545,75040,522183,3441,020,426636,41154,200690,61156,639633,972--------------------19,4308,62557,611262,1111,216,190880,90381,600962,503138,612823,891------------------------------------------------------------6,4772,875--3,547,477904,62977,627982,25671,148911,108----------6,4772,875--3,977,0731,029,49877,6271,107,12581,9051,025,220----------6,4772,87545,300194,1741,541,255610,15972,303682,46268,127614,335--------------------12,9545,75087,054430,5832,481,7421,139,895146,0061,285,901265,7991,020,102--------------------------------------------------6,4772,875--7,193,4051,879,60977,6271,957,23657,8421,899,394----------------------------------------6,4772,87574,022706,2184,033,7872,063,959131,1032,195,062472,1411,722,922----------297,933132,250314,7761,802,54950,544,36422,682,1991,619,59124,301,7901,429,64522,872,145Combustion Controls andCO Oxidation CatalystsActivated Carbon for D/F andIncremental Hg Control TOTALSFor units with ascrubber alreadyinstalled but notmeeting HCl floor,no TCI, only TACModelFacilityIDAffectedSectorStandard FuelCategorySizeCategoryNumber ofProjectedBoilersOp Hours PerYearDesignCapacity TCI TAC TCI TAC TCI TACIncreasedScrubber CausticTAC TCI TAC TCI TACIndCoalBlr1 Industrial Coal <=10 0 5,70010-----------IndDryBmassBIndustrial Dry Biomass <=10 0 7,3194-----------ComGas1Blr1Commercial Gas 1 <=10 27 7,910515,447,0186,440,754--2,056,5924,004,044-174,87477,625--IndGas1Blr1 Industrial Gas 1 <=10 0 8,1965-----------IndGas2Blr1 Industrial Gas 2 <=10 0 4,4698-----------ComHvyLiqBl Commercial Heavy Liquid <=10 1 5006583,643107,760--120,038155,877-6,4772,875--IndHvyLiqBlr1Industrial Heavy Liquid <=10 0 5,1335-----------ComLtLiqBlr1 Commercial Light Liquid <=10 0 5,1452-----------IndLtLiqBlr1 Industrial Light Liquid <=10 1 4,5544564,065176,581--86,350149,959-6,4772,875--IndWetBmassIndustrial Wet Biomass <=10 0 6,4864-----------ComCoalBlr1 Commercial Coal >10 to 100 0 5,16279-----------IndCoalBlr2 Industrial Coal >10 to 100 0 5,94668-----------IndDryBmassBIndustrial Dry Biomass >10 to 100 0 7,18747-----------ComGas1Blr2Commercial Gas 1 >10 to 100 4 5,064353,847,7081,085,858--1,047,387725,223-25,90711,500--IndGas1Blr2 Industrial Gas 1 >10 to 100 0 6,95544-----------ComGas2Blr1Commercial Gas 2 >10 to 100 1 7,591381,002,880331,933--546,850235,277-6,4772,875--IndGas2Blr2 Industrial Gas 2 >10 to 100 0 6,65045-----------ComHvyLiqBl Commercial Heavy Liquid >10 to 100 2 4,73651----966,950447,317-12,9545,750--IndHvyLiqBlr2Industrial Heavy Liquid >10 to 100 0 6,32549-----------ComLtLiqBlr2 Commercial Light Liquid >10 to 100 0 5,13237-----------IndLtLiqBlr2 Industrial Light Liquid >10 to 100 3 4,86445----1,139,148610,167-19,4308,62557,611262,111ComBmassBl Commercial Wet Biomass >10 to 100 0 8,76060-----------IndWetBmassIndustrial Wet Biomass >10 to 100 0 8,20553-----------IndBagasseBlIndustrial Bagasse >100 to 250 0 3,903229-----------ComCoalBlr2 Commercial Coal >100 to 250 0 5,994164-----------IndCoalBlr3 Industrial Coal >100 to 250 0 6,753188-----------IndDryBmassBIndustrial Dry Biomass >100 to 250 0 7,646167-----------ComGas1Blr3Commercial Gas 1 >100 to 250 1 4,2911582,604,383601,373--936,617300,380-6,4772,875--IndGas1Blr3 Industrial Gas 1 >100 to 250 0 6,855168-----------ComGas2Blr2Commercial Gas 2 >100 to 250 1 5,3341462,445,960598,011--1,524,637428,612-6,4772,875--IndGas2Blr3 Industrial Gas 2 >100 to 250 0 7,202178-----------ComHvyLiqBl Commercial Heavy Liquid >100 to 250 1 2,980196----1,489,478413,110-6,4772,875--IndHvyLiqBlr3Industrial Heavy Liquid >100 to 250 0 5,296174-----------ComLtLiqBlr3 Commercial Light Liquid >100 to 250 0 5,150184-----------IndLtLiqBlr3 Industrial Light Liquid >100 to 250 2 3,578178----2,381,734703,562-12,9545,75087,054430,583IndWetBmassIndustrial Wet Biomass >100 to 250 0 7,829187-----------IndBagasseBlIndustrial Bagasse >250 0 4,668479-----------ComCoalBlr3 Commercial Coal >250 0 7,832439-----------IndCoalBlr4 Industrial Coal >250 0 7,721545-----------IndDryBmassBIndustrial Dry Biomass >250 0 8,421492-----------ComGas1Blr4Commercial Gas 1 >250 1 1,7323184,892,926970,013--2,294,002906,720-6,4772,875--IndGas1Blr4 Industrial Gas 1 >250 0 7,695424-----------IndGas2Blr4 Industrial Gas 2 >250 0 8,094434-----------Activated Carbon for D/F andIncremental Hg ControlModel Unit Input ParametersAppendix A-4 New Major Source Boilers Cost Summaryin 2013 by Subcategory for Option 4N (Proposed)Fabric Filter ESP Wet ScrubberCombustion Controls and COOxidation CatalystsModelFacilityIDAffectedSectorStandard FuelCategorySizeCategoryNumber ofProjectedBoilersIndCoalBlr1 Industrial Coal <=10 0IndDryBmassBIndustrial Dry Biomass <=10 0ComGas1Blr1Commercial Gas 1 <=10 27IndGas1Blr1 Industrial Gas 1 <=10 0IndGas2Blr1 Industrial Gas 2 <=10 0ComHvyLiqBl Commercial Heavy Liquid <=10 1IndHvyLiqBlr1Industrial Heavy Liquid <=10 0ComLtLiqBlr1 Commercial Light Liquid <=10 0IndLtLiqBlr1 Industrial Light Liquid <=10 1IndWetBmassIndustrial Wet Biomass <=10 0ComCoalBlr1 Commercial Coal >10 to 100 0IndCoalBlr2 Industrial Coal >10 to 100 0IndDryBmassBIndustrial Dry Biomass >10 to 100 0ComGas1Blr2Commercial Gas 1 >10 to 100 4IndGas1Blr2 Industrial Gas 1 >10 to 100 0ComGas2Blr1Commercial Gas 2 >10 to 100 1IndGas2Blr2 Industrial Gas 2 >10 to 100 0ComHvyLiqBl Commercial Heavy Liquid >10 to 100 2IndHvyLiqBlr2Industrial Heavy Liquid >10 to 100 0ComLtLiqBlr2 Commercial Light Liquid >10 to 100 0IndLtLiqBlr2 Industrial Light Liquid >10 to 100 3ComBmassBl Commercial Wet Biomass >10 to 100 0IndWetBmassIndustrial Wet Biomass >10 to 100 0IndBagasseBlIndustrial Bagasse >100 to 250 0ComCoalBlr2 Commercial Coal >100 to 250 0IndCoalBlr3 Industrial Coal >100 to 250 0IndDryBmassBIndustrial Dry Biomass >100 to 250 0ComGas1Blr3Commercial Gas 1 >100 to 250 1IndGas1Blr3 Industrial Gas 1 >100 to 250 0ComGas2Blr2Commercial Gas 2 >100 to 250 1IndGas2Blr3 Industrial Gas 2 >100 to 250 0ComHvyLiqBl Commercial Heavy Liquid >100 to 250 1IndHvyLiqBlr3Industrial Heavy Liquid >100 to 250 0ComLtLiqBlr3 Commercial Light Liquid >100 to 250 0IndLtLiqBlr3 Industrial Light Liquid >100 to 250 2IndWetBmassIndustrial Wet Biomass >100 to 250 0IndBagasseBlIndustrial Bagasse >250 0ComCoalBlr3 Commercial Coal >250 0IndCoalBlr4 Industrial Coal >250 0IndDryBmassBIndustrial Dry Biomass >250 0ComGas1Blr4Commercial Gas 1 >250 1IndGas1Blr4 Industrial Gas 1 >250 0IndGas2Blr4 Industrial Gas 2 >250 0Appendix A-4 New Major Source Boilers Cost Summaryin 2013 by Subcategory for Option 4N (Proposed)Total for all Add-Onand CombustionControl Costs - TCITotal for all Add-onand CombustionControl Costs -TACTesting andMonitoring -TACTotal TAC(Controls, Testingand Monitoring)SumOfFuelSavings ($/yr)Total TACConsidering FuelSavings------------174,87977,625-77,62571,2526,373------------710,158266,51231,300297,8123,613294,199------------656,892329,41531,300360,7154,651356,064------------------------25,90811,500-11,50075,125(63,625)------1,556,207570,08526,031596,11620,474575,643------979,904453,06743,200496,26761,740434,527------------1,216,190880,90381,600962,503147,091815,412------------------------------------6,4772,875-2,87585,594(82,719)------3,977,0731,029,49877,6271,107,12579,2701,027,855------1,495,955415,98568,903484,888118,012366,876------------2,481,7421,139,895146,0061,285,901383,517902,384------------------------------6,4772,875-2,875172,359(169,484)------------TOTALSFor units with ascrubber alreadyinstalled but notmeeting HCl floor,no TCI, only TACModelFacilityIDAffectedSectorStandard FuelCategorySizeCategoryNumber ofProjectedBoilersOp Hours PerYearDesignCapacity TCI TAC TCI TAC TCI TACIncreasedScrubber CausticTAC TCI TAC TCI TACActivated Carbon for D/F andIncremental Hg ControlModel Unit Input ParametersAppendix A-4 New Major Source Boilers Cost Summaryin 2013 by Subcategory for Option 4N (Proposed)Fabric Filter ESP Wet ScrubberCombustion Controls and COOxidation CatalystsIndHvyLiqBlr4Industrial Heavy Liquid >250 0 5,367629-----------ComLtLiqBlr4 Commercial Light Liquid >250 0 4,652776-----------IndLtLiqBlr4 Industrial Light Liquid >250 1 5,246431----3,953,2871,354,866-6,4772,87574,022706,218IndWetBmassIndustrial Wet Biomass >250 0 8,218586-----------TOTALS: 4631,388,58310,312,284--18,543,07110,435,116-297,933132,250218,6881,398,912ModelFacilityIDAffectedSectorStandard FuelCategorySizeCategoryNumber ofProjectedBoilersAppendix A-4 New Major Source Boilers Cost Summaryin 2013 by Subcategory for Option 4N (Proposed)IndHvyLiqBlr4Industrial Heavy Liquid >250 0ComLtLiqBlr4 Commercial Light Liquid >250 0IndLtLiqBlr4 Industrial Light Liquid >250 1IndWetBmassIndustrial Wet Biomass >250 0TOTALS: 46Total for all Add-Onand CombustionControl Costs - TCITotal for all Add-onand CombustionControl Costs -TACTesting andMonitoring -TACTotal TAC(Controls, Testingand Monitoring)SumOfFuelSavings ($/yr)Total TACConsidering FuelSavingsTOTALS------------4,033,7872,063,959131,1032,195,062464,6161,730,446------17,321,6477,244,195637,0707,881,2651,687,3136,193,952Appendix A-5 Existing Major Source Boilers Cost Summary in 2013 by Subcategory under Alternative Solid Waste DefinitionFor units with ascrubberalready installedbut not meetingHCl floor, noTCI, only TACSizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-On andCombustion ControlCosts - TCITesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 biomass 6,652,209 2,077,833 -- - - - 51,81423,000 - - 51,81623,000 - 23,000- 23,000>=10 to 100 biomass 243,665,061 65,234,515 1,976,874 301,752- - - 1,206,215158,402 77,827 117,859 246,925,976 65,812,5298,619,222 74,431,751 - 74,431,751>100 to 250 biomass 233,327,170 54,550,568 3,985,325 712,6221,922,912 809,277 - 567,637 66,651- - 239,803,045 56,139,1194,969,247 61,108,365 186,864 60,921,501>250 biomass 753,768,037 174,857,025 9,117,491 1,701,276- - - 645,662 107,676- - 763,531,190 176,665,9778,689,462 185,355,439 4,214,074 181,141,365SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings>=10 to 100 Coal 115,483,165 26,547,344 6,414,081 975,80782,536,509 29,706,897 15,116 1,729,727 231,0291,538,616 3,986,022 207,702,099 61,462,215 6,168,426 67,630,641 924,859 66,705,782>100 to 250 Coal 649,950,914 147,165,570 10,318,772 1,338,112503,665,075 205,505,024 1,564,339 2,814,703 373,956 3,850,498 14,847,289 1,170,599,961 370,794,290 23,857,641394,651,932 4,032,261 390,619,671>250 Coal 1,243,820,106 283,949,656 14,648,090 2,465,211909,721,344 566,222,388 834,533 819,019 152,676 2,342,39914,567,271 2,171,350,958 868,191,735 26,587,686894,779,421 5,954,432 888,824,988SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 Gas 1 5,676,731,393 2,039,299,884 - -548,348,356 1,059,662,417 - 46,270,347 20,539,0006,311 23,858 46,271,688 20,539,000- 20,539,000 27,770,034 (7,231,034)>=10 to 100 Gas 1 4,591,378,266 1,246,830,609 -- 928,566,115 582,110,951 386 20,175,270 8,955,6259,565 28,643 20,175,855 8,955,625- 8,955,625 76,737,881 (67,782,256)>100 to 250 Gas 1 3,348,748,012 786,877,951 -- 896,664,949 297,552,920 - 5,751,409 2,553,000- - 5,751,576 2,553,000- 2,553,000 83,426,681 (80,873,681)>250 Gas 1 3,503,289,220 819,943,106 - -1,238,054,220 544,282,991 - 2,441,758 1,083,875- - 2,441,829 1,083,875- 1,083,875 103,738,687 (102,654,812)<10 Gas 2 820,276 143,656 -- 179,761 165,898 - 6,4772,875 - - 6,4772,875 - 2,875 942,781>=10 to 100 Gas 2 113,653,521 30,950,924 -- 45,363,943 18,674,330 - 375,655 166,750 - - 159,393,119 49,792,005 1,968,670 51,760,675 1,509,388 50,251,287>100 to 250 Gas 2 197,695,488 46,916,432 -- 95,266,854 27,937,056 - 272,026 120,750 - - 293,234,368 74,974,238 3,463,948 78,438,185 4,215,335 74,222,850>250 Gas 2 585,379,328 137,642,011 - -437,260,711 180,657,603 5,606 343,271 152,375228,009 2,116,086 1,023,211,319 320,573,680 4,739,403 325,313,083 15,448,137 309,864,946SizeCategoryMACT FloorFuelCategory TCI TAC TCI TAC TCI TACIncreasedScrubberCaustic TAC TCI TAC TCI TACTotal for all Add-On andCombustion ControlCosts - TCITotal for all Add-on andCombustion ControlCosts - TACTesting and Monitoring -TACTotal TAC (Controls,Testing and Monitoring)SumOfFuel Savings($/yr)Total TAC ConsideringFuel Savings<10 liquid - - 1,345,276 215,945 12,121,134 34,792,981 - 1,573,865 698,625- - 1,573,911 698,625 - 698,625 785,608(86,983)>=10 to 100 liquid - - 165,072,82125,322,783 95,482,623 59,305,830 - 1,133,442 503,125 - - 261,688,886 85,131,737 7,214,326 92,346,064 7,133,888 85,212,175>100 to 250 liquid - - 203,104,54937,297,500 142,917,376 46,634,965 - 602,344 267,375 - - 346,624,268 84,199,840 9,423,626 93,623,466 10,091,534 83,531,933>250 liquid 7,974,695 1,546,299 283,752,589 48,411,749309,125,663 153,505,365 3,037 375,655 166,750- - 601,228,603 203,633,2009,392,122 213,025,322 23,723,305 189,302,01621,272,336,8615,864,533,383699,735,868118,742,7566,247,197,5443,807,526,8942,423,01887,156,29736,323,5158,053,22535,687,0287,561,566,9422,451,226,564115,093,7792,566,320,344369,893,0622,196,427,282Notes:Annualized Energy AuditCosts24,953,044$Total Incl. Facility-levelCosts:2,221,380,326Fabric Filter ESP Wet Scrubber1. Energy Audits are conducted once per facility for all facilities.Combustion Controls and COOxidation CatalystsActivated Carbon for D/F and IncrementalHg ControlTOTALS

# APPENDICES A-6a & A-6b

Existing Major Source Bo ilers Cost Detail for Option 4E (proposed option)

Energy Audit Costs for Existing Majo r Sources for Option 4E (proposed

option)

(See file named “ mjr-Impacts Appx A-6 ” for facility-specific cost estimates)Appendix A-7 New Major Source Boilers Cost Detail for Option 4N (proposed option)FacilityID UnitIDFuelCategory forUnitMACT FloorStandardFuelCategorySizeCategoryUnitCountOp HoursPer YearDesignCapacity(mmbtu/hr)Exhaust gasflow rate (dscfm)Actual gas flowrate (acfm) O2% HCl CG Hg CG PM CG Metals CGComCoalBlr1 Commercial Coal Coal >10 to 100 0 5,1627923,07243,4257.11 2 1 1ComCoalBlr2 Commercial Coal Coal >100 to 250 0 5,99416447,78189,9317.11 2 1 1ComCoalBlr3 Commercial Coal Coal >250 0 7,832439128,156241,2117.11 2 1 1ComGas1Blr1 Commercial Gas 1 Gas 1 <=10 27 7,91058181,5073.05 6 6 1ComGas1Blr2 Commercial Gas 1 Gas 1 >10 to 100 4 5,064355,82510,7243.05 6 6 1ComGas1Blr3 Commercial Gas 1 Gas 1 >100 to 250 1 4,29115826,54748,8743.05 6 6 1ComGas1Blr4 Commercial Gas 1 Gas 1 >250 1 1,73231853,45898,4173.05 6 6 1ComGas2Blr1 Commercial Gas 2 Gas 2 >10 to 100 1 7,591386,35011,6903.05 6 6 1ComGas2Blr2 Commercial Gas 2 Gas 2 >100 to 250 1 5,33414624,58645,2633.05 6 6 1ComHvyLiqBlr1 Commercial Heavy Liquid Heavy Liquid <=10 1 50069651,9022.95 6 6 1ComHvyLiqBlr2 Commercial Heavy Liquid Heavy Liquid >10 to 100 2 4,736518,24316,2542.95 3 1 1ComHvyLiqBlr3 Commercial Heavy Liquid Heavy Liquid >100 to 250 1 2,98019631,51162,1382.95 3 1 1ComLtLiqBlr1 Commercial Light Liquid Light Liquid <=10 0 5,14523907232.95 6 6 1ComLtLiqBlr2 Commercial Light Liquid Light Liquid >10 to 100 0 5,132376,14911,3992.95 3 1 1ComLtLiqBlr3 Commercial Light Liquid Light Liquid >100 to 250 0 5,15018430,55656,6422.95 3 1 1ComLtLiqBlr4 Commercial Light Liquid Light Liquid >250 0 4,652776128,821238,7942.95 3 1 1ComBmassBlr1 Commercial Wet Biomass Wet Biomass >10 to 100 0 8,7606014,30826,7657.15 6 2 1IndBagasseBlr1 Industrial Bagasse Bagasse >100 to 250 0 3,90322954,609102,1537.15 6 2 1IndBagasseBlr2 Industrial Bagasse Bagasse >250 0 4,668479114,206213,6387.15 6 2 1IndCoalBlr1 Industrial Coal Coal <=10 0 5,700102,9205,4957.15 6 5 1IndCoalBlr2 Industrial Coal Coal >10 to 100 0 5,9466819,96537,5777.11 2 1 1IndCoalBlr3 Industrial Coal Coal >100 to 250 0 6,75318854,776103,0977.11 2 1 1IndCoalBlr4 Industrial Coal Coal >250 0 7,721545135,812261,6217.11 2 1 1IndDryBmassBlr1 Industrial Dry Biomass Dry Biomass <=10 0 7,31948891,6637.05 6 5 1IndDryBmassBlr2 Industrial Dry Biomass Dry Biomass >10 to 100 0 7,1874711,00820,5787.05 6 2 1IndDryBmassBlr3 Industrial Dry Biomass Dry Biomass >100 to 250 0 7,64616738,77672,4867.05 6 2 1IndDryBmassBlr4 Industrial Dry Biomass Dry Biomass >250 0 8,421492114,463213,9737.05 6 2 1IndGas1Blr1 Industrial Gas 1 Gas 1 <=10 0 8,19658531,5703.05 6 6 1IndGas1Blr2 Industrial Gas 1 Gas 1 >10 to 100 0 6,955447,33913,5123.05 6 6 1IndGas1Blr3 Industrial Gas 1 Gas 1 >100 to 250 0 6,85516828,19651,9093.05 6 6 1IndGas1Blr4 Industrial Gas 1 Gas 1 >250 0 7,69542471,167131,0203.05 6 6 1IndGas2Blr1 Industrial Gas 2 Gas 2 <=10 0 4,46981,3682,5183.05 6 6 1IndGas2Blr2 Industrial Gas 2 Gas 2 >10 to 100 0 6,650457,63914,0643.05 6 6 1IndGas2Blr3 Industrial Gas 2 Gas 2 >100 to 250 0 7,20217829,85454,9623.05 6 6 1Control DeviceGroupsAppendix A-7 New Major Source Boilers Cost Detail for Option 4N (proposed option)FacilityID UnitIDComCoalBlr1 CommercialComCoalBlr2 CommercialComCoalBlr3 CommercialComGas1Blr1 CommercialComGas1Blr2 CommercialComGas1Blr3 CommercialComGas1Blr4 CommercialComGas2Blr1 CommercialComGas2Blr2 CommercialComHvyLiqBlr1 CommercialComHvyLiqBlr2 CommercialComHvyLiqBlr3 CommercialComLtLiqBlr1 CommercialComLtLiqBlr2 CommercialComLtLiqBlr3 CommercialComLtLiqBlr4 CommercialComBmassBlr1 CommercialIndBagasseBlr1 IndustrialIndBagasseBlr2 IndustrialIndCoalBlr1 IndustrialIndCoalBlr2 IndustrialIndCoalBlr3 IndustrialIndCoalBlr4 IndustrialIndDryBmassBlr1 IndustrialIndDryBmassBlr2 IndustrialIndDryBmassBlr3 IndustrialIndDryBmassBlr4 IndustrialIndGas1Blr1 IndustrialIndGas1Blr2 IndustrialIndGas1Blr3 IndustrialIndGas1Blr4 IndustrialIndGas2Blr1 IndustrialIndGas2Blr2 IndustrialIndGas2Blr3 IndustrialFF-TCI FF-TAC ESP -TCI ESP -TAC Scrubber -TCI Scrubber - TACTAC -IncreasedNAHCO3caustic CO- TCI CO- TAC D/F - TCI D/F - TAC---------------------------------15,447,0186,440,754--2,056,5924,004,044-174,87477,625--3,847,7081,085,858--1,047,387725,223-25,90711,500--2,604,383601,373--936,617300,380-6,4772,875--4,892,926970,013--2,294,002906,720-6,4772,875--1,002,880331,933--546,850235,277-6,4772,875--2,445,960598,011--1,524,637428,612-6,4772,875--583,643107,760--120,038155,877-6,4772,875------966,950447,317-12,9545,750------1,489,478413,110-6,4772,875-------------ACI ACI ---------ACI ACI ---------ACI ACI ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------Hg Control (FF) PM Control HCl ControlAdditional Hg or D/F Control(ACI)CO/Organic ControlAppendix A-7 New Major Source Boilers Cost Detail for Option 4N (proposed option)FacilityID UnitIDComCoalBlr1 CommercialComCoalBlr2 CommercialComCoalBlr3 CommercialComGas1Blr1 CommercialComGas1Blr2 CommercialComGas1Blr3 CommercialComGas1Blr4 CommercialComGas2Blr1 CommercialComGas2Blr2 CommercialComHvyLiqBlr1 CommercialComHvyLiqBlr2 CommercialComHvyLiqBlr3 CommercialComLtLiqBlr1 CommercialComLtLiqBlr2 CommercialComLtLiqBlr3 CommercialComLtLiqBlr4 CommercialComBmassBlr1 CommercialIndBagasseBlr1 IndustrialIndBagasseBlr2 IndustrialIndCoalBlr1 IndustrialIndCoalBlr2 IndustrialIndCoalBlr3 IndustrialIndCoalBlr4 IndustrialIndDryBmassBlr1 IndustrialIndDryBmassBlr2 IndustrialIndDryBmassBlr3 IndustrialIndDryBmassBlr4 IndustrialIndGas1Blr1 IndustrialIndGas1Blr2 IndustrialIndGas1Blr3 IndustrialIndGas1Blr4 IndustrialIndGas2Blr1 IndustrialIndGas2Blr2 IndustrialIndGas2Blr3 IndustrialTestingTCITesting(TAC)COMonitoringTCICOMonitoringTAC Opacity -TCIOpacity -TACPM CEMS -TCIPM CEMS -TACWSMonitoring -TCIWSMonitoring -TACBag LeakDetection -TCIBag LeakDetection -TACACI CarbonRate (TCI)ACI CarbonRate (TAC)------------------------------------------1,188,000289,742------656,100151,200688,500261,900--176,00042,925------97,20022,400102,00038,800--37,0009,024162,77353,303----24,3005,60025,5009,700--37,0009,024162,77353,303----24,3005,60025,5009,700--44,00010,731------24,3005,60025,5009,700--37,0009,024162,77353,303----24,3005,60025,5009,700--16,00016,000------24,3005,60025,5009,700--32,00032,000------48,60011,200----10,00010,000162,77353,303----24,3005,600------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------Testing and MonitoringAppendix A-7 New Major Source Boilers Cost Detail for Option 4N (proposed option)FacilityID UnitIDComCoalBlr1 CommercialComCoalBlr2 CommercialComCoalBlr3 CommercialComGas1Blr1 CommercialComGas1Blr2 CommercialComGas1Blr3 CommercialComGas1Blr4 CommercialComGas2Blr1 CommercialComGas2Blr2 CommercialComHvyLiqBlr1 CommercialComHvyLiqBlr2 CommercialComHvyLiqBlr3 CommercialComLtLiqBlr1 CommercialComLtLiqBlr2 CommercialComLtLiqBlr3 CommercialComLtLiqBlr4 CommercialComBmassBlr1 CommercialIndBagasseBlr1 IndustrialIndBagasseBlr2 IndustrialIndCoalBlr1 IndustrialIndCoalBlr2 IndustrialIndCoalBlr3 IndustrialIndCoalBlr4 IndustrialIndDryBmassBlr1 IndustrialIndDryBmassBlr2 IndustrialIndDryBmassBlr3 IndustrialIndDryBmassBlr4 IndustrialIndGas1Blr1 IndustrialIndGas1Blr2 IndustrialIndGas1Blr3 IndustrialIndGas1Blr4 IndustrialIndGas2Blr1 IndustrialIndGas2Blr2 IndustrialIndGas2Blr3 IndustrialTotal ControlCosts - TCITotal ControlCosts - TACTotal TestingandMonitoring -TAC Total TACFuel Savings(TAC cons FuelSavings------------------174,87977,625-77,62571,2526,37325,90811,500-11,50075,125(63,625)6,4772,875-2,87585,594(82,719)6,4772,875-2,875172,359(169,484)1,556,207570,08526,031596,11620,474575,6433,977,0731,029,49877,6271,107,12579,2701,027,855710,158266,51231,300297,8123,613294,199979,904453,06743,200496,26761,740434,5271,495,955415,98568,903484,888118,012366,876------------------------------------------------------------------------------------------------------------------------------------TOTALS(considering work practice allowances for natural gas/refinery gas units)Appendix A-7 New Major Source Boilers Cost Detail for Option 4N (proposed option)FacilityID UnitIDFuelCategory forUnitMACT FloorStandardFuelCategorySizeCategoryUnitCountOp HoursPer YearDesignCapacity(mmbtu/hr)Exhaust gasflow rate (dscfm)Actual gas flowrate (acfm) O2% HCl CG Hg CG PM CG Metals CGControl DeviceGroupsIndGas2Blr4 Industrial Gas 2 Gas 2 >250 0 8,09443472,979134,3553.05 6 6 1IndHvyLiqBlr1 Industrial Heavy Liquid Heavy Liquid <=10 0 5,13358571,6892.95 6 6 1IndHvyLiqBlr2 Industrial Heavy Liquid Heavy Liquid >10 to 100 0 6,325497,92515,6282.95 3 1 1IndHvyLiqBlr3 Industrial Heavy Liquid Heavy Liquid >100 to 250 0 5,29617427,98555,1862.95 3 1 1IndHvyLiqBlr4 Industrial Heavy Liquid Heavy Liquid >250 0 5,367629101,182199,5262.95 3 1 1IndLtLiqBlr1 Industrial Light Liquid Light Liquid <=10 1 4,55447151,3252.95 6 6 1IndLtLiqBlr2 Industrial Light Liquid Light Liquid >10 to 100 3 4,864457,53813,9742.95 3 1 1IndLtLiqBlr3 Industrial Light Liquid Light Liquid >100 to 250 2 3,57817829,48254,6512.95 3 1 1IndLtLiqBlr4 Industrial Light Liquid Light Liquid >250 1 5,24643171,433132,4152.95 3 1 1IndWetBmassBlr1 Industrial Wet Biomass Wet Biomass <=10 0 6,48641,0491,9637.15 6 5 1IndWetBmassBlr2 Industrial Wet Biomass Wet Biomass >10 to 100 0 8,2055312,71523,7867.15 6 2 1IndWetBmassBlr3 Industrial Wet Biomass Wet Biomass >100 to 250 0 7,82918744,50283,2467.15 6 2 1IndWetBmassBlr4 Industrial Wet Biomass Wet Biomass >250 0 8,218586139,714261,3547.15 6 2 1Appendix A-7 New Major Source Boilers Cost Detail for Option 4N (proposed option)FacilityID UnitIDC C lBl 1C ilIndGas2Blr4 IndustrialIndHvyLiqBlr1 IndustrialIndHvyLiqBlr2 IndustrialIndHvyLiqBlr3 IndustrialIndHvyLiqBlr4 IndustrialIndLtLiqBlr1 IndustrialIndLtLiqBlr2 IndustrialIndLtLiqBlr3 IndustrialIndLtLiqBlr4 IndustrialIndWetBmassBlr1 IndustrialIndWetBmassBlr2 IndustrialIndWetBmassBlr3 IndustrialIndWetBmassBlr4 IndustrialFF-TCI FF-TAC ESP -TCI ESP -TAC Scrubber -TCI Scrubber - TACTAC -IncreasedNAHCO3caustic CO- TCI CO- TAC D/F - TCI D/F - TACHg Control (FF) PM Control HCl ControlAdditional Hg or D/F Control(ACI)CO/Organic Control-------------------------------------------------------564,065176,581--86,350149,959-6,4772,875--ACI ACI --1,139,148610,167-19,4308,62557,611262,111ACI ACI --2,381,734703,562-12,9545,75087,054430,583ACI ACI --3,953,2871,354,866-6,4772,87574,022706,218--------------------------------------------Appendix A-7 New Major Source Boilers Cost Detail for Option 4N (proposed option)FacilityID UnitIDC C lBl 1C ilIndGas2Blr4 IndustrialIndHvyLiqBlr1 IndustrialIndHvyLiqBlr2 IndustrialIndHvyLiqBlr3 IndustrialIndHvyLiqBlr4 IndustrialIndLtLiqBlr1 IndustrialIndLtLiqBlr2 IndustrialIndLtLiqBlr3 IndustrialIndLtLiqBlr4 IndustrialIndWetBmassBlr1 IndustrialIndWetBmassBlr2 IndustrialIndWetBmassBlr3 IndustrialIndWetBmassBlr4 IndustrialTestingTCITesting(TAC)COMonitoringTCICOMonitoringTAC Opacity -TCIOpacity -TACPM CEMS -TCIPM CEMS -TACWSMonitoring -TCIWSMonitoring -TACBag LeakDetection -TCIBag LeakDetection -TACACI CarbonRate (TCI)ACI CarbonRate (TAC)Testing and Monitoring----------------------------------------------------------------------16,00016,000------24,3005,60025,5009,700--48,00048,000------72,90016,800--345,00016,80020,00020,000325,546106,606----48,60011,200--230,0008,20010,00010,000162,77353,303--158,00056,10024,3005,600--115,0006,100--------------------------------------------------------Appendix A-7 New Major Source Boilers Cost Detail for Option 4N (proposed option)FacilityID UnitIDC C lBl 1C ilIndGas2Blr4 IndustrialIndHvyLiqBlr1 IndustrialIndHvyLiqBlr2 IndustrialIndHvyLiqBlr3 IndustrialIndHvyLiqBlr4 IndustrialIndLtLiqBlr1 IndustrialIndLtLiqBlr2 IndustrialIndLtLiqBlr3 IndustrialIndLtLiqBlr4 IndustrialIndWetBmassBlr1 IndustrialIndWetBmassBlr2 IndustrialIndWetBmassBlr3 IndustrialIndWetBmassBlr4 IndustrialTotal ControlCosts - TCITotal ControlCosts - TACTotal TestingandMonitoring -TAC Total TACFuel Savings(TAC cons FuelSavingsTOTALS(considering work practice allowances for natural gas/refinery gas units)------------------------------656,892329,41531,300360,7154,651356,0641,216,190880,90381,600962,503147,091815,4122,481,7421,139,895146,0061,285,901383,517902,3844,033,7872,063,959131,1032,195,062464,6161,730,446------------------------

# APPENDIX A-8

Existing Major Source Boilers Cost Detail under Alternative Solid Waste

Definition

(See file named “ mjr-Impacts Appx A-8 ” for facility-specific cost estimates)Appendix B-1 Estimated Emission Reductions for Existing Major Source Boilers and Process HeatersSUMMARY - Baseline Emissions by Fuel TypeSUMMARY - Option 1E Emission REDUCTIONS SUMMARY - Option 4E Emission REDUCTIONSExisting Boilers and Process Heaters at Major Sources Existing Boilers and Process Heaters at Major Sources Existing Boilers andProcess Heaters at Major Sources Existing Boilers and Process Heaters at Major SourcesFuel Subcategory PollutantBaseline Emissions(tpy) Fuel Subcategory PollutantEmission Reductions(tpy) Fuel Subcategory PollutantEmission Reductions(tpy) Fuel Subcategory PollutantBaseline Emissions(tpy)Emission Reductions(tpy)biomass Hg 4.65E-01 biomass Hg 2.19E-01 biomass Hg 2.19E-01 biomass Hg 2.51E-01 1.80E-01420 boilers PM - filterable 27,925420 boilers PM - filterable 22,549420 boilers PM - filterable 22,493239 boilers PM - filterable 7,0305,353PM 2.5 19,076 PM 2.5 15,086 PM 2.5 15,063 PM 2.5 4,955 3,734HCl 1,866.0HCl 516.2HCl 515.9HCl 988.0506.9THC 5,555THC 1,326THC 1,326THC 1,576357VOC 3,189VOC 761VOC 761VOC 905205CO 236,504CO 107,536CO 107,511CO 58,44336,229Dioxin/Furans (total mass) 4.92E-04 Dioxin/Furans (total mass) 4.47E-04 Dioxin/Furans (total mass) 4.47E-04 Dioxin/Furans (total mass) 1.06E-04 1.24E-05HF 56HF 8HF 8HF 76113SO2 19,354SO2 11,172SO2 11,159SO2 7,6524,101Non-Hg Metals 300Non-Hg Metals 227Non-Hg Metals 227Non-Hg Metals 20117Coal Hg 9Coal Hg 7Coal Hg 7Coal Hg 86578 boilers PM - filterable 26,924578 boilers PM - filterable 17,067578 boilers PM - filterable 17,067525 boilers PM - filterable 11,5025,455PM 2.5 13,348 PM 2.5 8,514 PM 2.5 8,514 PM 2.5 5,365 2,432HCl 44,640 HCl 35,446 HCl 35,446 HCl 4,520 3,010THC 1,736THC 851THC 851THC 8,1743,954VOC 996VOC 489VOC 489VOC 4,6922,270CO 141,317CO 112,286CO 112,286CO 206,622176,806Dioxin/Furans (total mass) 3.15E-04 Dioxin/Furans (total mass) 2.93E-04 Dioxin/Furans (total mass) 2.93E-04 Dioxin/Furans (total mass) 2.24E-04 1.91E-04HF 1,353HF 804HF 804HF 2,82777SO2 383,228SO2 298,823SO2 298,823SO2 47,33628,616Non-Hg Metals 1,888Non-Hg Metals 768Non-Hg Metals 768Non-Hg Metals 1,75198Gas 1 Hg 9.11E-01 Gas 1 Hg 5.79E-01 Gas 1 Hg 9.11E-03 Gas 1 Hg 9.08E-01 2.98E-0110,783 boilers PM - filterable 12,17910,783 boilers PM - filterable 39010,783 boilers PM - filterable 12210,775 boilers PM - filterable 30,903309PM 2.5 12,179PM 2.5 390PM 2.5 122PM 2.5 30,903309HCl 872HCl 540HCl 9HCl 11,100111THC 8,620THC 4,800THC 86THC 15,494155VOC 4,948VOC 2,755VOC 49VOC 8,89389CO 62,719CO 41,551CO 627CO 296,5742,966Dioxin/Furans (total mass) 2.18E-04 Dioxin/Furans (total mass) 0.00E+00 Dioxin/Furans (total mass) 2.18E-06 Dioxin/Furans (total mass) 4.29E-04 4.29E-06HF 12,151HF 7,497HF 122HF 8,90989SO2 7,330SO2 6,962SO2 73SO2 84,509845Non-Hg Metals 116Non-Hg Metals 0Non-Hg Metals 1Non-Hg Metals 1151Gas 1 - Metal Furnaces Hg 0Gas 1 - Metal Furnaces Hg 0Gas 1 - Metal Furnaces Hg 0Gas 1 - Metal FurnacesHg 00749 boilers PM - filterable 516749 boilers PM - filterable 15749 boilers PM - filterable 5749 boilers PM - filterable 7698PM 2.5 516 PM 2.5 15 PM 2.5 5 PM 2.5 769 8HCl 40 HCl 21 HCl 0 HCl 354 4THC 3,948THC 3,846THC 39THC 3524VOC 2,266VOC 2,207VOC 23VOC 2022CO 18,731CO 18,656CO 187CO 8,97890Dioxin/Furans (total mass) 3.81E-05 Dioxin/Furans (total mass) 3.73E-05 Dioxin/Furans (total mass) 3.81E-07 Dioxin/Furans (total mass) 9.45E-06 9.45E-08HF 16HF 8HF 0HF 2502SO2 113SO2 89SO2 1SO2 1,68817Non-Hg Metals 10Non-Hg Metals 0Non-Hg Metals 0Non-Hg Metals 100Gas 2 Hg 2.04E-01 Gas 2 Hg 1.72E-01 Gas 2 Hg 1.72E-01 Gas 2 Hg 1.97E-01 1.65E-01199 boilers PM - filterable 1,774199 boilers PM - filterable -199 boilers PM - filterable 0196 boilers PM - filterable 2,181606PM 2.5 1,774.32PM 2.5 -PM 2.5 0.00PM 2.5 2,181.49606.01HCl 220HCl 220HCl 220HCl 180179THC 419THC 302THC 302THC 1,2281,178VOC 241VOC 173VOC 173VOC 705676CO 8,262CO 8,150CO 8,150CO 21,55621,434Dioxin/Furans (total mass) 2.21E-05 Dioxin/Furans (total mass) 2.16E-08 Dioxin/Furans (total mass) 2.16E-08 Dioxin/Furans (total mass) 2.66E-05 5.00E-06HF 28HF 27HF 27HF 869864SO2 7,029SO2 6,677SO2 6,677SO2 2,5122,387Non-Hg Metals 18Non-Hg Metals -Non-Hg Metals 0Non-Hg Metals 180Liquid Hg 0Liquid Hg -Liquid Hg 0Liquid Hg 00826 boilers PM - filterable 11,346826 boilers PM - filterable 10,468826 boilers PM - filterable 10,433791 boilers PM - filterable 4,1693,288PM 2.5 5,629 PM 2.5 5,293 PM 2.5 5,287 PM 2.5 1,268 952HCl 1,042HCl 845HCl 841HCl 1,4931,295THC 528THC 505THC 501THC 2,6262,547VOC 303VOC 290VOC 287VOC 1,5071,462CO 105,128CO 104,949CO 102,676CO 45,36444,781Dioxin/Furans (total mass) 5.76E-05 Dioxin/Furans (total mass) 5.37E-05 Dioxin/Furans (total mass) 5.33E-05 Dioxin/Furans (total mass) 1.07E-04 1.03E-04HF 46HF 34HF 34HF 1,05732SO2 24,823SO2 22,910SO2 22,784SO2 12,0158,126Non-Hg Metals 2,677Non-Hg Metals 2,230Non-Hg Metals 2,203Non-Hg Metals 2,5911,458SUMMARY - Alternative Solid Waste DefinitionAppendix B-1 Estimated Emission Reductions for Existing Major Source Boilers and Process HeatersSUMMARY - Baseline Emissions by Fuel TypeSUMMARY - Option 1E Emission REDUCTIONS SUMMARY - Option 4E Emission REDUCTIONSExisting Boilers and Process Heaters at Major Sources Existing Boilers and Process Heaters at Major Sources Existing Boilers andProcess Heaters at Major Sources Existing Boilers and Process Heaters at Major SourcesFuel Subcategory PollutantBaseline Emissions(tpy) Fuel Subcategory PollutantEmission Reductions(tpy) Fuel Subcategory PollutantEmission Reductions(tpy) Fuel Subcategory PollutantBaseline Emissions(tpy)Emission Reductions(tpy)SUMMARY - Alternative Solid Waste DefinitionTOTAL Hg 11TOTAL Hg 8TOTAL Hg 8TOTAL Hg 10713,555 boilers PM - filterable 80,66513,555 boilers PM - filterable 50,48913,555 boilers PM - filterable 50,12013,275 boilers PM - filterable 56,55415,019PM 2.5 52,523 PM 2.5 29,299 PM 2.5 28,992 PM 2.5 45,441 8,040HCl 48,680 HCl 37,587 HCl 37,032 HCl 18,635 5,106THC 20,806THC 11,630THC 3,105THC 29,4518,194VOC 11,942VOC 6,675VOC 1,782VOC 16,9044,703CO 572,662CO 393,127CO 331,437CO 637,537282,306Dioxin/Furans (total mass) 1.14E-03 Dioxin/Furans (total mass) 8.32E-04 Dioxin/Furans (total mass) 7.96E-04 Dioxin/Furans (total mass) 9.02E-04 3.15E-04HF 13,650HF 8,380HF 996HF 14,6721,077SO2 441,878SO2 346,633SO2 339,518SO2 155,71244,092Non-Hg Metals 5,009Non-Hg Metals 3,226Non-Hg Metals 3,199Non-Hg Metals 4,6871,575NOTES:2. Emission reductions for THC and VOC were calculated using the calculated percent reduction in CO emissions.3. Emission reductions for HF and SO2 were calculated using the unit's percent reduction in HCl emissions.1. Non-Hg Metallic HAP are shown in a separate summary table. Reductions in non-Hg Metallic HAP were estimated using the calculated percent reduction in PM emissions.Appendix B-2 Estimated Emission Reductions for New Major Source Boilers and Process HeatersSUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1N Emission REDUCTIONS SUMMARY - Option 4N Emission REDUCTIONSNew Boilers at Major Sources New Boilers at Major Sources New Boilers at Major SourcesFuel Subcategory PollutantEmissionReductions(tpy) Fuel Subcategory PollutantEmissionReductions(tpy) Fuel Subcategory PollutantEmissionReductions(tpy)biomass -0 boilers -biomass -0 boilers -biomass -0 boilers -Coal - 0 boilers -Coal - 0 boilers -Coal - 0 boilers -Gas 1Hg0Gas 1Hg0Gas 1Hg033 boilersPM - filterable1.07E+0133 boilersPM - filterable9.94E+0033 boilersPM - filterable1.07E-01PM 2.511PM 2.510PM 2.50HCl1HCl0HCl0THC2THC7.46E-01THC1.85E-02VOC1VOC0VOC0CO38CO15CO0Dioxin/Furans (total mass)0Dioxin/Furans (total mass)-Dioxin/Furans (total mass)0HF11HF7HF0SO25SO23SO20Non-Hg Metals0Non-Hg Metals0Non-Hg Metals0Gas 2Hg0Gas 2Hg0Gas 2Hg02 boilersPM - filterable62 boilersPM - filterable42 boilersPM - filterable4PM 2.56PM 2.54PM 2.54HCl1HCl1HCl1THC1THC1THC1VOC1VOC1VOC1CO67CO66CO66Dioxin/Furans (total mass)0Dioxin/Furans (total mass)-Dioxin/Furans (total mass)-HF0HF0HF0SO218SO216SO216Non-Hg Metals0Non-Hg Metals0Non-Hg Metals0liquidHg0liquidHg0liquidHg011 boilersPM - filterable13511 boilersPM - filterable12911 boilersPM - filterable129PM 2.524PM 2.523PM 2.523HCl10HCl9HCl9THC6THC5THC5VOC3VOC3VOC3CO44CO42CO42Dioxin/Furans (total mass)0Dioxin/Furans (total mass)0Dioxin/Furans (total mass)0HF1HF1HF1SO2527SO2462SO2462Non-Hg Metals1Non-Hg Metals1Non-Hg Metals1TOTALHg0TOTALHg0TOTALHg0.0046 boilersPM - filterable15146 boilersPM - filterable14346 boilersPM - filterable134PM 2.541PM 2.537PM 2.528HCl11HCl10HCl9THC9THC8THC7VOC5VOC4VOC4CO149CO124CO109Dioxin/Furans (total mass)8.51E-07Dioxin/Furans (total mass)5.83E-07Dioxin/Furans (total mass)5.85E-07HF12HF7HF1SO2551SO2481SO2478Non-Hg Metals1Non-Hg Metals1Non-Hg Metals1Appendix B-3 Estimated Emission Reductions for New Major Source Boilers and Process Heaters - with Corrected PM Baselines and ReductionsSUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1N Emission REDUCTIONS SUMMARY - Option 4N Emission REDUCTIONSNew Boilers at Major Sources New Boilers at Major Sources New Boilers at Major SourcesFuel Subcategory PollutantEmissionReductions (tpy) Fuel Subcategory PollutantEmissionReductions (tpy) Fuel Subcategory PollutantEmissionReductions (tpy)biomass -0 boilers -biomass -0 boilers -biomass -0 boilers -Coal - 0 boilers -Coal - 0 boilers -Coal - 0 boilers -Gas 1Hg0Gas 1Hg0Gas 1Hg033 boilersPM - filterable1.07E+0133 boilersPM - filterable9.94E+0033 boilersPM - filterable1.07E-01PM 2.511PM 2.510PM 2.50HCl1HCl0HCl0THC2THC7.46E-01THC1.85E-02VOC1VOC0VOC0CO38CO15CO0Dioxin/Furans (total mass)0Dioxin/Furans (total mass)-Dioxin/Furans (total mass)0HF11HF7HF0SO25SO23SO20Non-Hg Metals0Non-Hg Metals0Non-Hg Metals0Gas 2Hg0Gas 2Hg0Gas 2Hg02 boilersPM - filterable62 boilersPM - filterable42 boilersPM - filterable4PM 2.56PM 2.54PM 2.54HCl1HCl1HCl1THC1THC1THC1VOC1VOC1VOC1CO67CO66CO66Dioxin/Furans (total mass)0Dioxin/Furans (total mass)-Dioxin/Furans (total mass)-HF0HF0HF0SO218SO216SO216Non-Hg Metals0Non-Hg Metals0Non-Hg Metals0liquidHg0liquidHg0liquidHg011 boilersPM - filterable7911 boilersPM - filterable7411 boilersPM - filterable74PM 2.514PM 2.513PM 2.513HCl10HCl9HCl9THC6THC5THC5VOC3VOC3VOC3CO44CO42CO42Dioxin/Furans (total mass)0Dioxin/Furans (total mass)0Dioxin/Furans (total mass)0HF1HF1HF1SO2527SO2462SO2462Non-Hg Metals1Non-Hg Metals1Non-Hg Metals1TOTALHg0TOTALHg0TOTALHg0.0046 boilersPM - filterable9646 boilersPM - filterable8846 boilersPM - filterable78PM 2.531PM 2.527PM 2.518HCl11HCl10HCl9THC9THC8THC7VOC5VOC4VOC4CO149CO124CO109Dioxin/Furans (total mass)8.51E-07Dioxin/Furans (total mass)5.83E-07Dioxin/Furans (total mass)5.85E-07HF12HF7HF1SO2551SO2481SO2478Non-Hg Metals1Non-Hg Metals1Non-Hg Metals1Proposed OptionAppendix C-1 Secondary Impacts from Existing Units at Major Sources Under Regulatory Option 4EACIIncreasedCaustic Oxidation CatalystSolid Waste(tpy)Electricity(kWh/yr)Solid Waste(tpy)Electricity(kWh/yr) Water (gal/yr)Wastewater(gal/yr)Electricity(kWh/yr)Solid Waste(tpy) Solid Waste (tpy) Electricity (kWh/yr)Solid Waste(tpy) Water (gal/yr)Wastewater(gal/yr) Electricity (kWh/yr)Energy Savings(mmBtu/yr)<10 --------------->=10 16,855444,697,2888,50328,084,75736,207,89410,245,482109,366,409442-13,132,04225,79936,207,89410,245,482595,280,496189,451<10 --------------7>=10 17,188911,013,5121,5707,089,1172,343,024,987700,531,839506,332,55416,5803,9054,204,26239,2432,343,024,987700,531,8391,428,639,4455,361,096<10 --------------2,482,625>=10 --------------27,467,539<10 --------------197,928>=10 --------------689,845<10 --------------388>=10 1,729290,141,303--6,720,9452,759,460264,836,4926929637,9212,4316,720,9452,759,460555,615,7162,370,279<10 --------------35,327>=10 4467,06713,84499,645,64447,780,46316,420,966237,664,18749526,709,24213,90247,780,46316,420,966364,486,1412,862,870<10 --------------2,716,275>=10 35,7761,646,319,17023,916134,819,5182,433,734,290729,957,7461,118,199,64217,7643,91944,683,46781,3752,433,734,290729,957,7462,944,021,79838,941,08035,7761,646,319,17023,916134,819,5182,433,734,290729,957,7461,118,199,64217,7643,91944,683,46781,3752,433,734,290729,957,7462,944,021,79841,657,355TOTALSSize Category(mmBtu/hr)Overall TotalBiomassCoalGas 1Gas 1 Metal FurnacesGas 2LiquidTotalFuel CategoryWet ScrubberFabric Filter ESPAppendix C-2 Secondary Impacts from New Units at Major Sources Under Regulatory Option 4NACIIncreasedCaustic Oxidation CatalystSolid Waste(tpy)Electricity(kWh/yr)Solid Waste(tpy)Electricity(kWh/yr) Water (gal/yr)Wastewater(gal/yr)Electricity(kWh/yr)Solid Waste(tpy) Solid Waste (tpy) Electricity (kWh/yr)Solid Waste(tpy) Water (gal/yr)Wastewater(gal/yr)Electricity(kWh/yr)EnergySavings(mmBtu/yr)<10 --------------->=10 ---------------<10 --------------->=10 ---------------<10 37,187355--970970596,088-1219,60237,187970970816,0456,111>=10 71,69017--12,0177,1451,507,121-11,066,05171,69112,0177,1452,573,18928,566<10 --------------->=10 39,6195--5,4665,4661,205,704-2319,23939,6215,4665,4661,524,9488,554<10 83927--1,2311,23160,577-017,3338391,2311,23177,937479>=10 ----177,553127,4704,129,615435232,074,287458177,553127,4706,203,90256,712<10 38,025382--2,2012,201656,665-1236,93538,0262,2012,201893,9826,590>=10 111,30922--195,037140,0816,842,441435263,459,577111,770195,037140,08110,302,03993,832149,334403--197,238142,2827,499,106435273,696,512149,796197,238142,28211,196,021100,422Wet ScrubberFabric Filter ESPTOTALSSize Category(mmBtu/hr)Overall TotalBiomassCoalGas 1Gas 2LiquidTotalFuel Category