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 and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source 

1.0 INTRODUCTION 

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

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

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

existing units and new units projected to be operational by the year 2013, three years after the 

rule is expected to be promulgated. The results of the impacts analysis are presented for both the 

most stringent regulatory option evaluated and the regulatory option contained in the proposed 

rule. The development of the maximum achievable control technology (MACT) floor level of 

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

costs for various control technologies is presented in other memoranda.1,2,3 This memorandum is 

organized as follows: 

1.0 Introduction 

2.0 Overview of Regulatory Options 

3.0 Estimating Cost Impacts 

4.0 Methodology for Estimating Emission Reductions 

5.0 Methodology for Estimating Secondary Impacts 

6.0 References 
2.0 OVERVIEW OF REGULATORY OPTIONS 

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

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

2.1 Existing Units 

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

meet PM, HCl, mercury, CO, and 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 does not estimate ACI for units exceeding the 

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

testing for dioxin/furan will be below detection 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 option discussed in the preamble. In this 

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

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

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

process heaters less than 10 mmBtu/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 being proposed parallel with 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 analyze the regulatory impacts 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 alternative solid waste definition. 
2.2 New Units 

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

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

 Option 1N represents the option where all new boilers, 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 does not estimate ACI for units exceeding the 

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

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

control devices. 

 Option 4N represents the primary proposed option 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 gas/refinery gas and 

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

Metallurgical Process Furnace subcategories must meet a work practice standard of an 

annual boiler tune-up. 

3.0 ESTIMATING COST IMPACTS 

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

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

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

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

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

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

 The following logic 

was used to apply control, testing, 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 greater 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 installed. A new fabric filter was estimated to be 

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

filter emitting Hg above the MACT floor emission limit, the incremental Hg removal 

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

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

a packed bed scrubber and did not meet the 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 and process heaters. 

 Wet scrubbers—the technology selected for the 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 being 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 exceeded the MACT floor, the cost of an ESP 

was estimated, unless a fabric filter had already 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 achieving 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 baseline 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 boiler already reported to have a scrubber 

installed and the baseline emissions still exceeded 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 floor, 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 efficiency were used in the 

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

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

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

required at 2,538 existing boilers and process 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 installing an oxidation catalyst on the exhaust of a 

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

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

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

analyzed in the cost impacts analysis: 

o Most boilers (other than Dutch ovens and 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 monoxide (CO), but were less than or 

equal to 400 ppm @ 3% O2. 

o If the baseline CO emissions were between 400 and 1000 ppm @ 3% O2 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 (LBMS) was the technology estimated to 

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

were between 400 and 1000 ppm @ 3% O2. 

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

stokers, fuel cells, and fluidized bed boilers and process heaters 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% O2 and exceeded the MACT floor. 

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

not have replaceable burners. The design 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 compared 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% O2. LBMS costs were estimated for any 

Dutch oven boiler with baseline CO between 5,000 – 12,500 ppm @ 3% O2. If the 

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

ppm @ 3% O2, 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% O2. The cost of a replacement LNB was 

estimated if CO emissions were between 1200 – 3000 ppm @ 3% O2 and catalytic 

oxidation was estimated if CO baseline was greater than 3000 ppm @ 3% O2.

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 design capacity of the unit, and the 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 pollutants 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, and 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 boilers designed to burn 

liquid fuels were expected to conduct fuel analysis, or report fuel analyses received from a fuel 

supplier for chlorine and Hg. Conducting stack tests for PM, 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 stack test and the cost 

to conduct tests on PM and D/F and 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 would 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 stacks that do not have any test ports or test 

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

construct or rent scaffolding and install test ports. The costs include 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 additional $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 installed based on the size of the unit and the 

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

units expected to install packed 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 detection monitor was included in the cost analysis. 

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

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

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

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

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

cost of $14,660 for an opacity monitor was included 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 conduct an annual tune-up or energy audit. The 

Department of Energy has conducted energy assessments at selected manufacturing facilities and 
reports that facilities can reduce fuel/energy use by 10 to 15 percent by using best practices to 

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

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

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

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

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

installation of an LBMS are also expected to improve the efficiency of the unit, thus reducing 

fuel consumption. This cost analysis assumes an annual fuel savings of 1 percent. The energy 

savings is estimated using the Equation 1: 

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

Where: 

DC = unit design capacity (mmBtu/hr) 

CF = capacity factor, 90% of design capacity 

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

EG = Efficiency gain, estimated to be 1% 

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

industrial and commercial prices for 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 from units in the coal, liquid and natural gas and 

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

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

byproduct instead of a purchased fuel. 

3.2 Option 2E/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/furan. Instead, it is estimated that most units, when testing for 

dioxin/furan will be below detection levels without 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 small units (less than 10 mmBtu/hr) and units in the natural 

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

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

heater. For all units firing natural gas or refinery gas, regardless of the size 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 monitoring costs are associated with small 

units or units of any size designed to burn natural gas, refinery 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 addition 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 facilities are industrial. 

3.5 Option 5E 

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

system to filter the refinery gas 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 emissions 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 Facility ID: CAExxonMobilTorrance (unit ID 75-F-1) and only one test run was 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 reported for 75-F-1. After removing the outlier 

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

natural gas, and a combined average mercury 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 process heaters. EPA expected that a centralized 

adsorption system would provide economies of scale 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 install a carbon adsorption system to treat refinery gas. Since the 

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

substantially as a result of adjusting the baseline emission factor, the cost to install carbon 

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

refinery gas units was not included in the proposal. However, the estimated costs of installing 

carbon adsorbers at refineries are included 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 units in the natural gas/refinery gas and natural gas-fired 

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

natural gas or refinery gas, regardless of the size of the unit, the only 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 Alternative Solid Waste Definition 

 The impacts of the alternative solid waste definition follows the identical logic for 

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

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

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

analyzed under the parallel rulemaking effort for Commercial Industrial Solid Waste Incinerators 

if the units are located in the private sector. Should the alternative definition of solid waste 
become the final promulgated definition, the additional waste burning units located in the public 

sector will be analyzed under the forthcoming 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 heaters. 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 $106

 (2008) with capital recovery 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 Type for Existing Units under Option 4E 

Costs shown in $106

 (2008) with capital recovery estimated at 7% 

Fabric Filter ESP Wet Scrubber 

Increased 

Caustic 

Rate 

Combustion 

Controls 

and 

Oxidation 

Catalysts 

Activated Carbon 

Injection 

Energy 

Number of Audit 

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 existing and new facilities and it presents a summary of the results 

for the regulatory options 1E/1N and 4E/4N. 
4.1 Emission Reductions from Existing Boilers and Process Heaters 

The emission reductions analysis for existing 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 questionnaire (ICR No. 2286.01). Each 

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

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

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

Emission Reductions for Option 1E 

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

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

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

procedures and results of the MACT floor analysis 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 from baseline emissions for THC 

and VOC as was achieved for CO. Similarly, a percent reduction was also calculated for HCl. It 

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

baseline emissions for HF as was achieved for HCl. 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 from baseline for SO2. To calculate emission 

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

in PM was calculated in order to estimate total 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 configuration installed on the 

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

presented in other memoranda4

 To calculate emission reductions for PM2.5, the emission 

reductions for PM were multiplied by the applicable 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 emission rate on a heat input basis to an annual 

emission rate, Equation 2 was used: 

Annual Emission Rate (tpy) = ERHI * 0.0005 * Ophours (Equation 2)

Where:

ERHI = emission rate (lb/mmBtu) 

0.0005 = conversion factor, lbs per ton 

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

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

Equations 3 and 4 were used: 

Annual Emission Rate (tpy) = ERC * 0.000001 * ρair * QS * 60 * Ophours * 0.0005 * 

(20.946 – O2) / (20.946 – Std O2) (Equation 3)

Where:

ERC = emission concentration (ppm @ 3% O2) 

0.000001 = conversion factor, ppm to parts 

ρair = density of air, 0.0749 lb/dscf 

QS = exhaust flowrate (dscfm) 

60 = conversion factor, minutes to hours 

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

0.0005 = conversion factor, lb per ton 

20.946 = percentage of oxygen in ambient air 

O2 = percentage of oxygen assumed in exhaust gas 

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

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

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

Where:

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

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

QS = exhaust flowrate (dscfm) 

60 = conversion factor, minutes per hour 

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

0.000000001 = conversion factor, ng to g 

0.0022 = conversion factor, g per lb 

0.0005 = conversion factor, lb per ton 

20.946 = percentage of oxygen in ambient air 

O2 = percentage of oxygen assumed in exhaust gas 

Std O2 = 7 percent oxygen in standardized emission concentration for proposed rule. 
Converting concentrations to an annual emission rate required an oxygen concentration 

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

assumptions and estimates is presented in 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 operate for 8,400 hours per year (two weeks of 

downtime). 

Emission Reductions for Option 4E 

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

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

gas or refinery gas. For small units firing any type 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 expected 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 emissions was estimated by multiplying the baseline 

emissions for each unit by a factor of 0.01. 

Emission Reductions under the Alternative Solid Waste Definition 

 The same calculations discussed for estimating 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 baseline emissions were compared to the MACT floor emission limits 

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

methodology used to calculate the MACT floor emission limits under the alternative solid waste 

definition is discussed in another memorandum.1 

Incremental Emission Reductions if Energy Audit Findings are Implemented 

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

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

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

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

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

reduction to the emissions remaining after MACT level of controls were installed on the unit to 
identify the potential for additional emission reductions if the findings of an energy audit were 

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

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

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

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

and 10 percent. 

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

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

solid waste definition are located in Appendix B. 

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

Energy Audit 

 Assuming a Five Percent Efficiency Gain From Implementing Audit Findings 

Emission 

Reductions and 

Energy Savings 

Per Facility 

HCl 

Emission 

Reductions 

(tpy) 

Filterable 

PM 

Emission 

Reductions 

(tpy) 

Non-Hg 

Metals 

Emission 

Reductions 

(tpy) 

Hg 

Emission 

Reductions 

(tpy) 

VOC 

Emission 

Reductions 

(tpy) 

Energy 

Saved 

(mmBtu/yr) 

Annual Fuel 

Savings ($/yr) 

Min 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 consumption projections from the EIA, there are 

46 new boilers and process heaters expected to come on-line by 2013.5

 a discussion of the 

methodology used to project new boilers and process heaters is discussed 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 establish the PM NSPS limit for biomass boilers. New 

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

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

meet the SO2 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 SO2 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 stoker boilers are the most common type of solid 

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

of fuel. 

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 existing units within the same fuel category and 

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

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

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

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

from the new source MACT floor emission limit corresponding to each unit’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 Section 4.1 of this memorandum, the emission 

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

emissions assigned to each unit from the MACT 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 Emission Reductions from New Units

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

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

emission rates used were 0.1 lb/mmBtu for biomass 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 estimated emission reductions for both options 1N 

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

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

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

5.0 METHODOLOGY FOR ESTIMATING SECONDARY 

IMPACTS 

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

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

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

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

the impacts at existing units under proposed regulatory option 4 and new units under proposed 

regulatory option 1. Table 4-1 summarizes the cost, emission, and secondary impacts of this 

proposed NESHAP. Appendices C-1 and C-2 present a detailed breakdown of the secondary 
waste, water, and energy impacts from each subcategory 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 representing 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 therefore not expected to 

incur any secondary waste, water, or electricity impacts from these 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 conduct 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 calculated for every unit expected to install a 
scrubber to meet the HCl limits in the proposed rule. Both the water and wastewater calculations 

required the use of several constants and variables. 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 these constants are provided in another memorandum.2

 

The variables used to estimate the quantity of water required and wastewater 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 actual 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 and fly ash in fabric filters or ESP control 

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

caustic from increasing the caustic injection rate. Solid waste impacts 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 limits. 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 contribution from each of these control devices, 

the variables 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 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 was 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: exhaust flow rate from the combustion unit to the control device 

(acfm); the inlet loading of particulate matter to the control device (gr/acfm); operating hours 
(hr/year) and the efficiency of the control device required to meet the PM emission limits in the 

proposed NESHAP. 

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

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

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

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

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

(gr/acfm). 

For this analysis, the spent carbon collected from units with 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 necessary to meet the proposed NESHAP emission 

limits for mercury or dioxin/furan. The calculation required the use of six variables, including: 

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

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

based required removal efficiency of mercury or dioxin /furan. 

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

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

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

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

requirements are one output of the cost algorithms used in the analyses, so no additional 

calculations were necessary. For some units, an electrical demand from multiple control devices 

was estimated. The total national electricity demand in Table 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 these control devices, a set of variables 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 operate 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 payback can improvements in efficiency, thereby 

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

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

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

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

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

baseline operating efficiency of each unit. 

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

boiler or process heater, and the national energy savings presented 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, and liquid fuel categories only. 

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

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

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

4E, the water, wastewater, solid waste, and electricity 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. Secondary 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 expected 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 waste, 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 boilers. 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 Methodology 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 for 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 Delivered 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, and Institutional Facilities. April 2010. 

6. U.S. Department of Energy, EIA. Annual 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 1E

For units with a scrubber already installedbut not meeting HCl floor, no TCI, only TAC

Size

Category

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-On and 

Combustion Control 

Costs - TCI

Testing and Monitoring -

TAC

<10 Biomass 3,300,263 1,032,962 6,489,630 1,087,101 1,709,522 3,810,588 - 478,175 52,501 132,142 622,215 12,109,732 6,605,368 1,555,400 >=10 to 100 Biomass 181,037,995 48,778,404 100,286,013 15,412,059 71,252,936 37,379,018 - 21,373,493 7,851,917 4,752,661 37,021,350 378,703,097 146,442,747 13,363,031 

>100 to 250 Biomass 240,585,110 57,125,423 55,697,832 10,225,507 76,093,682 28,469,564 - 15,076,277 6,653,545 4,007,498 43,499,661 391,460,399 145,973,700 8,581,933 

>250 Biomass 985,562,507 229,318,420 51,095,944 9,042,247 237,522,306 139,887,264 - 15,462,381 6,322,647 10,006,008 171,323,230 1,299,649,146 555,893,807 16,703,394 SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 Coal - - 98,787 422,041 - 57,381 6,300 2,784 7,521 158,952 435,862 151,300 

>=10 to 100 Coal 158,883,020 37,100,785 5,059,951 770,785 90,885,691 33,254,201 17,227 1,978,682 264,854 4,475,792 30,999,993 261,283,137 102,407,845 7,648,326 

>100 to 250 Coal 852,136,257 192,999,256 10,136,769 1,685,703 544,846,026 220,720,401 1,546,439 3,808,521 849,357 16,618,399 174,307,762 1,427,545,971 592,108,918 27,413,537 >250 Coal 1,786,804,872 405,382,675 25,057,227 4,211,481 979,190,605 617,365,416 834,533 7,205,580 2,609,877 21,761,031 398,351,302 2,820,019,315 1,428,755,284 30,778,234 

SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 Gas 1 5,671,599,945 2,037,647,704 - - 547,692,492 1,058,737,518 - 51,029,151 20,024,992 2,775,136 5,326,946 6,273,096,723 3,121,737,159 190,621,238 

>=10 to 100 Gas 1 4,601,847,886 1,249,220,882 - - 931,624,816 582,653,373 386 23,991,798 9,709,725 2,574,011 15,535,530 5,560,038,511 1,857,119,897 82,443,059 >100 to 250 Gas 1 3,364,410,262 790,335,946 - - 900,631,346 298,791,997 - 6,873,770 3,035,277 546,828 4,562,134 4,272,462,206 1,096,725,354 63,500,317 

>250 Gas 1 3,522,770,560 824,542,794 - - 1,245,538,173 547,385,698 - 1,837,594 777,350 542,854 8,142,630 4,770,689,181 1,380,848,473 24,843,555 <10 Gas 2 1,617,229 430,773 - - 338,720 328,051 - 12,954 5,750 - - 1,968,903 764,574 52,062 

>=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 50,357,002 1,942,639 

>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 75,745,766 3,314,139 

>250 Gas 2 633,123,968 148,571,975 - - 471,401,765 196,344,892 5,606 375,655 166,750 228,009 2,116,086 1,105,129,397 347,205,309 5,132,193 SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 Liquid - - 1,791,243 293,893 14,105,316 34,446,590 - 60,609,423 42,245,863 830,693 4,355,232 77,336,676 81,341,579 6,608,561 

>=10 to 100 Liquid - - 181,738,163 27,872,171 118,150,867 67,283,063 - 127,428,537 56,617,326 6,696,466 34,792,927 434,014,033 186,565,486 9,985,605 

>100 to 250 Liquid - - 236,655,792 43,365,475 182,018,521 58,546,443 - 49,744,853 20,260,840 7,064,577 43,188,716 475,483,744 165,361,475 11,102,402 

>250 Liquid 7,974,695 1,546,299 287,073,394 49,043,967 370,607,939 185,168,220 3,037 18,229,829 7,358,640 6,568,301 70,504,018 690,454,159 313,624,181 9,859,322 

 6,101,244,027 22,320,541,793 961,081,957 163,010,390 6,923,254,910 4,157,264,378 2,407,228 412,247,735 ########## 89,628,928 1,044,770,883 30,706,755,323 11,656,019,788 515,600,248 

Combustion Controls and CO 

Oxidation Catalysts

Activated Carbon for D/F and Incremental 

Fabric Filter ESP Wet Scrubber Hg Control TOTA
Appendix A-2 Existing Major Source Boilers Cost Summary by Subcategory for Option 4E (proposed option)

For units with a scrubber already installedbut not meeting HCl floor, no TCI, only TAC

Size

Category

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 Biomass - - - - - - - - - 168,402 74,750 - >=10 to 100 Biomass 100,286,013 15,412,059 71,252,936 37,379,018 - 2,059,846 236,979 31,146 115,737 354,667,935 101,922,197 11,693,931 >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 >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 

SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 Coal 19,431 8,625 - >=10 to 100 Coal 158,883,020 37,100,785 5,059,951 770,785 90,885,691 33,254,201 17,227 1,978,682 264,854 1,604,496 5,889,425 258,411,841 77,297,277 7,097,626 

>100 to 250 Coal 852,136,257 192,999,256 10,136,769 1,685,703 544,846,026 220,720,401 1,546,439 2,969,237 423,381 4,778,569 23,831,263 1,414,866,856 441,206,443 25,976,337 

>250 Coal 1,786,804,872 405,382,675 25,057,227 4,211,481 979,190,605 617,365,416 834,533 954,121 193,477 2,704,551 23,496,077 2,794,711,376 1,051,483,658 29,319,934 SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 Gas 1 - - - - - - - - - - - 46,232,826 20,521,750 - 

>=10 to 100 Gas 1 - - - - - - - - - - - 20,175,855 8,955,625 - >100 to 250 Gas 1 - - - - - - - - - - - 5,777,484 2,564,500 - >250 Gas 1 - - - - - - - - - - - 2,454,783 1,089,625 - 

<10 Gas 2 12,954 5,750 - >=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 

>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 

>250 Gas 2 633,123,968 148,571,975 - - 471,401,765 196,344,892 5,606 375,655 166,750 228,009 2,116,086 1,105,129,397 347,205,309 5,132,193 SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 liquid 25,908 11,500 - <10 liquid 1,515,618 672,750 - 

>=10 to 100 liquid - - 177,080,323 27,151,707 54,727,522 27,775,972 - 1,953,470 516,632 31,073 177,427 233,792,388 55,621,737 3,155,524 >=10 to 100 liquid - - 4,657,840 720,464 63,423,345 39,507,090 - 349,748 155,250 - - 68,430,933 40,382,804 4,563,503 

>100 to 250 liquid - - 236,655,792 43,365,475 96,972,973 31,610,955 - 518,145 230,000 - - 334,146,911 75,206,430 5,461,412 >100 to 250 liquid - - - - 85,045,548 26,935,489 - 155,443 69,000 - - 85,200,991 27,004,489 4,794,604 

>250 liquid - - 287,073,394 49,043,967 251,906,908 129,338,957 - 284,980 126,500 - - 539,265,282 178,509,425 5,387,926 >250 liquid 7,974,695 1,546,299 - - 118,701,031 55,829,262 3,037 90,675 40,250 - - 126,766,401 57,418,848 4,004,196 

 862,810,719 3,747,810,036 952,801,085 161,629,395 3,281,515,737 1,630,688,521 2,406,842 13,913,181 2,898,701 9,471,858 56,847,117 9,489,080,770 3,086,408,416 135,625,891 

Notes:

Annualized Energy Audit Costs 

Total Incl. Facility-level Costs: 

1. Energy Audits are conducted once per facility for all facilities.

Combustion Controls and CO 

Oxidation Catalysts

Activated Carbon for D/F and Incremental 

Fabric Filter ESP Wet Scrubber Hg Control TOTA
For units with a 

scrubber already installed but not meeting HCl floor, no TCI, only TAC

Model FacilityID

Affected Sector

Standard Fuel Category

SizeCategory

Number of Projected Boilers

Op Hours Per Year

Design Capacity TCI TAC TCI TAC TCI TAC

Increased Scrubber 

Caustic TAC 

IndCoalBlr1 Industrial Coal <=10 0 5,700 10.0 - - - - - - -

IndDryBmassBlr1 Industrial Dry Biomass <=10 0 7,319 3.8 - - - - - - -

ComGas1Blr1 Commercial Gas 1 <=10 27 7,910 4.9 15,447,018 6,440,754 - - 2,056,592 4,004,044 -

IndGas1Blr1 Industrial Gas 1 <=10 0 8,196 5.1 - - - - - - -

IndGas2Blr1 Industrial Gas 2 <=10 0 4,469 8.1 - - - - - - -

ComHvyLiqBlr1 Commercial Heavy Liquid <=10 1 500 6.0 583,643 107,760 - - 120,038 155,877 -

IndHvyLiqBlr1 Industrial Heavy Liquid <=10 0 5,133 5.3 - - - - - - -

ComLtLiqBlr1 Commercial Light Liquid <=10 0 5,145 2.3 - - - - - - -

IndLtLiqBlr1 Industrial Light Liquid <=10 1 4,554 4.3 564,065 176,581 - - 86,350 149,959 -

IndWetBmassBlr1 Industrial Wet Biomass <=10 0 6,486 4.4 - - - - - - -

ComCoalBlr1 Commercial Coal >10 to 100 0 5,162 79.0 - - - - - - -

IndCoalBlr2 Industrial Coal >10 to 100 0 5,946 68.4 - - - - - - -

IndDryBmassBlr2 Industrial Dry Biomass >10 to 100 0 7,187 47.3 - - - - - - -

ComGas1Blr2 Commercial Gas 1 >10 to 100 4 5,064 34.7 3,847,708 1,085,858 - - 1,047,387 725,223 -

IndGas1Blr2 Industrial Gas 1 >10 to 100 0 6,955 43.7 - - - - - - -

ComGas2Blr1 Commercial Gas 2 >10 to 100 1 7,591 37.8 1,002,880 331,933 - - 546,850 235,277 -

IndGas2Blr2 Industrial Gas 2 >10 to 100 0 6,650 45.5 - - - - - - -

ComHvyLiqBlr2 Commercial Heavy Liquid >10 to 100 2 4,736 51.3 - - - - 966,950 447,317 -

IndHvyLiqBlr2 Industrial Heavy Liquid >10 to 100 0 6,325 49.3 - - - - - - -

ComLtLiqBlr2 Commercial Light Liquid >10 to 100 0 5,132 37.1 - - - - - - -

IndLtLiqBlr2 Industrial Light Liquid >10 to 100 3 4,864 45.4 - - - - 1,139,148 610,167 -

ComBmassBlr1 Commercial Wet Biomass >10 to 100 0 8,760 60.0 - - - - - - -

IndWetBmassBlr2 Industrial Wet Biomass >10 to 100 0 8,205 53.3 - - - - - - -

IndBagasseBlr1 Industrial Bagasse >100 to 250 0 3,903 229.0 - - - - - - -

ComCoalBlr2 Commercial Coal >100 to 250 0 5,994 163.7 - - - - - - -

IndCoalBlr3 Industrial Coal >100 to 250 0 6,753 187.6 - - - - - - -

IndDryBmassBlr3 Industrial Dry Biomass >100 to 250 0 7,646 166.5 - - - - - - -

ComGas1Blr3 Commercial Gas 1 >100 to 250 1 4,291 158.0 2,604,383 601,373 - - 936,617 300,380 -

IndGas1Blr3 Industrial Gas 1 >100 to 250 0 6,855 167.8 - - - - - - -

ComGas2Blr2 Commercial Gas 2 >100 to 250 1 5,334 146.3 2,445,960 598,011 - - 1,524,637 428,612 -

IndGas2Blr3 Industrial Gas 2 >100 to 250 0 7,202 177.7 - - - - - - -

ComHvyLiqBlr3 Commercial Heavy Liquid >100 to 250 1 2,980 196.0 - - - - 1,489,478 413,110 -

IndHvyLiqBlr3 Industrial Heavy Liquid >100 to 250 0 5,296 174.1 - - - - - - -

ComLtLiqBlr3 Commercial Light Liquid >100 to 250 0 5,150 184.2 - - - - - - -

IndLtLiqBlr3 Industrial Light Liquid >100 to 250 2 3,578 177.7 - - - - 2,381,734 703,562 -

IndWetBmassBlr3 Industrial Wet Biomass >100 to 250 0 7,829 186.6 - - - - - - -

IndBagasseBlr2 Industrial Bagasse >250 0 4,668 478.9 - - - - - - -

ComCoalBlr3 Commercial Coal >250 0 7,832 439.0 - - - - - - -

IndCoalBlr4 Industrial Coal >250 0 7,721 545.3 - - - - - - -

IndDryBmassBlr4 Industrial Dry Biomass >250 0 8,421 491.5 - - - - - - -

ComGas1Blr4 Commercial Gas 1 >250 1 1,732 318.2 4,892,926 970,013 - - 2,294,002 906,720 -

IndGas1Blr4 Industrial Gas 1 >250 0 7,695 423.6 - - - - - - -

IndGas2Blr4 Industrial Gas 2 >250 0 8,094 434.4 - - - - - - -

IndHvyLiqBlr4 Industrial Heavy Liquid >250 0 5,367 629.4 - - - - - - -

ComLtLiqBlr4 Commercial Light Liquid >250 0 4,652 776.4 - - - - - - -

IndLtLiqBlr4 Industrial Light Liquid >250 1 5,246 430.5 - - - - 3,953,287 1,354,866 -

IndWetBmassBlr4 Industrial Wet Biomass >250 0 8,218 585.9 - - - - - - -

TOTALS: 46 31,388,583 10,312,284 - - 18,543,071 10,435,116 -

Wet Scrubber

Model Unit Input 

Parameters

Appendix A-3 New Major Source Boilers Cost Summary in 2013 by Subcategory for Option 1N Fabric Filter ESP
Model FacilityID

Affected Sector

Standard Fuel Category

SizeCategory

IndCoalBlr1 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 >250

TOTALS:

Appendix A-3 New Major Source Boilers Cost Summary in 2013 by Subcategory for Option 1N

TCI TAC TCI TAC

Total for all AddOn and 

Combustion 

Control Costs - 

TCI

Total for all Addon and 

Combustion 

Control Costs - 

TAC

Testing and 

Monitoring -TAC

Total TAC 

(Controls, Testing 

and Monitoring)

SumOfFuel 

Savings ($/yr)

Total TAC Considering Fuel Savings

 - - - - - - - - - -

 - - - - - - - - - -

 77,625 174,874 - - 17,678,484 10,522,423 702,842 11,225,265 109,178 11,116,087

 - - - - - - - - - -

 - - - - - - - - - -

 2,875 6,477 5,593 4,862 715,751 271,374 31,900 303,274 350 302,924

 - - - - - - - - - -

 - - - - - - - - - -

 2,875 6,477 4,673 21,257 661,565 350,672 36,600 387,272 4,103 383,169

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 11,500 25,907 - - 4,921,003 1,822,581 104,125 1,926,706 73,693 1,853,013

 - - - - - - - - - -

 2,875 6,477 - - 1,556,207 570,085 26,031 596,116 30,107 566,009

 - - - - - - - - - -

 5,750 12,954 40,522 183,344 1,020,426 636,411 54,200 690,611 56,639 633,972

 - - - - - - - - - -

 - - - - - - - - - -

 8,625 19,430 57,611 262,111 1,216,190 880,903 81,600 962,503 138,612 823,891

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 2,875 6,477 - - 3,547,477 904,629 77,627 982,256 71,148 911,108

 - - - - - - - - - -

 2,875 6,477 - - 3,977,073 1,029,498 77,627 1,107,125 81,905 1,025,220

 - - - - - - - - - -

 2,875 6,477 45,300 194,174 1,541,255 610,159 72,303 682,462 68,127 614,335

 - - - - - - - - - -

 - - - - - - - - - -

 5,750 12,954 87,054 430,583 2,481,742 1,139,895 146,006 1,285,901 265,799 1,020,102

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 2,875 6,477 - - 7,193,405 1,879,609 77,627 1,957,236 57,842 1,899,394

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 - - - - - - - - - -

 2,875 6,477 74,022 706,218 4,033,787 2,063,959 131,103 2,195,062 472,141 1,722,922

 - - - - - - - - - -

 132,250 297,933 314,776 1,802,549 50,544,364 22,682,199 1,619,591 24,301,790 1,429,645 22,872,145

Combustion Controls and 

CO Oxidation Catalysts

Activated Carbon for D/F and 

Incremental Hg Control TOTALS
For units with a 

scrubber already installed but not meeting HCl floor,no TCI, only TAC

Model FacilityID

Affected Sector

Standard Fuel Category

SizeCategory

Number of Projected Boilers

Op Hours Per Year

Design Capacity TCI TAC TCI TAC TCI TAC

Increased 

Scrubber Caustic 

TAC TCI 

IndCoalBlr1 Industrial Coal <=10 0 5,700 10 - - - - - - - - 

IndDryBmassBIndustrial Dry Biomass <=10 0 7,319 4 - - - - - - - - 

ComGas1Blr1Commercial Gas 1 <=10 27 7,910 5 15,447,018 6,440,754 - - 2,056,592 4,004,044 - 174,874 

 

IndGas1Blr1 Industrial Gas 1 <=10 0 8,196 5 - - - - - - - - 

IndGas2Blr1 Industrial Gas 2 <=10 0 4,469 8 - - - - - - - - 

ComHvyLiqBl Commercial Heavy Liquid <=10 1 500 6 583,643 107,760 - - 120,038 155,877 - 6,477 

 

IndHvyLiqBlr1Industrial Heavy Liquid <=10 0 5,133 5 - - - - - - - - 

ComLtLiqBlr1 Commercial Light Liquid <=10 0 5,145 2 - - - - - - - - 

IndLtLiqBlr1 Industrial Light Liquid <=10 1 4,554 4 564,065 176,581 - - 86,350 149,959 - 6,477 

 

IndWetBmassIndustrial Wet Biomass <=10 0 6,486 4 - - - - - - - - 

ComCoalBlr1 Commercial Coal >10 to 100 0 5,162 79 - - - - - - - - 

IndCoalBlr2 Industrial Coal >10 to 100 0 5,946 68 - - - - - - - - 

IndDryBmassBIndustrial Dry Biomass >10 to 100 0 7,187 47 - - - - - - - - 

ComGas1Blr2Commercial Gas 1 >10 to 100 4 5,064 35 3,847,708 1,085,858 - - 1,047,387 725,223 - 25,907 

 

IndGas1Blr2 Industrial Gas 1 >10 to 100 0 6,955 44 - - - - - - - - 

ComGas2Blr1Commercial Gas 2 >10 to 100 1 7,591 38 1,002,880 331,933 - - 546,850 235,277 - 6,477 

 

IndGas2Blr2 Industrial Gas 2 >10 to 100 0 6,650 45 - - - - - - - - 

ComHvyLiqBl Commercial Heavy Liquid >10 to 100 2 4,736 51 - - - - 966,950 447,317 - 12,954 

 

IndHvyLiqBlr2Industrial Heavy Liquid >10 to 100 0 6,325 49 - - - - - - - - 

ComLtLiqBlr2 Commercial Light Liquid >10 to 100 0 5,132 37 - - - - - - - - 

IndLtLiqBlr2 Industrial Light Liquid >10 to 100 3 4,864 45 - - - - 1,139,148 610,167 - 19,430 

 

ComBmassBl Commercial Wet Biomass >10 to 100 0 8,760 60 - - - - - - - - 

IndWetBmassIndustrial Wet Biomass >10 to 100 0 8,205 53 - - - - - - - - 

IndBagasseBl Industrial Bagasse >100 to 250 0 3,903 229 - - - - - - - - 

ComCoalBlr2 Commercial Coal >100 to 250 0 5,994 164 - - - - - - - - 

IndCoalBlr3 Industrial Coal >100 to 250 0 6,753 188 - - - - - - - - 

IndDryBmassBIndustrial Dry Biomass >100 to 250 0 7,646 167 - - - - - - - - 

ComGas1Blr3Commercial Gas 1 >100 to 250 1 4,291 158 2,604,383 601,373 - - 936,617 300,380 - 6,477 

 

IndGas1Blr3 Industrial Gas 1 >100 to 250 0 6,855 168 - - - - - - - - 

ComGas2Blr2Commercial Gas 2 >100 to 250 1 5,334 146 2,445,960 598,011 - - 1,524,637 428,612 - 6,477 

 

IndGas2Blr3 Industrial Gas 2 >100 to 250 0 7,202 178 - - - - - - - - 

ComHvyLiqBl Commercial Heavy Liquid >100 to 250 1 2,980 196 - - - - 1,489,478 413,110 - 6,477 

 

IndHvyLiqBlr3Industrial Heavy Liquid >100 to 250 0 5,296 174 - - - - - - - - 

ComLtLiqBlr3 Commercial Light Liquid >100 to 250 0 5,150 184 - - - - - - - - 

IndLtLiqBlr3 Industrial Light Liquid >100 to 250 2 3,578 178 - - - - 2,381,734 703,562 - 12,954 

 

IndWetBmassIndustrial Wet Biomass >100 to 250 0 7,829 187 - - - - - - - - 

IndBagasseBl Industrial Bagasse >250 0 4,668 479 - - - - - - - - ComCoalBlr3 Commercial Coal >250 0 7,832 439 - - - - - - - - 

IndCoalBlr4 Industrial Coal >250 0 7,721 545 - - - - - - - - 

IndDryBmassBIndustrial Dry Biomass >250 0 8,421 492 - - - - - - - - 

ComGas1Blr4Commercial Gas 1 >250 1 1,732 318 4,892,926 970,013 - - 2,294,002 906,720 - 6,477 

 

IndGas1Blr4 Industrial Gas 1 >250 0 7,695 424 - - - - - - - - 

IndGas2Blr4 Industrial Gas 2 >250 0 8,094 434 - - - - - - - - 

Model Unit Input Parameters 

Appendix A-4 New Major Source Boilers Cost Summary in 2013 by Subcategory for Option 4N (Proposed) Fabric Filter ESP Wet Scrubber

Combustion Cont

Oxidation Ca
Model 

FacilityID

Affected Sector

Standard Fuel Category

SizeCategory

Number of Projected Boilers

IndCoalBlr1 Industrial Coal <=10 0IndDryBmassBIndustrial Dry Biomass <=10 0

ComGas1Blr1Commercial 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 0IndBagasseBl Industrial 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 0IndBagasseBl Industrial 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 0

Appendix A-4 New Major Source Boilers Cost Summary in 2013 by Subcategory for Option 4N (Proposed)

Total for all Add-On

and Combustion 

Control Costs - TCI

Total for all Add-on 

and Combustion 

Control Costs - 

TAC

Testing and 

Monitoring -TAC

Total TAC 

(Controls, Testing 

and Monitoring)

SumOfFuel 

Savings ($/yr)

Total TAC Considering Fuel Savings

 - - - - - -

 - - - - - -

174,879 77,625 - 77,625 71,252 6,373

 - - - - - -

 - - - - - -

710,158 266,512 31,300 297,812 3,613 294,199

 - - - - - -

 - - - - - -

656,892 329,415 31,300 360,715 4,651 356,064

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 11,500 25,908 - 11,500 75,125 (63,625)

 - - - - - -

 570,085 1,556,207 26,031 596,116 20,474 575,643

 - - - - - -

979,904 453,067 43,200 496,267 61,740 434,527

 - - - - - -

 - - - - - -

 880,903 1,216,190 81,600 962,503 147,091 815,412

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 2,875 6,477 - 2,875 85,594 (82,719)

 - - - - - -

 1,029,498 3,977,073 77,627 1,107,125 79,270 1,027,855

 - - - - - -

 415,985 1,495,955 68,903 484,888 118,012 366,876

 - - - - - -

 - - - - - -

 1,139,895 2,481,742 146,006 1,285,901 383,517 902,384

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 2,875 6,477 - 2,875 172,359 (169,484)

 - - - - - -

 - - - - - -

TOTALS
For units with a 

scrubber already installed but not meeting HCl floor,no TCI, only TAC

Model FacilityID

Affected Sector

Standard Fuel Category

SizeCategory

Number of Projected Boilers

Op Hours Per Year

Design Capacity TCI TAC TCI TAC TCI TAC

Increased 

Scrubber Caustic 

TAC TCI 

Model Unit Input Parameters 

Appendix A-4 New Major Source Boilers Cost Summary in 2013 by Subcategory for Option 4N (Proposed) Fabric Filter ESP Wet Scrubber

Combustion Cont

Oxidation Ca

IndHvyLiqBlr4Industrial Heavy Liquid >250 0 5,367 629 - - - - - - - - 

ComLtLiqBlr4 Commercial Light Liquid >250 0 4,652 776 - - - - - - - - 

IndLtLiqBlr4 Industrial Light Liquid >250 1 5,246 431 - - - - 3,953,287 1,354,866 - 6,477 

 

IndWetBmassIndustrial Wet Biomass >250 0 8,218 586 - - - - - - - - 

TOTALS: 46 31,388,583 10,312,284 - - 18,543,071 10,435,116 - 297,933 

 
Model 

FacilityID

Affected Sector

Standard Fuel Category

SizeCategory

Number of Projected Boilers

Appendix A-4 New Major Source Boilers Cost Summary in 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 0

TOTALS: 46

Total for all Add-On

and Combustion 

Control Costs - TCI

Total for all Add-on 

and Combustion 

Control Costs - 

TAC

Testing and 

Monitoring -TAC

Total TAC 

(Controls, Testing 

and Monitoring)

SumOfFuel 

Savings ($/yr)

Total TAC Considering Fuel Savings

TOTALS

 - - - - - -

 - - - - - -

 2,063,959 4,033,787 131,103 2,195,062 464,616 1,730,446

 - - - - - -

 7,244,195 17,321,647 637,070 7,881,265 1,687,313 6,193,952
Appendix A-5 Existing Major Source Boilers Cost Summary in 2013 by Subcategory under Alternative Solid Waste Definition

For units with a scrubber already installedbut not meeting HCl floor, no TCI, only TAC

Size

Category

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-On and 

Combustion Control 

Costs - TCI

Testing and Monitoring -

TAC

<10 biomass 6,652,209 2,077,833 - - - - - 51,814 23,000 - - 51,816 23,000 - 

>=10 to 100 biomass 243,665,061 65,234,515 1,976,874 301,752 - - - 1,206,215 158,402 77,827 117,859 246,925,976 65,812,529 8,619,222 >100 to 250 biomass 233,327,170 54,550,568 3,985,325 712,622 1,922,912 809,277 - 567,637 66,651 - - 239,803,045 56,139,119 4,969,247 >250 biomass 753,768,037 174,857,025 9,117,491 1,701,276 - - - 645,662 107,676 - - 763,531,190 176,665,977 8,689,462 

SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

>=10 to 100 Coal 115,483,165 26,547,344 6,414,081 975,807 82,536,509 29,706,897 15,116 1,729,727 231,029 1,538,616 3,986,022 207,702,099 61,462,215 6,168,426 

>100 to 250 Coal 649,950,914 147,165,570 10,318,772 1,338,112 503,665,075 205,505,024 1,564,339 2,814,703 373,956 3,850,498 14,847,289 1,170,599,961 370,794,290 23,857,641 

>250 Coal 1,243,820,106 283,949,656 14,648,090 2,465,211 909,721,344 566,222,388 834,533 819,019 152,676 2,342,399 14,567,271 2,171,350,958 868,191,735 26,587,686 SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 Gas 1 5,676,731,393 2,039,299,884 - - 548,348,356 1,059,662,417 - 46,270,347 20,539,000 6,311 23,858 46,271,688 20,539,000 - >=10 to 100 Gas 1 4,591,378,266 1,246,830,609 - - 928,566,115 582,110,951 386 20,175,270 8,955,625 9,565 28,643 20,175,855 8,955,625 - 

>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 - 

>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 - <10 Gas 2 820,276 143,656 - - 179,761 165,898 - 6,477 2,875 - - 6,477 2,875 - 

>=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 

>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 

>250 Gas 2 585,379,328 137,642,011 - - 437,260,711 180,657,603 5,606 343,271 152,375 228,009 2,116,086 1,023,211,319 320,573,680 4,739,403 SizeCategory

MACT Floor 

Fuel 

Category TCI TAC TCI TAC TCI TAC

Increased 

Scrubber 

Caustic TAC TCI TAC TCI TAC

Total for all Add-On and 

Combustion Control 

Costs - TCI

Total for all Add-on and 

Combustion Control 

Costs - TAC

Testing and Monitoring -

TAC

<10 liquid - - 1,345,276 215,945 12,121,134 34,792,981 - 1,573,865 698,625 - - 1,573,911 698,625 - 

>=10 to 100 liquid - - 165,072,821 25,322,783 95,482,623 59,305,830 - 1,133,442 503,125 - - 261,688,886 85,131,737 7,214,326 

>100 to 250 liquid - - 203,104,549 37,297,500 142,917,376 46,634,965 - 602,344 267,375 - - 346,624,268 84,199,840 9,423,626 

>250 liquid 7,974,695 1,546,299 283,752,589 48,411,749 309,125,663 153,505,365 3,037 375,655 166,750 - - 601,228,603 203,633,200 9,392,122 

 5,864,533,383 21,272,336,861 699,735,868 118,742,756 6,247,197,544 3,807,526,894 2,423,018 87,156,297 36,323,515 8,053,225 35,687,028 7,561,566,942 2,451,226,564 115,093,779 

Notes:

Fabric Filter ESP Wet Scrubber

1. Energy Audits are conducted once per facility for all facilities.

Combustion Controls and CO 

Oxidation Catalysts

Activated Carbon for D/F and Incremental 

Hg Control TOTA
APPENDICES A-6a & A-6b 

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

Energy Audit Costs for Existing Major 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 

FacilityID UnitID

Fuel Category for Unit

MACT Floor Standard Fuel Category

Size Category

Unit Count

 Op Hours Per Year 

 Design Capacity (mmbtu/hr) 

 Exhaust gas flow rate (dscfm) 

 Actual gas flow rate (acfm) O2% 

ComCoalBlr1 Commercial Coal Coal >10 to 100 0 5,162 79 23,072 43,425 

 

ComCoalBlr2 Commercial Coal Coal >100 to 250 0 5,994 164 47,781 89,931 

 

ComCoalBlr3 Commercial Coal Coal >250 0 7,832 439 128,156 241,211 

 

ComGas1Blr1 Commercial Gas 1 Gas 1 <=10 27 7,910 5 818 1,507 

 

ComGas1Blr2 Commercial Gas 1 Gas 1 >10 to 100 4 5,064 35 5,825 10,724 

 

ComGas1Blr3 Commercial Gas 1 Gas 1 >100 to 250 1 4,291 158 26,547 48,874 

 

ComGas1Blr4 Commercial Gas 1 Gas 1 >250 1 1,732 318 53,458 98,417 

 

ComGas2Blr1 Commercial Gas 2 Gas 2 >10 to 100 1 7,591 38 6,350 11,690 

 

ComGas2Blr2 Commercial Gas 2 Gas 2 >100 to 250 1 5,334 146 24,586 45,263 

 

ComHvyLiqBlr1 Commercial Heavy Liquid Heavy Liquid <=10 1 500 6 965 1,902 

 

ComHvyLiqBlr2 Commercial Heavy Liquid Heavy Liquid >10 to 100 2 4,736 51 8,243 16,254 

 

ComHvyLiqBlr3 Commercial Heavy Liquid Heavy Liquid >100 to 250 1 2,980 196 31,511 62,138 

 

ComLtLiqBlr1 Commercial Light Liquid Light Liquid <=10 0 5,145 2 390 723 

 

ComLtLiqBlr2 Commercial Light Liquid Light Liquid >10 to 100 0 5,132 37 6,149 11,399 

 

ComLtLiqBlr3 Commercial Light Liquid Light Liquid >100 to 250 0 5,150 184 30,556 56,642 

 

ComLtLiqBlr4 Commercial Light Liquid Light Liquid >250 0 4,652 776 128,821 238,794 

 

ComBmassBlr1 Commercial Wet Biomass Wet Biomass >10 to 100 0 8,760 60 14,308 26,765 

 

IndBagasseBlr1 Industrial Bagasse Bagasse >100 to 250 0 3,903 229 54,609 102,153 

 

IndBagasseBlr2 Industrial Bagasse Bagasse >250 0 4,668 479 114,206 213,638 

 

IndCoalBlr1 Industrial Coal Coal <=10 0 5,700 10 2,920 5,495 

 

IndCoalBlr2 Industrial Coal Coal >10 to 100 0 5,946 68 19,965 37,577 

 

IndCoalBlr3 Industrial Coal Coal >100 to 250 0 6,753 188 54,776 103,097 

 

IndCoalBlr4 Industrial Coal Coal >250 0 7,721 545 135,812 261,621 

 

IndDryBmassBlr1 Industrial Dry Biomass Dry Biomass <=10 0 7,319 4 889 1,663 

 

IndDryBmassBlr2 Industrial Dry Biomass Dry Biomass >10 to 100 0 7,187 47 11,008 20,578 

 

IndDryBmassBlr3 Industrial Dry Biomass Dry Biomass >100 to 250 0 7,646 167 38,776 72,486 

 

IndDryBmassBlr4 Industrial Dry Biomass Dry Biomass >250 0 8,421 492 114,463 213,973 

 

IndGas1Blr1 Industrial Gas 1 Gas 1 <=10 0 8,196 5 853 1,570 

 

IndGas1Blr2 Industrial Gas 1 Gas 1 >10 to 100 0 6,955 44 7,339 13,512 

 

IndGas1Blr3 Industrial Gas 1 Gas 1 >100 to 250 0 6,855 168 28,196 51,909 

 

IndGas1Blr4 Industrial Gas 1 Gas 1 >250 0 7,695 424 71,167 131,020 

 

IndGas2Blr1 Industrial Gas 2 Gas 2 <=10 0 4,469 8 1,368 2,518 

 

IndGas2Blr2 Industrial Gas 2 Gas 2 >10 to 100 0 6,650 45 7,639 14,064 

 

IndGas2Blr3 Industrial Gas 2 Gas 2 >100 to 250 0 7,202 178 29,854 54,962 

 
Appendix A-7 New Major Source Boilers Cost Detail for Option 4N 

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 Industrial

 FF-TCI FF-TAC ESP -TCI ESP -TAC Scrubber -TCI Scrubber - TAC 

 TAC - Increased NAHCO3 caustic 

 - - - - - - - 

 - - - - - - - 

 - - - - - - -  6,440,754 15,447,018 - - 2,056,592 4,004,044 - 

 1,085,858 3,847,708 - - 1,047,387 725,223 - 

 601,373 2,604,383 - - 936,617 300,380 - 

 970,013 4,892,926 - - 2,294,002 906,720 - 

 331,933 1,002,880 - - 546,850 235,277 - 

 598,011 2,445,960 - - 1,524,637 428,612 - 

 107,760 583,643 - - 120,038 155,877 - 

 - - - - 966,950 447,317 - 

 - - - - 1,489,478 413,110 - 

 - - - - - - - 

ACI ACI - - - - - 

ACI ACI - - - - - 

ACI ACI - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

Hg Control (FF) PM Control HCl Control
Appendix A-7 New Major Source Boilers Cost Detail for Option 4N 

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 Industrial

 TestingTCI 

 Testing (TAC) 

 CO MonitoringTCI 

 CO MonitoringTAC Opacity -TCI 

 Opacity - TAC 

 PM CEMS - TCI 

 PM CEMS - TAC 

 WMoTC

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 289,742 1,188,000 - - - - - - 

 

 42,925 176,000 - - - - - - 

 

 9,024 37,000 162,773 53,303 - - - - 

 

 9,024 37,000 162,773 53,303 - - - - 

 

 10,731 44,000 - - - - - - 

 

 9,024 37,000 162,773 53,303 - - - - 

 

 16,000 16,000 - - - - - - 

 

 32,000 32,000 - - - - - - 

 

 10,000 10,000 162,773 53,303 - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

Testing and Monitoring
Appendix A-7 New Major Source Boilers Cost Detail for Option 4N 

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 Industrial

 Total Control Costs - TCI 

 Total Control Costs - TAC 

 Total Testing and Monitoring -TAC Total TAC Fuel Savings (

 TAC cons Fuel Savings 

 - - - - - -

 - - - - - -

 - - - - - -

 77,625 174,879 - 77,625 71,252 6,373 11,500 25,908 - 11,500 75,125 (63,625)

 2,875 6,477 - 2,875 85,594 (82,719)

 2,875 6,477 - 2,875 172,359 (169,484)

 570,085 1,556,207 26,031 596,116 20,474 575,643

 1,029,498 3,977,073 77,627 1,107,125 79,270 1,027,855

 266,512 710,158 31,300 297,812 3,613 294,199

 453,067 979,904 43,200 496,267 61,740 434,527

 415,985 1,495,955 68,903 484,888 118,012 366,876

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 TOTALS 

(considering work practice allowances for natural gas/refinery gas units) 
Appendix A-7 New Major Source Boilers Cost Detail for Option 4N 

FacilityID UnitID

Fuel Category for Unit

MACT Floor Standard Fuel Category

Size Category

Unit Count

 Op Hours Per Year 

 Design Capacity (mmbtu/hr) 

 Exhaust gas flow rate (dscfm) 

 Actual gas flow rate (acfm) O2% 

IndGas2Blr4 Industrial Gas 2 Gas 2 >250 0 8,094 434 72,979 134,355 

 

IndHvyLiqBlr1 Industrial Heavy Liquid Heavy Liquid <=10 0 5,133 5 857 1,689 

 

IndHvyLiqBlr2 Industrial Heavy Liquid Heavy Liquid >10 to 100 0 6,325 49 7,925 15,628 

 

IndHvyLiqBlr3 Industrial Heavy Liquid Heavy Liquid >100 to 250 0 5,296 174 27,985 55,186 

 

IndHvyLiqBlr4 Industrial Heavy Liquid Heavy Liquid >250 0 5,367 629 101,182 199,526 

 

IndLtLiqBlr1 Industrial Light Liquid Light Liquid <=10 1 4,554 4 715 1,325 

 

IndLtLiqBlr2 Industrial Light Liquid Light Liquid >10 to 100 3 4,864 45 7,538 13,974 

 

IndLtLiqBlr3 Industrial Light Liquid Light Liquid >100 to 250 2 3,578 178 29,482 54,651 

 

IndLtLiqBlr4 Industrial Light Liquid Light Liquid >250 1 5,246 431 71,433 132,415 

 

IndWetBmassBlr1 Industrial Wet Biomass Wet Biomass <=10 0 6,486 4 1,049 1,963 

 

IndWetBmassBlr2 Industrial Wet Biomass Wet Biomass >10 to 100 0 8,205 53 12,715 23,786 

 

IndWetBmassBlr3 Industrial Wet Biomass Wet Biomass >100 to 250 0 7,829 187 44,502 83,246 

 

IndWetBmassBlr4 Industrial Wet Biomass Wet Biomass >250 0 8,218 586 139,714 261,354 

 
Appendix A-7 New Major Source Boilers Cost Detail for Option 4N 

FacilityID UnitIDC C lBl 1 IndGas2Blr4 Industrial C ilIndHvyLiqBlr1 IndustrialIndHvyLiqBlr2 IndustrialIndHvyLiqBlr3 IndustrialIndHvyLiqBlr4 IndustrialIndLtLiqBlr1 IndustrialIndLtLiqBlr2 IndustrialIndLtLiqBlr3 IndustrialIndLtLiqBlr4 IndustrialIndWetBmassBlr1 IndustrialIndWetBmassBlr2 IndustrialIndWetBmassBlr3 IndustrialIndWetBmassBlr4 Industrial

 FF-TCI FF-TAC ESP -TCI ESP -TAC Scrubber -TCI Scrubber - TAC 

 TAC - Increased NAHCO3 caustic 

Hg Control (FF) PM Control HCl Control

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 176,581 564,065 - - 86,350 149,959 - 

ACI ACI - - 1,139,148 610,167 - 

ACI ACI - - 2,381,734 703,562 - 

ACI ACI - - 3,953,287 1,354,866 - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 

 - - - - - - - 
Appendix A-7 New Major Source Boilers Cost Detail for Option 4N 

FacilityID UnitIDC C lBl 1 IndGas2Blr4 Industrial C ilIndHvyLiqBlr1 IndustrialIndHvyLiqBlr2 IndustrialIndHvyLiqBlr3 IndustrialIndHvyLiqBlr4 IndustrialIndLtLiqBlr1 IndustrialIndLtLiqBlr2 IndustrialIndLtLiqBlr3 IndustrialIndLtLiqBlr4 IndustrialIndWetBmassBlr1 IndustrialIndWetBmassBlr2 IndustrialIndWetBmassBlr3 IndustrialIndWetBmassBlr4 Industrial

 TestingTCI 

 Testing (TAC) 

 CO MonitoringTCI 

 CO MonitoringTAC Opacity -TCI 

 Opacity - TAC 

 PM CEMS - TCI 

 PM CEMS - TAC 

 WMoTC

Testing and Monitoring

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 16,000 16,000 - - - - - - 

 

 48,000 48,000 - - - - - - 

 

 20,000 20,000 325,546 106,606 - - - - 

 

 10,000 10,000 162,773 53,303 - - 158,000 56,100 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 

 - - - - - - - - 

 
Appendix A-7 New Major Source Boilers Cost Detail for Option 4N 

FacilityID UnitIDC C lBl 1 IndGas2Blr4 Industrial C ilIndHvyLiqBlr1 IndustrialIndHvyLiqBlr2 IndustrialIndHvyLiqBlr3 IndustrialIndHvyLiqBlr4 IndustrialIndLtLiqBlr1 IndustrialIndLtLiqBlr2 IndustrialIndLtLiqBlr3 IndustrialIndLtLiqBlr4 IndustrialIndWetBmassBlr1 IndustrialIndWetBmassBlr2 IndustrialIndWetBmassBlr3 IndustrialIndWetBmassBlr4 Industrial

 Total Control Costs - TCI 

 Total Control Costs - TAC 

 Total Testing and Monitoring -TAC Total TAC Fuel Savings (

 TAC cons Fuel Savings 

 TOTALS 

(considering work practice allowances for natural gas/refinery gas units) 

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -

 329,415 656,892 31,300 360,715 4,651 356,064

 880,903 1,216,190 81,600 962,503 147,091 815,412

 1,139,895 2,481,742 146,006 1,285,901 383,517 902,384

 2,063,959 4,033,787 131,103 2,195,062 464,616 1,730,446

 - - - - - -

 - - - - - -

 - - - - - -

 - - - - - -
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 Heaters

SUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1E Emission REDUCTIONS SUMMARY - Option 4E Emission REDUCTIONS

Existing Boilers and Process Heaters at Major Sources Existing Boilers and Process Heaters at Major Sources Existing Boilers and Process Heaters at Major Sources Existing Boilers and Process Heaters at MajoFuel Subcategory Pollutant

Baseline Emissions (tpy) Fuel Subcategory Pollutant

Emission Reductions 

(tpy) Fuel Subcategory Pollutant

Emission Reductions (tpy) Fuel Subcategory Pollutant

biomass Hg 4.65E-01 biomass Hg 2.19E-01 biomass Hg 2.19E-01 biomass Hg 420 boilers PM - filterable 27,925 420 boilers PM - filterable 22,549 420 boilers PM - filterable 22,493 239 boilers PM - filterable 

PM 2.5 19,076 PM 2.5 15,086 PM 2.5 15,063 PM 2.5 HCl 1,866.0 HCl 516.2 HCl 515.9 HCl 

THC 5,555 THC 1,326 THC 1,326 THC 

VOC 3,189 VOC 761 VOC 761 VOC 

CO 236,504 CO 107,536 CO 107,511 CO 

Dioxin/Furans (total mass) 4.92E-04 Dioxin/Furans (total mass) 4.47E-04 Dioxin/Furans (total mass) 4.47E-04 Dioxin/Furans (total mHF 56 HF 8 HF 8 HF 

SO2 19,354 SO2 11,172 SO2 11,159 SO2 

Non-Hg Metals 300 Non-Hg Metals 227 Non-Hg Metals 227 Non-Hg Metals 

Coal Hg 9 Coal Hg 7 Coal Hg 7 Coal Hg 578 boilers PM - filterable 26,924 578 boilers PM - filterable 17,067 578 boilers PM - filterable 17,067 525 boilers PM - filterable 

PM 2.5 13,348 PM 2.5 8,514 PM 2.5 8,514 PM 2.5 HCl 44,640 HCl 35,446 HCl 35,446 HCl THC 1,736 THC 851 THC 851 THC 

VOC 996 VOC 489 VOC 489 VOC 

CO 141,317 CO 112,286 CO 112,286 CO 

Dioxin/Furans (total mass) 3.15E-04 Dioxin/Furans (total mass) 2.93E-04 Dioxin/Furans (total mass) 2.93E-04 Dioxin/Furans (total mHF 1,353 HF 804 HF 804 HF 

SO2 383,228 SO2 298,823 SO2 298,823 SO2 

Non-Hg Metals 1,888 Non-Hg Metals 768 Non-Hg Metals 768 Non-Hg Metals 

Gas 1 Hg 9.11E-01 Gas 1 Hg 5.79E-01 Gas 1 Hg 9.11E-03 Gas 1 Hg 10,783 boilers PM - filterable 12,179 10,783 boilers PM - filterable 390 10,783 boilers PM - filterable 122 10,775 boilers PM - filterable 

PM 2.5 12,179 PM 2.5 390 PM 2.5 122 PM 2.5 

HCl 872 HCl 540 HCl 9 HCl 

THC 8,620 THC 4,800 THC 86 THC 

VOC 4,948 VOC 2,755 VOC 49 VOC 

CO 62,719 CO 41,551 CO 627 CO 

Dioxin/Furans (total mass) 2.18E-04 Dioxin/Furans (total mass) 0.00E+00 Dioxin/Furans (total mass) 2.18E-06 Dioxin/Furans (total mHF 12,151 HF 7,497 HF 122 HF 

SO2 7,330 SO2 6,962 SO2 73 SO2 

Non-Hg Metals 116 Non-Hg Metals 0 Non-Hg Metals 1 Non-Hg Metals 

Gas 1 - Metal Furnaces Hg 0 Gas 1 - Metal Furnaces Hg 0 Gas 1 - Metal Furnaces Hg 0 Gas 1 - Metal Furnaces Hg 

749 boilers PM - filterable 516 749 boilers PM - filterable 15 749 boilers PM - filterable 5 749 boilers PM - filterable 

PM 2.5 516 PM 2.5 15 PM 2.5 5 PM 2.5 HCl 40 HCl 21 HCl 0 HCl THC 3,948 THC 3,846 THC 39 THC 

VOC 2,266 VOC 2,207 VOC 23 VOC 

CO 18,731 CO 18,656 CO 187 CO 

Dioxin/Furans (total mass) 3.81E-05 Dioxin/Furans (total mass) 3.73E-05 Dioxin/Furans (total mass) 3.81E-07 Dioxin/Furans (total mHF 16 HF 8 HF 0 HF 

SO2 113 SO2 89 SO2 1 SO2 

Non-Hg Metals 10 Non-Hg Metals 0 Non-Hg Metals 0 Non-Hg Metals 

Gas 2 Hg 2.04E-01 Gas 2 Hg 1.72E-01 Gas 2 Hg 1.72E-01 Gas 2 Hg 199 boilers PM - filterable 1,774 199 boilers PM - filterable - 199 boilers PM - filterable 0 196 boilers PM - filterable 

PM 2.5 1,774.32 PM 2.5 - PM 2.5 0.00 PM 2.5 

HCl 220 HCl 220 HCl 220 HCl 

THC 419 THC 302 THC 302 THC 

VOC 241 VOC 173 VOC 173 VOC 

CO 8,262 CO 8,150 CO 8,150 CO 

Dioxin/Furans (total mass) 2.21E-05 Dioxin/Furans (total mass) 2.16E-08 Dioxin/Furans (total mass) 2.16E-08 Dioxin/Furans (total mHF 28 HF 27 HF 27 HF 

SO2 7,029 SO2 6,677 SO2 6,677 SO2 

Non-Hg Metals 18 Non-Hg Metals - Non-Hg Metals 0 Non-Hg Metals 

Liquid Hg 0 Liquid Hg - Liquid Hg 0 Liquid Hg 826 boilers PM - filterable 11,346 826 boilers PM - filterable 10,468 826 boilers PM - filterable 10,433 791 boilers PM - filterable 

PM 2.5 5,629 PM 2.5 5,293 PM 2.5 5,287 PM 2.5 HCl 1,042 HCl 845 HCl 841 HCl 

THC 528 THC 505 THC 501 THC 

VOC 303 VOC 290 VOC 287 VOC 

CO 105,128 CO 104,949 CO 102,676 CO 

Dioxin/Furans (total mass) 5.76E-05 Dioxin/Furans (total mass) 5.37E-05 Dioxin/Furans (total mass) 5.33E-05 Dioxin/Furans (total mHF 46 HF 34 HF 34 HF 

SO2 24,823 SO2 22,910 SO2 22,784 SO2 

Non-Hg Metals 2,677 Non-Hg Metals 2,230 Non-Hg Metals 2,203 Non-Hg Metals 

SUMMARY - Alternative Solid Waste Definitio
Appendix B-1 Estimated Emission Reductions for Existing Major Source Boilers and Process Heaters

SUMMARY - Baseline Emissions by Fuel Type SUMMARY - Option 1E Emission REDUCTIONS SUMMARY - Option 4E Emission REDUCTIONS

Existing Boilers and Process Heaters at Major Sources Existing Boilers and Process Heaters at Major Sources Existing Boilers and Process Heaters at Major Sources Existing Boilers and Process Heaters at MajoFuel Subcategory Pollutant

Baseline Emissions (tpy) Fuel Subcategory Pollutant

Emission Reductions 

(tpy) Fuel Subcategory Pollutant

Emission Reductions (tpy) Fuel Subcategory Pollutant

SUMMARY - Alternative Solid Waste Definitio

TOTAL Hg 11 TOTAL Hg 8 TOTAL Hg 8 TOTAL Hg 13,555 boilers PM - filterable 80,665 13,555 boilers PM - filterable 50,489 13,555 boilers PM - filterable 50,120 13,275 boilers PM - filterable 

PM 2.5 52,523 PM 2.5 29,299 PM 2.5 28,992 PM 2.5 HCl 48,680 HCl 37,587 HCl 37,032 HCl THC 20,806 THC 11,630 THC 3,105 THC 

VOC 11,942 VOC 6,675 VOC 1,782 VOC 

CO 572,662 CO 393,127 CO 331,437 CO 

Dioxin/Furans (total mass) 1.14E-03 Dioxin/Furans (total mass) 8.32E-04 Dioxin/Furans (total mass) 7.96E-04 Dioxin/Furans (total mHF 13,650 HF 8,380 HF 996 HF 

SO2 441,878 SO2 346,633 SO2 339,518 SO2 

Non-Hg Metals 5,009 Non-Hg Metals 3,226 Non-Hg Metals 3,199 Non-Hg Metals 

NOTES: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 Heaters

SUMMARY - 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 Pollutant

 Emission Reductions (tpy) Fuel Subcategory Pollutant

 Emission Reductions (tpy) Fuel Subcategory Pollutant

 EmRed(tpy

biomass -0 boilers - biomass -0 boilers - biomass -0 boilers 

Coal - 0 boilers - Coal - 0 boilers - Coal - 0 boilers 

Gas 1 Hg 0 Gas 1 Hg 0 Gas 1 Hg 

33 boilers PM - filterable 1.07E+01 33 boilers PM - filterable 9.94E+00 33 boilers PM - filterable 

PM 2.5 11 PM 2.5 10 PM 2.5 

HCl 1 HCl 0 HCl 

THC 2 THC 7.46E-01 THC VOC 1 VOC 0 VOC 

CO 38 CO 15 CO 

Dioxin/Furans (total mass) 0 Dioxin/Furans (total mass) - Dioxin/Furans (total mass) 

HF 11 HF 7 HF 

SO2 5 SO2 3 SO2 

Non-Hg Metals 0 Non-Hg Metals 0 Non-Hg Metals 

Gas 2 Hg 0 Gas 2 Hg 0 Gas 2 Hg 

2 boilers PM - filterable 6 2 boilers PM - filterable 4 2 boilers PM - filterable 

PM 2.5 6 PM 2.5 4 PM 2.5 

HCl 1 HCl 1 HCl 

THC 1 THC 1 THC 

VOC 1 VOC 1 VOC 

CO 67 CO 66 CO 

Dioxin/Furans (total mass) 0 Dioxin/Furans (total mass) - Dioxin/Furans (total mass) 

HF 0 HF 0 HF 

SO2 18 SO2 16 SO2 Non-Hg Metals 0 Non-Hg Metals 0 Non-Hg Metals 

liquid Hg 0 liquid Hg 0 liquid Hg 

11 boilers PM - filterable 135 11 boilers PM - filterable 129 11 boilers PM - filterable 

PM 2.5 24 PM 2.5 23 PM 2.5 HCl 10 HCl 9 HCl 

THC 6 THC 5 THC 

VOC 3 VOC 3 VOC 

CO 44 CO 42 CO 

Dioxin/Furans (total mass) 0 Dioxin/Furans (total mass) 0 Dioxin/Furans (total mass) 

HF 1 HF 1 HF 

SO2 527 SO2 462 SO2 

Non-Hg Metals 1 Non-Hg Metals 1 Non-Hg Metals 

TOTAL Hg TOTAL 0 Hg TOTAL 0 Hg 

46 boilers PM - filterable 151 46 boilers PM - filterable 143 46 boilers PM - filterable 

PM 2.5 41 PM 2.5 37 PM 2.5 HCl 11 HCl 10 HCl 

THC 9 THC 8 THC 

VOC 5 VOC 4 VOC 

CO 149 CO 124 CO 

Dioxin/Furans (total mass) 8.51E-07 Dioxin/Furans (total mass) 5.83E-07 Dioxin/Furans (total mass) 

HF 12 HF 7 HF 

SO2 551 SO2 481 SO2 

Non-Hg Metals 1 Non-Hg Metals 1 Non-Hg Metals 
Appendix B-3 Estimated Emission Reductions for New Major Source Boilers and Process Heaters - with Corrected PM Baselines and Reductions

SUMMARY - 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 Pollutant

 Emission Reductions (tpy) Fuel Subcategory Pollutant

 Emission Reductions (tpy) Fuel Subcategory Pollutant

 EmRed

biomass -0 boilers - biomass -0 boilers - biomass -0 boilers 

Coal - 0 boilers - Coal - 0 boilers - Coal - 0 boilers 

Gas 1 Hg 0 Gas 1 Hg 0 Gas 1 Hg 

33 boilers PM - filterable 1.07E+01 33 boilers PM - filterable 9.94E+00 33 boilers PM - filterable 

PM 2.5 11 PM 2.5 10 PM 2.5 

HCl 1 HCl 0 HCl THC 2 THC 7.46E-01 THC 

VOC 1 VOC 0 VOC 

CO 38 CO 15 CO 

Dioxin/Furans (total mass) 0 Dioxin/Furans (total mass) - Dioxin/Furans (total mass) HF 11 HF 7 HF 

SO2 5 SO2 3 SO2 

Non-Hg Metals 0 Non-Hg Metals 0 Non-Hg Metals 

Gas 2 Hg 0 Gas 2 Hg 0 Gas 2 Hg 

2 boilers PM - filterable 6 2 boilers PM - filterable 4 2 boilers PM - filterable 

PM 2.5 6 PM 2.5 4 PM 2.5 HCl 1 HCl 1 HCl THC 1 THC 1 THC VOC 1 VOC 1 VOC CO 67 CO 66 CO Dioxin/Furans (total mass) 0 Dioxin/Furans (total mass) - Dioxin/Furans (total mass) HF 0 HF 0 HF 

SO2 18 SO2 16 SO2 Non-Hg Metals 0 Non-Hg Metals 0 Non-Hg Metals 

liquid Hg 0 liquid Hg 0 liquid Hg 

11 boilers PM - filterable 79 11 boilers PM - filterable 74 11 boilers PM - filterable 

PM 2.5 14 PM 2.5 13 PM 2.5 HCl 10 HCl 9 HCl THC 6 THC 5 THC VOC 3 VOC 3 VOC CO 44 CO 42 CO Dioxin/Furans (total mass) 0 Dioxin/Furans (total mass) 0 Dioxin/Furans (total mass) HF 1 HF 1 HF 

SO2 527 SO2 462 SO2 

Non-Hg Metals 1 Non-Hg Metals 1 Non-Hg Metals 

TOTAL Hg TOTAL 0 Hg TOTAL 0 Hg 46 boilers PM - filterable 46 boilers 96 PM - filterable 46 boilers 88 PM - filterable 

PM 2.5 31 PM 2.5 27 PM 2.5 HCl 11 HCl 10 HCl THC 9 THC 8 THC VOC 5 VOC 4 VOC CO 149 CO 124 CO 

Dioxin/Furans (total mass) 8.51E-07 Dioxin/Furans (total mass) 5.83E-07 Dioxin/Furans (total mass) 

HF 12 HF 7 HF 

SO2 551 SO2 481 SO2 

Non-Hg Metals 1 Non-Hg Metals 1 Non-Hg Metals 

Proposed Option
Appendix C-1 Secondary Impacts from Existing Units at Major Sources Under Regulatory Option 4E

ACI

Increased 

Caustic Oxidation Catalyst

Solid 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)

W

<10 - - - - - - - - - - - - 

 

>=10 16,855 444,697,288 8,503 28,084,757 36,207,894 10,245,482 109,366,409 442 - 13,132,042 25,799 36,207,894 

 

<10 - - - - - - - - - - - - 

 

>=10 17,188 911,013,512 1,570 7,089,117 2,343,024,987 700,531,839 506,332,554 16,580 3,905 4,204,262 39,243 2,343,024,987 

 

<10 - - - - - - - - - - - - 

 

>=10 - - - - - - - - - - - - 

 

<10 - - - - - - - - - - - - 

 

>=10 - - - - - - - - - - - - 

 

<10 - - - - - - - - - - - - 

 

>=10 1,729 290,141,303 - - 6,720,945 2,759,460 264,836,492 692 9 637,921 2,431 6,720,945 

 

<10 - - - - - - - - - - - - 

 

>=10 4 467,067 13,844 99,645,644 47,780,463 16,420,966 237,664,187 49 5 26,709,242 13,902 47,780,463 

 

<10 - - - - - - - - - - - - 

 

>=10 35,776 1,646,319,170 23,916 134,819,518 2,433,734,290 729,957,746 1,118,199,642 17,764 3,919 44,683,467 81,375 2,433,734,290 

 

 1,646,319,170 35,776 23,916 134,819,518 2,433,734,290 729,957,746 1,118,199,642 17,764 3,919 44,683,467 81,375 2,433,734,290 

 

Size Category 

(mmBtu/hr)

Overall Total

Biomass

Coal

Gas 1

Gas 1 Metal Furnaces

Gas 2

Liquid

Total

Fuel Category

Fabric Filter ESP Wet Scrubber
Appendix C-2 Secondary Impacts from New Units at Major Sources Under Regulatory Option 4N

ACI

Increased 

Caustic Oxidation Catalyst

Solid 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)

<10 - - - - - - - - - - - - 

>=10 - - - - - - - - - - - - 

<10 - - - - - - - - - - - - 

>=10 - - - - - - - - - - - - 

<10 37,187 355 - - 970 970 596,088 - 1 219,602 37,187 970 

>=10 71,690 17 - - 12,017 7,145 1,507,121 - 1 1,066,051 71,691 12,017 

<10 - - - - - - - - - - - - 

>=10 39,619 5 - - 5,466 5,466 1,205,704 - 2 319,239 39,621 5,466 

<10 839 27 - - 1,231 1,231 60,577 - 0 17,333 839 1,231 

>=10 - - - - 177,553 127,470 4,129,615 435 23 2,074,287 458 177,553 

<10 38,025 382 - - 2,201 2,201 656,665 - 1 236,935 38,026 2,201 

>=10 111,309 22 - - 195,037 140,081 6,842,441 435 26 3,459,577 111,770 195,037 

 403 149,334 - - 197,238 142,282 7,499,106 435 27 3,696,512 149,796 197,238 

Fabric Filter ESP Wet Scrubber 

Size Category 

(mmBtu/hr)

Overall Total

Biomass

Coal

Gas 1Gas 2

Liquid

Total

Fuel Category