MEMORANDUM 

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

FROM: Amanda Singleton and Susan McClutchey, ERG 

DATE: April 2010 

SUBJECT: Methodology for Estimating Control Costs for Industrial, Commercial, 

Institutional Boilers and Process Heaters National Emission Standards for 

Hazardous Air Pollutants – Major Source 

1.0 Introduction 

This memorandum discusses the algorithms and inputs used to estimate capital and 

annual control costs for the Major Source Industrial, Commercial, and Institutional Boilers and 

Process Heaters for the National Emission Standards for Hazardous Air Pollutants. Cost impacts 

were calculated for add-on control technologies, testing and monitoring, and work practices such 

as tune-ups and facility-wide energy audits. The add-on control costs were estimated for each 

individual boiler and process heater based on a combination of reported and standardized data, 

including fuel types, unit sizes, current control devices, and baseline emission values. 

Characteristics necessary to estimate control costs were assigned to specific units based on data 

reported by industry in the 2008 Questionnaire for Boilers, Process Heaters, Incinerators and 

Other Combustion Units1

 (ICR No. 2286.01, OMB Control No. 2060-0616, EPA Form No. 

5900-122), herein referred to as the “Boiler Survey,” and the data reported in the 2009 Test Plan 

for Boilers and Process Heaters2

 (ICR No. 2286.03, OMB Control No. 2060-0616, EPA Form 

No. 5900-122), herein referred to as the “Phase II Test Plan.” A data dictionary and description 

of all the fields contained in the database of reported industry data are summarized in other 

memoranda.3

 The standardization of reported emission data and the methodology used to assign 

baseline emission factors to each boiler and process heater in the unit inventory are also 

described in other memoranda.4, 5 
This memorandum is organized as follows: 

1.0 Introduction 

2.0 Inputs for Cost Algorithms 

3.0 Cost Algorithms for Add-on Control Devices 

4.0 Cost Algorithms and Inputs for Work Practices, Testing, and Monitoring 

5.0 References 

List of Appendices: 

Appendix A: Example Calculation of Exhaust Flow Rate, Percent Moisture, and 

Percent O2. 

Appendices B to I: Detailed Control Cost Algorithms 

Appendix J: Detailed Testing and Monitoring Cost Estimates 
2.0 Inputs for Cost Algorithms

Add-on control technologies are those that are applied to the vent gas stream of a boiler 

to reduce emissions before the stream enters the atmosphere. The boiler survey data include 

information on control devices currently installed on each combustion unit. Based on a review of 

controls installed on the boilers and process heaters, the controls expected to be needed to meet 

the proposed Maximum Achievable Control Technology MACT floor emission limits and 

analyzed for the impacts analysis include the fabric filter, electrostatic precipitator (ESP), packed 

bed scrubber, activated carbon injection, carbon bed adsorbers, replacement burners (assumed to 

be low-nitrogen oxide [NOx] burners), linkageless boiler management system, and carbon 

monoxide (CO) oxidation catalyst. In addition, for units that reported to have a scrubber already 

installed, the impacts analysis also analyzed the costs of increasing the caustic flowrate on an 

existing scrubber in order to improve scrubber efficiency. 

2.1 Components of Control Cost Algorithms 

 

When add-on technologies are used, consideration must be given to added expenses such 

as ductwork and associated equipment. The discussion of the algorithms used to calculate capital 

and annual costs of these devices and the inputs to the algorithms are presented in this section. 

Components of capital costs incorporated into the algorithms include: 

 Purchased equipment cost of the primary device and auxiliary equipment 

 Instrumentation 

 Sales tax and freight 

 Installation costs. Installation costs include structural needs such as foundations 

and support, handling and erection, piping, insulation, painting, engineering, 

construction, field expenses, contractor fees, start-up, performance tests, and 

contingencies. 

 Components of annual cost include: 

 Raw materials (e.g., catalysts) 

 Utilities (e.g., electricity, fuel, steam, air, water) 

 Waste treatment and disposal 
 Labor (operating, supervisory, maintenance) 

 Maintenance materials 

 Replacement parts 

 Overhead 

 Property taxes 

 Insurance 

 Administration charges 

 Capital recovery costs 

 For this analysis, all costs were estimated in 2008 dollars and annualized using an interest 

rate of 7 percent over the life of the equipment. Costs originally provided in years other than 

2008 were escalated to 2008 dollars using the Chemical Engineering Plant Cost index. 

 Table 1 gives the costs for components common to the costing algorithms for multiple 

control devices, along with the source of the information. 

Table 1: Costs of Common Components Used in Cost Estimate Algorithms 

Cost Component Cost (2008$) Source 

Weighted Labor Rate 51.26 U.S. Dept. of Labor—Bureau of Labor 

Statistics 

Electricity ($/kWh) 0.070 Energy Information Administration 

Water ($/gal) .0006 Electric Power Research Institute 

Waste Water Disposal ($/gal) .0054 Air Compliance Advisor User Guide—

Version 7.5 

Cost Factor for Caustic ($/ton) 600 Purchasing.com 

Activated Carbon ($/lb) 1.38 The Innovation Group. Chemical Profiles: 

Carbon, Activated. 2002 and Norit vendor 

data. 

Dust Disposal ($/ton) 42.14 NSWMA’s 2005 Tip Fee Survey 

Compressed Air ($/1000 ft3) 0.31 P2Pays.Org Energy Tips 

Catalyst Cost ($/ft3) 959.25 OAQPS Control Cost Manual—Chapter 2 

 

The labor rate was based on the May 2008 hourly mean wage reported for occupational 

code for Stationary Engineers and Boiler Operators (SOC code 518021) across the following 
four industries: Electric Power Generation, Transmission and Distribution (221100); Pulp, Paper 

and Paperboard Mills (322100); Chemical Manufacturing (325000); and Colleges, Universities 

and Professional Schools (611300). All of these industries have several facilities expected to be 

subject to the proposed standard. The average raw wage for these four industries was $24.41, and 

to account for benefits and overhead, a factor of 110 percent of the raw wage was applied to 

estimate a loaded hourly wage. 

 The cost for caustic has ranged widely over the last several years due to rapid swings in 

the national economy. Caustic costs have ranged from $300 to $800 per ton. A mid-range value 

of $600 per ton was used for this impacts analysis. 

 The cost algorithms for the control devices were obtained primarily from previous EPA 

studies and regulatory development projects, including the OAQPS Control Cost Manual 

(OCCM)7; the 2009 Hospital Medical Waste Incinerator New Source Performance Standards and 

Emission Guidelines (HMWI)8

; and the algorithms used to estimate the cost impacts under the 

vacated NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters9. The 

OCCM contains the detailed cost procedures and algorithms for each control device. The 

appendices to this memorandum include cost algorithms reduced/simplified to basic equations 

from the EPA studies. 

 Installing air pollution control devices on existing boilers requires additional costs to 

retrofit the equipment. These costs are not included in the cost estimates of the OCCM or other 

sources. For this analysis, a factor of 1.4 was applied to the costs of installing a fabric filter, 

packed-bed scrubber, electrostatic precipitator and a CO oxidation catalyst as well as any duct 

work associated with the installation of these control devices. A factor of 1.3 in the EPA 

CueCost model represents a retrofit of medium difficulty. A factor of 1.2 was applied to the costs 

of installing activated carbon injection since this retrofit does not typically require a lot of 

additional space. A factor of 1.6 was applied to the costs of installing carbon adsorption 

technology. Because this technology is expected to be used predominantly at refineries, this 

higher factor, which represents a “difficult retrofit” in the EPA CueCost model, was used to 

account for the space constraints that often exist at refineries.10

2.2 Inputs to Control Cost Algorithms 

The inputs required to estimate the cost impacts include primary fuel type; exhaust gas 

flow rate (on both an actual and dry standard basis); flue gas temperature, oxygen, and moisture; 
baseline emissions entering the control device; target MACT floor emission rate or 

concentration; unit design capacity; and hours of operation. These inputs were either reported by 

industry in the 2008 Boiler Survey or 2009 Phase II testing, or they were calculated from the 

reported data. 

2.2.1 Reported Data Inputs 

Unit design capacity was reported in the Boiler Survey and standardized to million 

British Thermal Units per hours (mmBtu/hr). Discussions of how this parameter was 

standardized are contained in other memoranda.4 The Boiler Survey collected data on small gasfired units less than 10 mmBtu/hr, in aggregate, and the cost analysis assumed a design capacity 

size of 5 mmBtu/hr hour to estimate the costs of controlling these small boilers. 

Although hours of operation were reported for most of the units in the Boiler Survey, the 

cost analysis assumes 8,400 hours per year of operation for add-on controls with large capital 

expenditures, such as packed scrubbers, fabric filters, carbon bed adsorbers, CO oxidation 

catalysts, and electrostatic precipitators. This annual hour estimate was used to avoid 

underestimating the variable operating costs. The operating hours reported in the survey were 

used for the activated carbon injection, low-NOx burners (LNB), and increased scrubber caustic, 

as these technologies lack large capital expenditures and their cost estimates are more sensitive 

to the hours of operation of the combustion device. If hours of operation were not reported in the 

survey, 8,400 hours was used as the default, as this represents full-time operation accounting for 

a two-week downtime period for maintenance.

2.2.2 Calculated Data Inputs 

Baseline Emissions and MACT Floor Emissions 

Some control cost algorithms require a pollutant removal efficiency as an input to 

estimate variable operating costs. For example, scrubbers designed to remove 20 percent of 

hydrogen chloride (HCl) will operate at lower pumping rates and use less caustic than scrubbers 

designed to remove 85 percent of HCl emissions. The methodology used to assign baseline 

emission factors and estimate the MACT floor emissions for each subcategory is discussed in 

separate memoranda5, 6. To assign the appropriate inlet and outlet emission rates to each boiler in 

the cost analysis, a VLOOKUP table was created in Excel to map the appropriate emission value 

to each boiler based on the boiler fuel type, control devices installed, and combustor design.
Excess Air and Exhaust Temperature

Information concerning excess air (in percent) and exhaust temperature (in degrees 

Fahrenheit [°F]) was reviewed in an EPA publication on fossil fuel industrial boilers11 and in 

data reported in the Internal Combustion Coordinated Rulemaking ICCR for non-fossil fuel 

industrial boilers.12, 23 Based on the review of these information sources, gas and distillate oil 

model units were assigned a typical excess air value of 15 percent and an exhaust temperature of 

350°F. Residual oil model units were assigned a typical excess air value of 15 percent and an 

exhaust temperature of 400°F. Coal model units less than 400 MMBtu/hr were assigned a typical 

excess air value of 50 percent and an exhaust temperature of 400°F. Coal model units greater 

than 400 MMBtu/hr were assigned a typical excess air value of 30 percent and an exhaust 

temperature of 400°F. Model units with non-fossil material combinations were assigned a typical 

excess air value of 50 percent and an exhaust temperature of 400°F. 

Exhaust Flowrate, Moisture and Percent Oxygen

Information on exhaust gas flowrate, moisture content, and percent oxygen for boilers 

and process heaters was reported in the Boiler Survey on a limited basis, or in most cases, was 

not available. Therefore, these parameters were calculated from the combustion kinetics of 

burning the primary fuels. For this calculation, the hydrogen, carbon, nitrogen, oxygen, and 

water composition of the primary fuel is necessary. 

The primary fuel of each boiler and process heater was identified according to the 10 

percent fuel category listed in the Boiler Survey database. The methodology used to assign each 

combustion unit to a fuel category is discussed in another memorandum.5

 Next; each fuel 

category was assigned a fuel composition, as indicated in Table 2. 

Table 2: Boiler and Process Heater Fuel Categories in Database and their Corresponding 

Fuel Composition Equations 

Fuel Category from Boiler and 

Process Heater Inventory 

Fuel Composition Assumption for 

Combustion Kinetics Calculations 

Coal Sub-bituminous 

Coal Sub-bituminous over 400 MMBtu/hr 

Light Liquid Distillate Liquids 

Heavy Liquid Residual Liquids 

Dry Biomass Biomass (dry) 

Wet Biomass, Bagasse Biomass (wet) 

Gas 1 (NG only), Gas 1 (Other), Gas 2 Natural Gas 
An average heating value and material analysis data (in percent by weight) were obtained 

for hydrogen, carbon, nitrogen, ash, sulfur, and oxygen for each fuel.13 These average 

percentages and the elements’ molecular weights were used to calculate the theoretical amount 

of oxygen (in moles per hundred pounds of fuel [mole/100 lb fuel]) necessary for the combustion 

of the fuel. The ratio of nitrogen to oxygen in the atmosphere, the average heating value for 

natural gas, and the excess air percentage and exhaust temperature (discussed in Section 3.3) for 

gas model units were used to calculate the exhaust flowrate (actual cubic feet per minute [acfm]), 

exhaust moisture content (%), and exhaust oxygen content (%, dry basis) for gas model units. An 

example calculation is provided in Appendix A. 

3.0 Cost Algorithms for Add-on Control Devices 

3.1 Fabric Filter 

Fabric filters offer emission control for mercury (Hg), particulate matter (PM), and nonHg metallic HAP. The algorithms used to estimate capital and annual costs of fabric filters were 

based on those used in the October 2008 memo entitled Compliance Costs and Economic Inputs 

for Existing Hospital/Medical/Infectious Waste Incinerators14 (see Docket EPA–HQ–OAR–

2006–0534). The cost algorithms for estimating annual and capital costs are provided in 

Appendix B-1. The algorithms estimate the costs for a pulse-jet type fabric filter using felt bags. 

When fabric filters are applied to certain boilers designed to fire biomass fuels, a flame-retardant 

spray may be required to reduce fire hazards. The cost for the flame retardant has not been 

included in this cost analysis. Capital costs are based on the gross cloth area of the fabric filter, 

which is a function of the gas inlet flowrate. Annual costs include dust disposal, electricity, 

maintenance, labor, bag replacement, maintenance labor, compressed air, capital recovery costs, 

overhead, administrative costs, property taxes, and insurance. 

3.2 Electrostatic Precipitator 

 The Electrostatic Precipitator, or ESP, is commonly used to control PM emissions. The 

algorithms used to estimate capital and annual costs of ESPs came from Chapter 6 of the 

OCCM7. The ESP costs are based on a cold-side, dry-type ESP. Few, if any, hot-side ESPs are 

being specified for purchase. Capital costs are based on the total collection plate area, which is 

calculated from the gas inlet flowrate and the required removal efficiency. The cost algorithms 
for estimating capital and annual costs of ESPs reduced to basic equations are provided in 

Appendix C-1. Annual costs include dust disposal, electricity, maintenance materials, operating 

labor, maintenance labor, capital recovery costs, overhead, administrative, property taxes, and 

insurance. Appendix C-2 presents the values for the inputs used in this analysis. 

3.3 Packed Bed Scrubber 

Packed bed scrubbers are generally used to lower emissions of HCl, hydrogen fluoride 

(HF), and sulfur dioxide (SO2), although they also offer some Hg and PM control. The 

algorithms used to estimate capital and annual costs of packed bed scrubbers were obtained from 

Chapter 8 of the OCCM7

. The capital costs comprise the scrubber tower, packing, and pumps. 

Capital costs are based primarily on gas flowrate and required HCl removal efficiency to reduce 

the baseline HCl emissions to the targeted MACT floor emission limit. The cost algorithms for 

estimating capital and annual costs of packed scrubber equipment reduced to their basic 

equations for each are provided in Appendix D-1. Annual costs include caustic, wastewater 

disposal, water, electricity, maintenance, labor, capital recovery costs, overhead, administrative, 

property taxes, and insurance. Appendix D-2 presents the values for the inputs used in this 

analysis. 

3.4 Increased Caustic Rate 

Emissions of acid gases such as HCl can be reduced further by increasing the feed rate of 

lime or sodium bicarbonate (NaHCO3) caustic prior to the fabric filter. The cost to increase lime 

flow were estimated using the equations from the July 2009 analysis for the HMWI rulemaking. 

In the HMWI analysis, the costs for makeup lime and dust disposal were estimated for a dry 

sorbent injection system followed by a fabric filter (DIFF). These costs range from 

approximately $200/yr to $20,900/yr.15 Model costs to increase NaHCO3 flow were estimated 

using similar equations, with a slight difference based on the stoichiometry and molecular weight 

for NaHCO3. These costs range from approximately $800/yr to $81,600/yr.15. To estimate the 

increase in the caustic rate, the baseline HCl concentration was compared to the target MACT 

floor emission rate. Appendix E-1 presents the values for the inputs and the equations used to 

estimate the annual costs used in this analysis. There are no capital costs associated with this 

control option, as this incremental control is used in the cost analysis only when units with 

existing scrubbers or injection technologies need to increase the efficiency of those systems to 

meet the MACT floor emission limit. 
3.5 Activated Carbon Injection 

Activated carbon injection (ACI) offers emission control for Hg and can be used in 

addition to a fabric filter (ACI/FF) to increase Hg collection efficiency. ACI/FF is installed on 

two coal-fired boilers (OHRittmanSalt). In addition, injection of activated carbon has been 

demonstrated to remove dioxin/furan emissions from combustion equipment. Cost estimates for 

ACI were derived from the 2009 analysis for the HMWI rulemaking15, which was based on a 90 

percent reduction in Hg emissions and 98 percent reduction in dioxin/furan. Because some of the 

percent reductions required for boilers and process heaters to meet the proposed Hg or 

dioxin/furan MACT floor emission limits differ from 90 percent, a cost adjustment factor was 

created to scale these costs up or down. The cost adjustment factor represented the ratio of the 

pollutant removal efficiency required to meet the MACT floor emission limit over the 90 

percent. For example, if a boiler required an Hg removal efficiency of 95 percent, the cost 

adjustment factor would be 0.95/0.9, or 1.05. The cost estimates used in the HMWI rulemaking 

would be multiplied by 1.05 for this particular boiler to account for an increase in pollutant 

removal efficiencies. Appendix F-1 shows the inputs to the algorithm and the equations to 

estimate the capital and annual costs of ACI. 

3.6 Low-NOx Burner/Replacement Burner 

The quality and efficiency of combustion can be improved by replacing old burners with 

new replacement burners. This cost analysis assumes that a facility would replace a burner with a 

new LNB. Modern LNBs can reduce emissions of NOx, and CO. Not all combustor designs 

utilize a burner that can be replaced with a LNB. For example, stoker boilers and Dutch ovens 

use a grate to support the fuel instead of having a replaceable burner. Therefore, a replacement 

LNB was only considered to be a feasible control option for pulverized coal boilers and oil and 

gas boilers and process heaters. The equations used to estimate the costs of LNBs comes from 

vendor quotes provided in a 2005 memo titled, “Analysis of Combustion Controls for Reducing 

NOx Emissions from Coal-Fired EGUs in the WRAP Region.”16 According to this memo, capital 

costs for retrofitting boilers with LNBs ranged from $6 to $24 per kW capacity of the boiler, in 

2004$. Because these costs were based on utility-scale boilers, an upper end of the range—$20 

per kW capacity of the boiler—was used in this analysis and scaled to 2008$. The reported boiler 

design capacity was converted into a kW capacity to estimate the total capital investment cost. 

Fixed and variable annual costs to operate the burner are minimal. Annual operations and 

maintenance costs from the burner retrofit are a balance of the increased costs from additional 
auxiliary fan power consumption, increased difficulty of maintaining steam temperatures over 

the load range at reduced excess air, and higher maintenance demands, combined with cost 

savings as a result of increased boiler efficiency. The capital recovery factor for a LNB was 

based on a 15-year equipment life. The inputs and equations to estimate the capital and annual 

costs of a LNB are shown in Appendix G-1. 

3.7 Linkageless Boiler Management System 

The linkageless boiler management system (LBMS) improves the efficiency of a boiler 

and offers control of CO and other organic HAP using microprocessor technology to monitor 

data for several individually controlled channels such as fuel, air, flue-gas recirculation, and 

atomizing air. By monitoring and adjusting these parameters, an LBMS can be programmed to 

adjust the fuel-to-air ratios on the burner to maximize combustion efficiency. In addition, an 

LBMS employs separate individual, programmable fuel curves for each fuel type, eliminating the 

need to readjust the ratios when switching fuels. Further, when firing rates change, the individual 

stepper motors for each fuel and air function adjust to allow a burner to run minimal excess-air 

levels throughout the firing range. 

A 2008 quote from the U.S. Department of Energy provided the estimated cost of an 

LBMS.17 The quote included a note that LBMS costs are relatively fixed, regardless of the size 

of the boiler. A capital investment of $19,127 in 2008 dollars was used for the LBMS cost 

estimate in all cases where the installation of an LBMS was an appropriate control option for CO 

emissions. An annualized cost of $2,100 per boiler was estimated based on the capital recovery 

over a 15-year period at an interest rate of 7 percent. Literature indicates that the efficiency gains 

of an LBMS may offset any additional costs associated with installing the system, depending on 

the burner’s age, quality, and design, but these cost savings were considered under a separate 

section of the cost analysis.18 

3.8 CO Oxidation Catalyst 

The algorithms used to estimate capital and annual costs of a CO oxidation catalyst were 

based on the costs for catalytic oxidizers in Chapter 2 of the OCCM7

. The algorithms in the 

OCCM were specific to a broad size range of incineration units. Although the exhaust flowrates 

for some of the boilers for which control cost estimates were being made fell outside that size 

range, the equations were used in all cases because they offered the best available estimate. The 

algorithms used to estimate the capital and annual costs of a catalytic oxidizer are included in 
Appendix H-1. The capital cost is based primarily on exhaust flow rate. Annual costs include 

catalyst, electricity, maintenance, labor, capital recovery costs, overhead, administrative, 

property taxes, and insurance. 

3.9 Carbon Adsorber Beds 

Activated carbon bed adsorption was reported to be used at three facilities on 11 different 

boilers and process heaters in the Boiler Survey: 

 CTElectric Boat—nine boilers firing natural gas and fuel oil 

 NYAESGreenidgeDresden—one coal-fired boiler 

 TXMOTIVAEnterprisesPortArthur—one refinery gas-fired process heater 

Carbon adsorption is used to filter volatile organic contaminants out of gas streams with 

low to medium pollutant concentrations. Chapter 3 of the OCCM7 discusses the design and costs 

associated with fixed bed and canister adsorption systems. Activated carbon adsorption has been 

used to treat digester gases upstream of combustion for siloxanes and other gas contaminants that 

may foul combustion equipment. Other combustion equipment, such as the 2009 HWMI rule, 

identified carbon adsorption being used to control mercury at East Carolina University. Some 

technical limitations to mercury adsorption exist when there are low concentrations of mercury 

in the flue gas. Carbon bed adsorbers are commonly used as mercury control on gas fields in 

Eastern Europe an Asia where mercury concentrations range between 193 and 3,000 μg/Nm3

. 

 As a beyond-the-floor option for Hg control, EPA estimated the costs to reduce Hg 

emissions from refinery gas units using carbon adsorption. In estimating the annual cost of the 

carbon for the carbon bed, the amount required was assumed to be equivalent to that used in the 

ACI calculation in section 3.5 of this memorandum. The cost estimates are based on a 

centralized carbon adsorption system that would treat the refinery gas prior to it being combusted 

in boilers or process heaters co-located at the same facility. The costs do not reflect carbon 

regeneration; instead, the cost estimates include costs to purchase virgin carbon and dispose of 

spent carbon. The costs for disposal and carbon purchase are shown in Table 1 of this 

memorandum. The direct annual costs and overhead costs are based on estimates provided in a 

June 19, 2009 memo for the HMWI rule.15 Indirect annual costs for property taxes, insurance, 

construction, contractor fees, and contingencies were developed using factors from Table 1.3 of 

Chapter 3 of the OCCM6. The capital costs for installing a fixed carbon bed adsorption system 

were estimated using a factor of $20 to $30 per kW of installed capacity, based on literature for 

an integrated plasma gasification combined cycle system.19 The upper end of this range ($30 per 
kW) was used for this cost analysis. The inputs and equations used to estimate the capital and 

annual costs of a carbon adsorber are included in Appendix I-1. 

3.10 Duct Work and Auxiliary Equipment 

The algorithms used to estimate capital and annual costs of ductwork were obtained from 

Chapter 10 of the OCCM.7

 Capital costs include ductwork for any ESP, packed bed scrubber, or 

fabric filter installed on the unit. The number of duct lines is based on the exhaust flowrate, and 

it is estimated that 500 feet of duct work is required for every 154,042 of exhaust (in acfm) per 

control device. The 500 feet of ductwork was based on engineering judgment and previous 

experience on the distance between emission points and control devices in chemical facilities. 

Costs are based on ductwork diameter, which is a function of flue gas flowrate. Costs for 

ductwork also include elbows to connect the duct joints and fans to move the exhaust through the 

ductwork. The cost algorithms for estimating capital and annual costs for ductwork and auxiliary 

equipment are included in the individual appendices for Fabric Filters, Packed Bed Scrubbers, 

and ESP. Annual costs include electricity, maintenance and labor, capital recovery costs, 

overhead, administrative, property taxes, and insurance. 

4.0 Cost Algorithms and Inputs for Work Practices, Testing, 

and Monitoring 

 Some boilers were found to be emitting pollutant amounts very close to the allowable 

level. In these cases, add-on controls may not be necessary if less costly practices, such as 

regular tune-ups to ensure optimum equipment efficiency or occasional energy audits, are 

initiated. Further, under the proposed rule, there is a work practice standard in lieu of an 

emission limit for small boilers less than 10 mmBtu/hr and natural gas and refinery gas-fired 

boilers of all sizes. 

To demonstrate initial and continuous compliance with the proposed rule, testing, fuel 

analysis, and monitoring are required to varying degrees for certain affected sources. 

Consequently, tune-ups, energy audits, and testing and monitoring costs were incorporated into 

the cost estimates, which are discussed in this section. 

4.1 Tune-ups 

The estimated cost to conduct an annual tune-up on an industrial, commercial, or 

institutional boiler is based on the cost estimate provided by Dr. H.M. Eckerlin and E.W. 

Soderberg of the Industrial Extension Service USI Boiler Efficiency Program.20 Their report 
summarizes the findings and recommendations of an evaluation of boilers in state-owned 

facilities. Their report indicates that the initial set-up for a boiler tune-up ranges from $3,000 to 

$7,000 per boiler, and thereafter, an annual tune-up costs $1,000 per boiler per year. For this 

analysis, an average of $5,000 per boiler initial set-up cost was annualized over five years for an 

annualized cost of $1,580 per boiler. The USI study and other literature suggest that annual 

boiler tune-ups can improve combustion efficiency between 1 and 5 percent, and often the fuel 

savings cover the cost of conducting a tune-up. The cost estimate for the tune-up in this analysis 

includes inspection of the burner, cleaning and repairs to the burner as necessary, inspection and 

adjustment of the flame pattern, inspection and calibration of the air-to-fuel ratio controls, 

minimizing total emissions of CO consistent with the manufacturer’s specifications, and 

measurement of CO emissions before and after the tune-up. 

4.2 Energy Audits 

An energy audit provides a detailed assessment of the pattern of energy use within a 

facility, as well as a comprehensive energy-saving and costing analysis. A detailed description of 

relevant energy-saving technologies may also be included to help identify opportunities to reduce 

energy consumption. The cost of an energy audit depends on the area of a facility and the types 

of equipment installed there. Energy audits are conducted on a facility level rather than per 

combustion unit. For industrial facilities identified by NAICS codes 211, 212, 311, 312, 313, 

314, 316, 321, a cost of $75,000 was estimated for an energy audit. This estimate is based on 

costs presented to the 2009 Boiler Small Business Regulatory Flexibility Act panel by an 

affected small entity, Port Townsend Paper Company. The cost was annualized over five years at 

7 percent interest to estimate the annual cost impacts of the proposed rule. Commercial and 

institutional facilities are expected to pay substantially less than industrial facilities for energy 

audits. An estimate of $2,000 to $5,000 per energy audit was obtained from two utilities. This 

estimate was used to determine the cost impact of energy audits for all NAICS codes 

representing commercial and institutional facilities. An average of $3,500 per facility was 

annualized over five years at 7 percent to obtain an annualized cost estimate for energy audits at 

commercial facilities. 

 
4.3 Testing 

Capital and annual costs for testing include stack tests for PM, Hg, HCl, CO, and 

dioxin/furan. The proposed rule provides a compliance alternative to conduct a fuel analysis in 

lieu of a stack test for HCl and Hg, if the fuel contains less mercury or chlorine than the MACT 

floor emission limit for the appropriate subcategory. The proposed rule also provides compliance 

flexibility to sources that consecutively test at 90 percent or less of the emission limits. The 

flexibility allows these sources to test at three-year intervals instead of annually. Because the 

number of sources expected to qualify for the three-year interval is unknown, and all sources 

must test annually for the first three years of compliance, this cost analysis is based on an annual 

testing frequency. The cost analysis also assumes that every solid fuel unit will conduct testing 

for all pollutants annually, and liquid fuel units will conduct stack testing for PM, CO, and 

dioxin/furan and fuel analysis for Hg and chlorine. Testing cost estimates were based on those 

used in the Phase II Test Plan and were adjusted downward slightly to account for a lower 

number of pollutants being tested. The testing costs assume that all pollutants will be tested 

simultaneously, or over the course of a single travel occurrence for a testing contractor. For the 

simpler methods (e.g., PM), the testing costs range from $5,000 to $7,000. For the pollutants that 

involve more lab analysis (e.g., Hg), the testing costs range from $10,000 to $15,000. Although 

the cost ranges can be applied, as is done for cases where a single pollutant is being measured, 

estimating costs for facilities that need test data for more than one pollutant is more difficult and 

uncertain. For example, if a facility needs PM and CO data, the test costs would not be twice the 

$5,000 to $7,000 price, because some of the costs are associated with getting the testing 

contractor to the site and setting up the equipment (these are one-time costs, such as port 

installation and scaffolding costs described below and would not be duplicated regardless of the 

number of pollutants tested). Therefore, if a facility had more than one of the simpler tests to run 

(e.g., PM and CO or PM and HCl), then the site-specific costs would start in the $5,000 to 

$7,000 range with a few thousand dollars added for the second pollutant. If a facility needed PM 

data and dioxin/furan data, then the site-specific costs would be the sum of the tests in the $5,000 

to $7,000 and $10,000 to $15,000 ranges. See the 2009 Phase II Test Plan for a discussion of the 

testing cost estimates.2

 A summary of the testing and monitoring costs used in this cost analysis 

is presented in Appendix J-1. 

The costs associated with installing test ports and renting scaffolding for stacks without 

test ports were also estimated, based on a preliminary engineering estimate provided by ERG Air 
Laboratory Staff. The assumptions included the installation of four ports at a minimum cost of 

$2,537 per port after adjusting to $2008 and applying a 1.4 retrofit factor. In addition to the cost 

of the port installation, an average cost for 2 days of per diem expenses and airfare of $835.31 

was included in the cost of each installation for a technician to complete the installation and 

testing of the ports. This comes to an estimated $11,000 per boiler to install ports for testing. 

The cost of temporary scaffolding was also included in the cost estimate for testing. An 

assumption of three weeks of scaffolding to install ports and two additional weeks to conduct 

stack testing led to an estimate of $14,000 per boiler for scaffolding. 

4.4 Monitoring 

Monitoring costs are included for opacity monitoring (for units without scrubbers) or PM 

continuous emissions monitoring systems (CEMS) (for units greater than 250 mmBtu/hr), bag 

leak detection (for units with fabric filters), scrubber parametric monitoring (for units with 

scrubbers), and CO monitors (for units greater than 100 mmBtu/hr). Cost estimates for CO 

monitors were developed using the 2007 EPA CEMS cost model.21 Cost estimates for bag leak 

detection, PM CEMS, and wet scrubber parametric monitoring were based on estimates used in 

the 2009 HMWI rulemaking.13 Cost estimates for opacity monitoring were based on a 1997 

memorandum prepared for the HMWI rulemaking, and escalated to 2008 dollars.22 Monitoring 

costs include the costs for planning, selecting, and installing monitoring equipment and support 

facilities; conducting an annual relative accuracy test audit and writing the report; performing 

cylinder gas audits; developing a QA/QC plan; monitoring operations and maintenance; and 

performing capital recovery. CO monitors were annualized over a 10-year lifetime using 

guidance from the 2007 EPA CEMS cost model. Bag leak detection, PM CEMS, and wet 

scrubber parametric monitoring were all annualized over a 20-year lifetime. A summary of the 

monitoring costs is presented in Appendices J-2 and J-3. 

5.0 References 

1. U.S. Environmental Protection Agency. 2008 Questionnaire for Boilers, Process Heaters, 

Incinerators and Other Combustion Units (ICR No. 2286.01, OMB Control No. 2060-

0616, EPA Form No. 5900-122) 

2. U.S. Environmental Protection Agency. 2009 Test Plan for Boilers and Process Heaters 

ICR No. 2286.03, OMB Control No. 2060-0616, EPA Form No. 5900-122 
3. McClutchey. S, and G. Gibson, ERG. Data Dictionary for Boiler, Process Heater, and 

Other Combustion Unit Survey Databases. April 2010. 

4. Gibson, G., ERG. Standardization of Reported Data from the Questionnaire for Boilers, 

Process Heaters, Incinerators and Other Combustion Units, April 2010. 

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

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

2010. 

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

Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants – 

Major Source, April 2010. 

7. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth 

Edition. EPA/452/B-02-001, January 2002. 

8. Holloway, Thomas. RTI International. E-mail with attachment: HMWI Fabric Filter 

Control Cost Spreadsheet, July 2009. 

9. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, 

Commercial, and Institutional Boilers and Process Heaters National Emission Standards 

for Hazardous Air Pollutants, October 2002. 

10. U.S. Environmental Protection Agency. Coal Utility Environmental Cost Version 5.0. 

EPA/600/R-09/131. Office of Research and Development Air Pollution Prevention and 

Control Division. September 2009. www.epa.gov/ttncatc1/products.html. 

11. U. S. Environmental Protection Agency, 1982. Fossil Fuel Fired Industrial Boilers - 

Background Information: Volume 1. EPA-450/3-82-006a. Office of Air Quality Planning 

 and Standards, Research Triangle Park, NC. 

12. Alvis, Jeanette. ERG. Memorandum to Fred Porter, U. S. Environmental Protection 

Agency, OAQPS. Description of the ICCR Materials Analysis Database, Version 2.0.

August 2, 1999. 

13. Babcock and Wilcox. Steam its generation and use 40th edition. 1992. 

14. Holloway, Thomas. RTI International, Memo to Mary Johnson, U.S. Environmental 

Protection Agency, Compliance Costs and Economic Inputs for Existing HMWI. October 

24, 2008. 

15. Holloway, Thomas. RTI International. Revised Baseline Operating Costs for Existing 

HMWI Memo. June 19, 2009. 

16. ERG. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-Fired 

EGUs in the WRAP Region. September 5, 2005.
17. Phone conversation between Amanda Singleton, ERG and Gil McCoy, U.S. Department 

of Energy, Energy Efficiency and Renewable Energy. October 27, 2008 for quote on a 

Linkageless Boiler Management System. 

18. Cairnie, D. 2008. Linkageless Burner Control. Heating/Piping/Air Conditioning 

Engineering, on-line edition: http://hpac.com/heating/linkageless_burner_control/

19. Global Environmental Solutions Inc., The Utilization of Integrated Plasma Gasification 

Combined Cycle System. www.gesi-solutions.com/resources/GESI--

THE+UTILIZATION+OF+INTEGRATED+PLASMA+GASIFICATION+COMBINED

+CYCLE+SYSTEM.pdf

20. Eckerlin, Dr. H.M. and E.W. Soderberg , Industrial Extension Service USI boiler 

Efficiency Program. February 25, 2004.15, 

www.energync.net/programs/docs/usi/om/boilers/ssr.pdf. 

21. Research Triangle Institute, 2007, “U.S. EPA Continuous Emission Monitoring System 

(CEMS) Cost Model.” www.epa.gov/ttn/emc/cem.html. 

22. Holloway, Thomas. Midwest Research Institute, Memo to Rick Copland, U.S. 

Environmental Protection Agency, Revised Testing and Monitoring Options and Costs 

for Medical Waste Incinerators (MWI’s) - Methodology and Assumptions. March 17, 

1997 

23. U. S. Environmental Protection Agency, 1982. Background Information for New Source 

Performance Standards: Nonfossil Fuel Fired Industrial Boilers. Draft EIS. EPA-450/3-

 82-007. Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

 
Appendix A: Example Calculation of Exhaust Flow Rate, Percent Moisture and Percent Oxygen

C 70.6 Excess Air (%) 15H2 22.7 Temperature (std.) 350

N2 5.7 Heating Value (Btu/lb) 22027

S --Ash --O2 1

Calculate Theoretical Oxygen Requirement in Combustion Air:Element % by weight Molecular weight

Mole/100 lb of fuel=%/MW

Resulting Product

Requiremoles oOx/ 100 fuel

C 70.6 12 5.9 CO2 H2 22.7 2 11.4 H2O 

N2 5.7 28 0.2

O2 1 32 0.03 -0

Total 100 122027 Btu/lb fuel x 100/100 lb fuel x MMBtu/1000000 Btu = 2.2MMBtu/ 100 lb fuel15 = 100 x (O2 - 11.6)/11.6O2 = 13.3 molesO2/100 lb fuelMaterial Analysis Average Values for Natural Gas from Steam

Fuel Values and Combustion Unit Assumptions

Calculate Heat Content of Natural Gas per 100 lb of fuelSolve for Required Moles of O2/100 lb fuel at 15% excess air
Appendix A: Example Calculation of Exhaust Flow Rate, Percent Moisture and Percent Oxygen

Ratio of N2 to O2 in the Atmosphere - 3.77 [moles N2 to moles O2]N2 = 13.3 moles O2/100 lb fuel x 3.77 moles N2/1.0 mole O2N2 = 50.1 moles/100 lb fuelCalculate Exhaust TotalsElement Basis Exhaust (moles/100 lb fuel)CO2 5.9 C 5.9H20 11.4 H2 11.4O2 13.3 - 11.6 1.7N2 0.2+50.1 50.3Total 69.3Calculate Exhaust Volume acf/lb fuelPressure x Volume = Moles x Constant x TemperatureExhaust Volume = Moles x constant x Temperature / PressureConstant = 10.73 psia-ft3/lb-mole-deg RTemperature Conversion deg R = deg F + 460Calculate Exhaust Volume acf/MMBtuExhaust Volume = Volume in acf/lb fuel x Heat Content per 100 lb fuelExhuast Volume = 409 acf / lb fuel x 100 lb fuel / 2.2 MM Btu = 18590 acf/MMBtu at 15% excess airCalculate Exhaust Flow Rate from Exhaust Volume using Example Capacity of 5 MMBtu/hrExhaust Flow rate = Exhaust Volume in acf/MMBtu x Capacity in MMBtu/hr x 1 hr/60 minutesExhaust Flow Rate = 18590 acf/MMBtu x 5 MMBtu/hr x 1/60 = 1549 acfmCalculate Percent Moisture in ExhaustExhaust Moisture (%) = (11.4 moles H2O/100 lb fuel) / 69.3 total moles/100 lb fuel x 100% = 16.5 %Calculate Percent Oxygen in ExhaustExhaust Moisture (%) = (1.7 moles O2/100 lb fuel) / 69.3 total moles/100 lb fuel x 100% = 2.5 %Sources:Alvis, Jeanette, C. Burlew and R. Oommen, ERG. Development of Model Units for the Industrial/Commercial/Institutional Boilers and Process Heaters NationStandards for Hazardous Air Pollutants. October 2002.

Exhuast Volume = 69.3 lb-moles / 100 lb fuel x 10.73 psia-ft3/lb-mole-deg R x (1/14.7psia) x (350 deg F + 460) = 409 acf / lb fuel

Calculate Moles of N2/100 lb fuel in Combustion Air
Appendix B: Fabric Filter Costs

Parameters/Costs Equation

A. Parameters

1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 mmBtu/hr)

2. Annual operating hours, hr/yr (H) used Boiler Survey data as input

3. Exhaust gas flow rate, dscfm (Q) calculated per boiler, see Section 2.0 of the memo.

4. PM concentration, gr/dscf (PM) calculated baseline emission factor for PM (lb/mmBtu)*C*(7000/60)/Q

5. Water vapor in gas (% by weight) (%M) estimated per boiler, see Section 2.0 of the memo.

 a. lb/min = Q / (385 ft3

/lb-mol) x (29 lb/lb-mol) x %M

 b. scfm = (lb/min) / (18 lb/lb-mol) x (385 ft 3

/lb-mol)

 a. Dry gas from incinerator, Btu/lb air = [7.010 x (300°F - 77°F) - 7.554 x (1800°F - 77°F)] / (29 lb/lb-mol)

 b. Water vapor from incinerator, Btu/lb water 

vapor

= [8.154 x (300°F - 77°F) - 9.215 x (1800°F - 77°F)] / (18 lb/lb-mol)

 c. Total gas stream, Btu/yr = [(Btu/lb air) x Q / (385 ft3/lb-mol) x (29 lb/lb-mol) x (60 min/hr) x H] + 

[(Btu/lb water vapor) x Q x (0.00753 lb water vapor/ft3) x (60 min/hr) x 

H]

 d. Cooling water

 i. Heat of vaporization at 77 °F, Btu/lb

 ii. Sensible heat for vapor, Btu/lb

 iii. Total, Btu/lb water

7. Cooling water evaporated, lb/yr

 a. lb/yr = [enthalpy change (total gas stream, Btu/yr)] / [enthalpy change 

(cooling water, Btu/lb)]

 b. scfm = [cooling water evaporated (lb/yr)] / (18 lb/lb-mol) x (385 ft3/lb-mol) / 

(H * 60 min/hr)

8. Actual gas flow into fabric filter, acfm (AQ) = [Q + (water vapor in gas from incinerator, scfm) + (water vapor 

added in quench, i.e., cooling water evaporated, scfm)] x [(300 °F + 

460°F)/528°R]

9. Operating labor rate, $/hr (LR) 51.26

10. Electricity cost, $/kWh (EC) 0.069981

11. Water cost, $/gal (WC) 0.000559

12. Compressed air cost, $/1,000 ft3 (CAC) 0.31

13. Dust disposal cost, $/ton (DDC) 42.14

14. Capital recovery factors = [i x (1 + i)a

] / [(1 + i)a - 1], where i = interest rate, a = equipment life

 a. Bag CRF, 2-yr life, 7% interest

 b. Cage CRF, 4-yr life, 7% interest

 c. Equipment CRF, 20-yr life, 7% interest

 d. Duct CRF, 20-yr life, 7% interest

15. Cost index

 a. 2008 525.4

 b. 1989 357.5

16. Retrofit Factor 1.4

17. Gas transport velocity, ft/min (ut) assigned constant, 3000

18. Diameter of duct, ft (Dd) =1.128 x (Q/ut)^1/2

19. Number of Duct Lines, (ND)

 if Q < 154042 acfm =1

 if Q > 154042 acfm = Q/154042 acfm

20. Length of ductwork (L) assigned constant, 500

21. # of elbows per length of duct (Ne/Ld) assigned constant, 0.02

22. Fan coefficient (af) assigned constant, 22.1

23. Fan Diameter, inches (Df) assigned constant, 36.5

24. Fan exponent (b) assigned constant, 1.55

B. Total Capital Investment

1. TCIduct, $ =(1.458 x ((0.39 x ((Dd/ND)^2) x 3.14159 x L)+(74.2 x L x Ne/Ld x 

EXP(0.8016 x (Dd/ND))) + (23 x EXP(0.6804 x (Dd/ND))) + (af x 

(Df^b))))

2. TCI $ = (TCIduct + 47.0 x Q + 306,720) x (Retrofit Factor) x (525.4/357.5)

3. $/dscfm = $ / Q

C. Direct Annual Operating Costs, $/yr

1. Electricity = (0.746 kW/hp) x hp (0.0072 x Q + 3.20) x H x EC

2. Electricity - Ducts

 a. Friction loss factor for elbow (k) assigned constant, 0.19

 b. Efficiency of fan (ef) assigned constant, 0.70

 c. Pressure drop through duct, in.H2O (Pd) =0.136 x (1/Dd)^1.18 x (ut/1000)^1.8 + (L/100) x (L x Ne/Ld x k x 

(ut/4016)^2)

 f. Electricity for Fan use, kW (Efan) =((0.000117 x Q x H x Pd)/ef)

 g. Cost of Electricity, $/yr =EC x Efan

3. Evaporative cooler water = (0.1007 x Q + 23.1506) gal/min x (60 min/hr) x H x WC

4. Operating labor = (1 hr/shift) x (1 shift/8 hr) x H x LR

5. Supervisory labor = 0.15 x (operating labor)

6. Maintenance labor = (0.5 hr/shift) x (1 shift/8 hr) x H x (LR x 1.1)

7. Maintenance materials = 0.02 x TCI

8. Compressed air = AQ x (2 ft3

 air/1,000 ft3 filtered) x (60 min/hr) x H x CAC

9. Dust disposal = (PM gr/dscf x Q x 60 min/hr x 1 lb/7,000 gr) x (1 ton/2,000 lb) x H x 

DDC

10. Bag replacement

 a. Bag cost = AQ x ($2.5/ft2

) x (525.4/317.4) x (1.08 taxes and freight ratio)/(3.5 

ft/min G/C ratio)

 b. Bag replacement labor cost = AQ x (0.15 hr/bag)/(18 ft2

 bag area)/(3.5 ft/min G/C ratio) x LR

 c. Bag replacement cost = Bag CRF x [(total bag cost) + (bag replacement labor cost)]

11. Cage replacement

 a. Number of bags = AQ/(3.5 ft/min G/C ratio)/(18 ft2 bag area)

 b. Cage replacement labor cost = bag replacement labor cost

 c. Cage replacement cost = Cage CRF x [single-cage cost (4.941+ 0.163 x 18 ft 2

 bag area) x 

(number of bags) x (525.4/317.4) + (cage replacement labor cost)]

D. Indirect Annual Costs, $/yr

6. Enthalpy change in quench (1800°F to 300°F)
Appendix B: Fabric Filter Costs

Parameters/Costs Equation

1. Overhead = 0.6 x (labor + maintenance materials)

2. Property taxes, insurance, and 

administration

= 0.04 x TCI

3. Capital recovery = Equipment CRF x (TCI - bag replacement cost - cage replacement 

cost)

4. Duct TAC

 a.TACductwork =TCIduct x (0.04 + CRFduct)

 b. Duct_cap recov =TACductwork x 0.7

 c. Duct_admin =TACductwork x 0.1498

 d. Duct_prop tax =TACductwork x 0.0749

 e. Duct_insurance =TACductwork x 0.0749

 f. Total TACduct =Duct_cap recov + Duct_admin + Duct_prop tax + Duct_insurance

E. Total Annual Cost

1. $/yr = Direct Annual Costs + Indirect Annual Costs + Total TACduct

2. ($/yr) / dscfm = ($/yr) / Q

Sources:

3. Electricity cost: Energy Information Administration. Average Industrial Retail Price of Electricity: October 2009.

4. Water cost: Air Compliance Advisor, version 7.5.

5. Compressed air cost: P2Pays.org. Energy Tips – Compressed Air. Compressed Air Tip Sheet #1. August 2004.

6. Dust disposal cost: NSWMA’s 2005 Tip Fee Survey

1. Cost equations: Hospital/Medical/Infectious Waste Incinerators (HMIWI) [EPA-HQ-OAR-2006-0534] Model Plant Description and 

Cost Report (II-A-112); and Dry Injection Fabric Filter Cost Memorandum (IV-B-32).

2. Operating labor rate: Bureau of Labor Statistics, Occupational Employment Statistics, May 2008 National Industry-Specific 

Occupational Employment and Wage Estimates
Appendix C: ESP Costs

Parameters/Costs Equation

A. Parameters

1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 mmBtu/hr)

2. Annual operating hours, hr/yr (H) used Boiler Survey data as input

3. Exhaust gas flow rate, acfm (Q) calculated per boiler, see Section 2.0 of the memo.

4. PM concentration, gr/dscf (PM) calculated baseline emission factor for PM (lb/mmBtu)*C*(7000/60)/Q

5. Efficiency, % (E) =100*(1-(PM emission limit/PM))

6. Temperature (T) assigned based on fuel type, see Section 2.2.2 of the memo

7. Inlet Moisutrue, % (IM) assigned constant, see Appendix C-2

8. Specific Collection Area ratio (SCA) assigned based on efficiency, see Appendix C-2

9. PM Migration velocity (Mv) assigned constant, see Appendix C-2

10. Total Collection Place area, ft2 (TCP) =(Q/1000) x ((-508*LN(1-(E/100)))/Mv) x SCA

11. Equipment Cost of ESP, $ (EC)

 if TCP<50,000 =614.55(TCP)^0.6276

 if TCP>50,000 =57.87(TCP)^0.8431

12. Factor to convert from FRP to other material 

(m)

assigned constant, see Appendix C-2

13. Cost index

 a. 2008 525.4

 b. 1998 389.5

14. Capital recovery factors = [i x (1 + i)a

] / [(1 + i)a - 1], where i = interest rate, a = equipment life

 Equipment CRF, 20-yr life, 7% interest

 Duct CRF, 20-yr life, 7% interest

15. Operating labor rate, $/hr (LR) SEE cost input summary

16. Electricity cost, $/kWh (EC) SEE cost input summary

17. Dust disposal cost, $/ton (DDC) SEE cost input summary

18. Retrofit Factor 1.4

19. Gas transport velocity, ft/min (ut) assigned constant, see Appendix C-2

20. Diameter of duct, ft (Dd) =1.128 x (Q/ut)^1/2

21. Number of Duct Lines, (ND)

 if Q < 154042 acfm =1

 if Q > 154042 acfm = Q/154042 acfm

22. Length of ductwork (L) assigned constant, see Appendix C-2

23. # of elbows per length of duct (Ne/Ld) assigned constant, see Appendix C-2

24. Fan coefficient (af) assigned constant, see Appendix C-2

25. Fan Diameter, inches (Df) assigned constant, see Appendix C-2

26. Fan exponent (b) assigned constant, see Appendix C-2

B. Total Capital Investment (TCI)

1. TCIduct, $ =(1.458 x ((0.39 x ((Dd/ND)^2) x 3.14159 x L)+(74.2 x L x Ne/Ld x 

EXP(0.8016 x (Dd/ND))) + (23 x EXP(0.6804 x (Dd/ND))) + (af x 

(Df^b))))*(575.4/389.5)*Retrofit Factor

2. $ =3.8326 x m x EC x Retrofit Factor + TCIduct

3. $/acfm = $ / Q

C. Direct Annual Operating Costs, $/yr

1. Electricity

 a. Friction loss factor for elbow (k) assigned constant, see Appendix C-2

 b. Efficiency of fan (ef) assigned constant, see Appendix C-2

 c. Pressure drop through duct, in.H2O (Pd) =0.136 x (1/Dd)^1.18 x (ut/1000)^1.8 + (L/100) x (L x Ne/Ld x k x 

(ut/4016)^2)

 d. Pressure drop through ESP, in.H2O (Pesp) assigned constant, see Appendix C-2

 e. Pressure drop of gas, in.H2O (Pg) =Pesp+Pd

 f. Electricity for Fan use, kW (Efan) =((0.000117 x Q x H x Pg)/ef) + 0.00194 x TCP x H

 g. Cost of Electricity, $/yr =EC x Efan

2. Dust disposal =0.00000429 x H x DDC x PM x Q x E

3. Labor

 a. If TCP < 10,000 then Of =0

 b. If TCP > or = 10,000 then Of=1

 c. Cost of Labor, $/yr (LC) = 0.1854 x H x LR x Of

4. Maintenance Cost, $/yr (MC)

 a. If TCP<50,0000 =4125 + 0.004464 x TCI

 b. If TCP> or = 50,000 =0.0825 x TCP + 0.00446 x TCI

D. Indirect Annual Costs, $/yr

1. Overhead = 0.6 x (LC + MC)

2. Property taxes = 0.01 x TCI

3. Capital recovery = Equipment CRF x (TCI)

4. Administrative cost =0.02 x TCI

5. Insurance =0.01 x TCI

6. Duct TAC

 a.TACductwork =TCIduct x (0.04 + CRFduct)

 b. Duct_cap recov =TACductwork x 0.7

 c. Duct_admin =TACductwork x 0.1498

 d. Duct_prop tax =TACductwork x 0.0749
Appendix C: ESP Costs

Parameters/Costs Equation

 e. Duct_insurance =TACductwork x 0.0749

 f. Total TACduct =Duct_cap recov + Duct_admin + Duct_prop tax + Duct_insurance

E. Total Annual Cost

1. $/yr = Direct Annual Costs + Indirect Annual Costs + Total TACduct

2. ($/yr) / dscfm = ($/yr) / Q

Sources:

1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 6. EPA/452/B-02-001, January 2002

2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process Heaters 

National Emission Standards for Hazardous Air Pollutants, October 2002.
Appendix C: ESP Costs

Var COMMON DEFAULTS - ESP

I I = interest rate 0.07

Ne_Ld Ne/LD = # of elbows per length of duct 0.02

L L = length of ductwork 500

ut ut = gas transport velocity, ft/min 3000

Var DEFAULTS- TOTAL ANNUAL COST -- ESP

n n = life of equipment, yrs 20

Op_ESP Op_ESP = operating hours/year 8400

CFdd CFdd = cost factor for dust disposal, $/ton 42.14111

CFlab CFlab = cost factor for labor, $/hr 51.26

Ps = DEFAULTS - ELECTRICITY - ESP

CFelec CFelec = cost factor for electricy, $/kw-hr 0.06998

Pesp Pesp = pressure drop through esp, in H2O 0.38

k k = friction loss factor for elbow 0.19

Ef Ef = efficiency of fan 0.7

DEFAULTS - DUCTWORK - ESP

af af = fan coefficient 22.1

b b = fan exponent 1.55

Df Df = fan diameter, inches 36.5

n_duct n_duct = life of equipment, yrs 20

DEFAULTS -TCI - ESP

Fone Fone = special add-on factor 1

Ftwo Ftwo = no special add-on factor 0

m m = factor to convert from FRP to other mat. 1

Mv Mv = PM migration velocity, cm/s 16

Sources:

ESP DEFAULTS

1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 6. 

EPA/452/B-02-001, January 2002.

2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional 

Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, October 2002.
Appendix D: Packed Bed Scrubber

Parameters/Costs Equation

A. Parameters

1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 mmBtu/hr)

2. Annual operating hours, hr/yr (H) used Boiler Survey data as input

3. Exhaust gas flow rate, acfm (AQ) calculated per boiler, see Section 2.0 of the memo.

4. PM filterable baseline emission, lb/mmBtu (PMb) used Boiler Survey data as input

5. HCl Baseline, lb/mmbtu (HClb) used Boiler Survey data as input

6. Temperature (T) assigned based on fuel type, see Section 2.2.2 of the memo

7. Inlet Moisutrue, % (IM) calculated per fuel type, see Appendix D-2

8. HCl Floor, lb/mmBtu (HClf) assigned based on fuel

9. Efficiency (E) = 100 x (1 - (HClf/HClb))

10. Inlet HCl Loading, lb/hr (In HCl) =HClb x C

11. Inlet PM loading, lb/hr (In PM) = PMb x C

12. Inlet HCl loading, mole fraction (In HClm) =InHCl x (T = 460) / (2958.12 x AQ)

13. Inlet PM loading, gr/acfm (InPMg) =InPM / AQ x 116.7

14. Packing Cost Factor, $/ft3 (Cp) constant, see Appendix D-2

15. Scrubber Diameter Component (SDC)

 a. ratio of solvent density to water density (mm) defined in Appendix D-2

 b. packing factor (Fp) defined in Appendix D-2

 c. viscosity of liquid, lb/ft-hr (ui) defined in Appendix D-2

 d. flooding factor (f) defined in Appendix D-2

 e. minimum wetting rate, ft2/hr (MWR) defined in Appendix D-2

 f. packing constant, ft2/ft3 (ap) defined in Appendix D-2

 g. SDC '=(-0.915 - SQRT(-1.144359 -(1.188 x (LOG((mm x Fp x ((ui / 2.42) ^ 0.2) x MWR^2 x 

ap^2) / (12960000 x f^2 x 32.2),10)))))/-0.594

16. Scrubber Diameter, ft (Ds)

 a. density of liquid, lb/ft3 (Dl) defined in Appendix D-2

 b. density of gas, lb/ft3 (Dg) defined in Appendix D-2

 c. Ds =(SQRT((240 x Dg x AQ x 10^SDC)/(MWR x Dl x ap x PI x SQRT((Dg/Dl)))))

17. Height of packing, ft (Hpack)

 a. packing constant (BBB) defined in Appendix D-2

 b. packing constant (X) defined in Appendix D-2

 c. HpackA = X x (240 x Dg x AQ) / (PI x Ds^2)

 d. packing constant (g) defined in Appendix D-2

 e. HpackB = (MWR x D x ap)^g

 f. viscosity of gas, lb/ft-hr (ug) defined in Appendix D-2

 h. diffusivity of gas, ft2/hr (Dfg) defined in Appendix D-2

 i. HpackC = SQRT(ug/(Dg*Dfg)

 j. packing constant (BB) defined in Appendix D-2

 k. HpackD =((MWR x Dl x ap)/ui)^BB

 l. liquid diffusivity, ft2/hr (Dfl) defined in Appendix D-2

 m. HpackE = SQRT(ui/(Dl x Dfl))

 n. pollutant mole fraction exiting scrubber(Out 

HClm)

=In HClm x (100-E)/(100 - (In HClm x E))

 o. adsorption factor (AF) defined in Appendix D-2

 p. packing constant (t) defined in Appendix D-2

 q. Hpack =Ln(In HClm/Out HClm) x (HpackA/HpackB^BBB) x HpackC + 1/AF x (t x HpackE^BB) x 

HpackE

18. Cost factor for pump, $/gpm (Cfpump) defined in Appendix D-2

19. Factor to convert FRP to another material defined in Appendix D-2

20. Cost Index

 a. 2008 525.4

 b. 1998 389.5

21. Capital recovery factor (CRF) = [i x (1 + i)a

] / [(1 + i)a - 1], where i = interest rate, a = equipment life

 Equipment CRF, 20-yr life, 7% interest

 Duct CRF, 20-yr life, 7% interest

22. Operating labor rate, $/hr (CFlab) $51.26

23. Electricity cost, $/kWh (CFelec) $0.069981

24. Water cost, $/gal (CFw) $0.00059889

25. Wastewater disposal cost, $/gal (CFww) $0.005439

26. Pump Cost Factor, $/gpm (CFp) $23.64

27. Cost Factor for Caustic, $/ton (CFcaus) $600

28. Moles of caustic/moles pollutant (SR1) defined in Appendix D-2
Appendix D: Packed Bed Scrubber

Parameters/Costs Equation

29. Caustic mole weight, lb/lbmole (MWcaustic) defined in Appendix D-2

30. Gas molecular weight, lb/lb-mole (MWg) defined in Appendix D-2

31. Moles salt/moles HCl (SR2) defined in Appendix D-2

32. Salt molecular weight, lb/lbmole (MWsalt) defined in Appendix D-2

33. Fraction of waste stream treated (BF) defined in Appendix D-2

34. Maintenance labor rate, $/hr (Cfmain) $51.26

35. Retrofit Factor 1.4

19. Gas transport velocity, ft/min (ut) defined in Appendix D-2

20. Diameter of duct, ft (Dd) =1.128 x (Q/ut)^1/2

21. Number of Duct Lines, (ND)

 if Q < 154042 acfm =1

 if Q > 154042 acfm = Q/154042 acfm

22. Length of ductwork (L) defined in Appendix D-2

23. # of elbows per length of duct (Ne/Ld) defined in Appendix D-2

24. Fan coefficient (af) defined in Appendix D-2

25. Fan Diameter, inches (Df) defined in Appendix D-2

26. Fan exponent (b) defined in Appendix D-2

B. Total Capital Investment (TCI)

1. TCItower, $ =(417.956 x m x PI x Ds x Hpack) + (453.7808 x m x PI x Ds^2) + 

(838.8974 x m x PI x Ds)

2. TCIp, $ =0.649 x Cp x Hpack x PI x Ds^2

3. TCIpump, $ =0.0312 x MWR x a x PI x Ds^2 x Cfpump x m

4. TCIduct, $ =(1.458 x ((0.39 x ((Dd/ND)^2) x 3.14159 x L)+(74.2 x L x Ne/Ld x 

EXP(0.8016 x (Dd/ND))) + (23 x EXP(0.6804 x (Dd/ND))) + (af x 

(Df^b))))

5. Total TCI, $ = (TCItower + TCIpump + TCIp + TCIduct) x (525.4/389.5) x Retrofit 

Factor

6. $/acfm = $ / Q

C. Direct Annual Operating Costs, $/yr

1. Electricity

 a. Pressure of pump, ft of H2O (Pp) defined in Appendix D-2

 b. Efficiency of pump (Ep) defined in Appendix D-2

 c. Electricity for Pump use, kw (Epump) =(0.00000585 x H x PI x Ds^2 x MWR x ap x Pp) / Ep

 d. Friction loss factor for elbow (k) defined in Appendix D-2

 e. Efficiency of fan (ef) defined in Appendix D-2

 f. Pressure drop through duct, in.H2O (Pd) =0.136 x (1/Dd)^1.18 x (ut/1000)^1.8 + (L/100) x (L x Ne/Ld x k x 

(ut/4016)^2)

 g. packing constant (c) defined in Appendix D-2

 h. packing constant (j) defined in Appendix D-2

 i. Pressure drop through scrubber, in.H2O (Ps) =(Hpack x AQ^2 x c x Dg x [10^(j x MWR x Dl x ap / 3600)]) / (225 x PI^2 x Ds^4)

 j. Pressure drop of gas, in.H2O (Pg) =Ps+Pd

 k. Electricity for Fan use, kW (Efan) =((0.000117 x AQ x H x Pg)/ef)

 l. Cost of Electricity, $/yr (Ce) =EC x (Epump + Efan)

2. Caustic Cost ($/yr), Ccaustic =0.03 x AQ x Dg x (In HClm - Out HClm) x SR1 x MWcaustic x H x 

CFcaus / MWg

3. Cost of ww disposal, $/yr (Cww) =7.194 x AQ x Dg x (In HClm - Out HClm) x SR2 x Mwsalt x (1/BF) x H 

x CFww / MWg

4. Cost of water, $/yr (Cw) =Cww x (CFw / CFww)

5. Cost of Labor, $/yr (Clab) = 0.07188 x H x Cflab

6. Cost of Maintenance, $/yr (Cmain) =0.125 x H x Cfmain

D. Indirect Annual Costs, $/yr

1. Overhead = 0.6 x (CFlab + CFmain)

2. Property taxes = 0.01 x TCI

3. Capital recovery = Equipment CRF x (TCI)

4. Administrative cost =0.02 x TCI

5. Insurance =0.01 x TCI

6. Capital recovery = CRF x TCI

7. Duct TAC

 a.TACductwork =TCIduct x (0.04 + CRFduct)

 b. Duct_cap recov =TACductwork x 0.7

 c. Duct_admin =TACductwork x 0.1498
Appendix D: Packed Bed Scrubber

Parameters/Costs Equation

 d. Duct_prop tax =TACductwork x 0.0749

 e. Duct_insurance =TACductwork x 0.0749

 f. Total TACduct =Duct_cap recov + Duct_admin + Duct_prop tax + Duct_insurance

E. Total Annual Cost

1. $/yr = Direct Annual Costs + Indirect Annual Costs + Total TACduct

2. ($/yr) / acfm = ($/yr) / AQ

Sources:

1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 8. EPA/452/B-02-001, January 2002.

2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process Heaters National 

Emission Standards for Hazardous Air Pollutants, October 2002.
Appendix D: Packed Bed Scrubber

Var COMMON DEFAULTS - PACKED SCRUBBER

I I = interest rate 0.07

Dg Dg = density of gas, lb/ft3 0.0709

Ne_Ld Ne/LD = # of elbows per length of duct 0.02

L L = length of ductwork 500

MWR MWR = minimum wetting rate, ft2/hr 1.3

ut ut = gas transport velocity, ft/min 3000

Dl Dl = density of liquid, lb/ft3 62.4

ap a = packing constant, ft2/ft3 28

Var DEFAULTS- TOTAL ANNUAL COST -- PACKED SCRUBBER

n n = life of equipment, yrs 15

SR1 SR1 = moles caustic/moles pollutant 0.5

MWc MWc = caustic molec wt, lb/lb-mole 62

Op_Scr Op_Scr = operating hours/year 8400

CFc Cfc = cost factor for caustic, $/ton 440

MWg MWg = gas molecular weight, lb/lb-mole 29

SR2 SR2 = moles salt/moles HCl 1

MWs MWs = salt molecular weight, lb/lb-mole 58.5

BF BF = fraction of waste stream treated 0.1

CFww CFww = cost factor for ww disposal, $/gal 0.0054

CFwt CFwt = cost factor for water, $/gal 0.00060

SR3 SR3 = adjustment for 76% Na2O solution 0.76

CFlab CFlab = cost factor for labor, $/hr 51.26

CFmain CFmain = cost factor for maintenance, $/hr 51.26

DEFAULTS - ELECTRICITY - PACKED SCRUBBER

CFelec CFelec = cost factor for electricy, $/kw-hr 0.06998

Pp Pp = pressure of pump, ft of H20 60

Ep Ep = efficiency of pump 0.7

Op_pump Op_pump = operating hours/year 8000

cpc cpc = packing constant 0.24

j j = packing constant 0.17

k k = friction loss factor for elbow 0.35

ef ef = efficiency of fan 0.7

DEFAULTS - DUCTWORK - PACKED SCRUBBER

af af = fan coefficient 22.1

b b = fan exponent 1.55

Df Df = fan diameter, inches 36.5

n_duct n_duct = life of equipment, yrs 20

PACKED SCRUBBER DEFAULTS
Appendix D: Packed Bed Scrubber

DEFAULTS -TCI - PACKED SCRUBBER

m m = factor to convert from FRP to other material 1

mm mm = ratio of solvent density to water density 1

Fp Fp = packing factor 65

ui ui = viscosity of liquid, lb/ft-hr 2.16

f f = flooding factor 0.7

ug ug = viscosity of gas, lb/ft-hr 0.044

Dfg Dfg = diffusivity of pollutant in gas, ft2/hr 0.725

Dfl Dfl = diffusivity of pollutant in liquid, ft2/hr 0.000102

AFT AFT = absorption factor 17

x x = packing constant 3.82

t t = packing constant 0.0125

g g = packing constant 0.45

BBB BBB = packing constant 0.41

bb b = packing constant 0.22

eff eff = efficiency of scrubber 99

Cp Cp = packing cost factor, $/ft3 20

CFpump CFpump = cost factor for pump, $/gpm 23.64

Site Site 0

Bldg Bldg 0

Sources:

2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air Pollutants, October 2002.

1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 8. EPA/452/B-02-001, 

January 2002.
Appendix E: Increased Caustic

Parameters/Costs Equation Fuel Category F-Factor

Bagasse 9420

A. Parameters Coal 9780

1. Annual operating hours, hr/yr (H) used Boiler Survey data as input Dry Biomass 9240

2. Exhaust gas flow rate, acfm (AQ) calculated per boiler, see Section 2.0 of the memo. Gas 1 (NG Only) 8710

3. Exhaust gas flow rate, dscfm (Q) calculated per boiler, see Section 2.0 of the memo. Gas 1 (Other) 8710

4. Baseline HCl, units (lb/mmBtu) (HClb) calculated per boiler Gas 2 8710

5. Floor HCl level, (lb/mmBtu) (HClf) assigned by fuel category

6. F-Factor determined by fuel category, see index Heavy Liquid 9190

7. Uncontrolled HCl, ppmvd (HClu) =HClb x F-Factor x (1/36.4609) x 385.34 x 1000000 Light Liquid 9190

8. Controlled HCl, ppmvd (HClc) =HClf x F-Factor x (1/36.4609) x 385.34 x 1000000 Wet Biomass 9600

9. Operating Labor Rate, $/hr (LR) $51.26

10. Wastewater Blowdown, gpm (B) =Hclu/1000000 x Q x 1/385 x 1/1 x 58.2/1 x 1/0.1 x 

1/8.33

11. Caustic Cost, $/ton (CC) $357

12. Sewage disposal, $/1000 gal (SDC) $5.40

13. Water Cost, $/1000 gal (WC) $0.60

14. Lime Cost, $/ton (LC) $95

15. Sodium Bicarbonate, $/ton (SBC) $440

16. Dust Disposal, $/ton (DDC) $34.29

17. Activated Carbon, $/lb (ACC) $1.38

18. Natural Gas, $/1000 ft3 (NGC) $9.58

19. Electricity Cost, $/kWh (EC) $0.07

20. Capital recovery factors = [i x (1 + i)a

] / [(1 + i)a - 1], where i = interest rate, a 

= equipment life

 a. Bag CRF, 2-yr life, 7% interest

 b. Cage CRF, 4-yr life, 7% interest

15. Cost index

 a. 2008 525.4

 b. 1984 317.4

B. Total Bag/Cage Cost

1. $ = AQ x 2.5 x (525.4/317.4) x (1.08/3.5)

2. Bag Replacement Labor Cost = AQ x 0.15/18/3.5 x LR

3. Cage Replacement Labor Cost = Bag Replacement Labor Cost

4. Total Cage Cost = Cage CRF x ((4.941 + 0.163 x 18) x (AQ/3.5/18) x 

(5.75.4/317.4) + Cage Labor Cost

C. Total Increased NaHCO3 Cost

1. Makeup NaHCO3 Cost, $ = 2.73x10-7 x Hclu x Q x 1/2000 x 60 x H x SBC

2. Dust Disposal Cost, $ =HCLu x Q x 60 x 2.1x10-7 x 1/2000 x H x DDC

3. Total Cost, $/yr/dscfm =(Makeup NaHCO3 + Dust Disposal Cost) /Q

D. Increased Carbon Cost

1. Activated Carbon Cost, $ =1.27x10-3 x Q x H x ACC

2.Dust Disposal Cost, $ =1.27x10-3 x Q x 1/2000 x H x DDC

3. Total Cost, $/yr/dscfm = (Activated Carbon Cost + Dust Disposal Cost)/Q

Sources:

1. Cost equations: Hospital/Medical/Infectious Waste Incinerators (HMIWI) [EPA-HQ-OAR-2006-0534] Model Plant Description and Cost Report (II-A-112); and Dry Injection 

Fabric Filter Cost Memorandum (IV-B-32).
Appendix F: Activated Carbon Injection Model Costs

Parameters/Costs Equation

A. Parameters

1. Incinerator capacity, lb/hr (C) converted based on reported heat input capacity

2. Annual operating hours, hr/yr (H) as reported in survey

3. Exhaust gas flow rate, dscfm (Q) calculated per boiler, see Section 2.0 of the memo.

4. Operating labor rate, $/hr (LR) $51.26

5. Activated carbon cost, $/lb (ACC) $1.38 

6. Dust disposal cost, $/ton (DDC) $42.14 

7. Capital recovery factor, 20-yr 

equipment life, 7% interest (CRF)

= [i x (1 + i)a

] / [(1 + i)a - 1], where i = interest rate, 

a = equipment life

8. Cost index

 a. 2008 525.4

 b. 1990 390.6

9. ACI Adjustment Factor (AF) Calculated control efficiency (% reduction) to 

meet Hg or D/F limit/0.9

B. Total Capital Investment

1. $ = 4,500 x (Q/1,976)0.6 x (1.2 retrofit factor) x 

(575.4/361.3)

2. $/dscfm = $ / Q

C. Direct Annual Costs, $/yr

1. Operating labor = (0.25 hr/8-hr shift) x H x LR

2. Supervisory labor = 0.15 x (operating labor)

3. Maintenance = 0.2 x TCI

4. Activated carbon = 0.00127 x Q x H x ACC x AF

5. Dust disposal = 0.00127 x Q x (1 ton/2,000 lb) x H x DDC x AF

D. Indirect Annual Costs, $/yr

1. Overhead = 0.6 x (labor + maintenance materials)

2. Property taxes, insurance, and 

administration

= 0.04 x TCI

3. Capital recovery = CRF x TCI

E. Total Annual Cost

1. $/yr = Direct Annual Costs + Indirect Annual Costs

2. ($/yr) / dscfm = ($/yr) / Q

Note:

Sources:

4. Dust disposal cost: NSWMA’s 2005 Tip Fee Survey.

Factor of 1.27 x 10-3 for activated carbon is based on injecting carbon at a rate to achieve a 

carbon concentration of 338 mg/dscm (achieving reductions of 90% for Hg, 98% for CDD/CDF).

2. Operating labor rate: Bureau of Labor Statistics, Occupational Employment Statistics, May 

2007 National Industry-Specific Occupational Employment and Wage Estimates.

1. Cost equations: Hospital/Medical/Infectious Waste Incinerators (HMIWI) [EPA-HQ-OAR-2006-

0534] Model Plant Description and Cost Report (II-A-112).

3. Activated carbon cost: The Innovation Group. Chemical Profiles: Carbon, Activated. 2002. 

Assumed 20% price increase based on online information from Norit, an activated carbon 

vendor.
Appendix G: Low NOx Burners

Parameters/Costs Equation

A. Parameters

1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 

mmBtu/hr)

2. Annual operating hours, hr/yr (H) used Boiler Survey data as input

3. Unit Size, kW (kW) =C x (1000/3.413)

4. Unit Size, MW (MW) =C x (1/3.413)

5. Capital recovery factor = [i x (1 + i)a

] / [(1 + i)a - 1], where i = interest rate, 

a = equipment life

 a. Equipment CRF, 15-yr life, 7% interest

15. Cost index

 a. 2008 525.4

 b. 2004 444.2

B. Total Capital Investment

TCI ($) =20 x kW x (300/MW)^0.359

C. Direct Annual Operating Costs, $/yr

Variable O&M Costs = 0.000293 x H x C x (0.05/1000) x (575.4/444.2)

D. Indirect Annual Costs, $/yr

1. Fixed O&M Costs = 0.015 x TCI

2. Capital recovery = Equipment CRF x TCI

1. $/yr

= Direct Annual Costs + Indirect Annual Costs

Source:

1. ERG, 2005. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-Fired EGUs in the WRAP 

Region September 6, 2005.
Appendix H: Oxidation Catalyst

Parameters/Costs Equation

A. Parameters

1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 

mmBtu/hr)

2. Annual operating hours, hr/yr (H) 8400

3. Exhaust gas flow rate, scfm (Q) calculated per boiler, see Section 2.0 of the memo.

4. Percent additional fuel/air added (Aux) = Default of 0.05

5. Exhaust gas flow rate, scfm (AF) =Q x (1+Aux)

6. Equipment Cost, $ (EC) = 1105 x Q^0.5471

7. Additional Purchase Equipment Cost 

(Instruments,taxes,freight), $ (AddEC)

= 0.35 x EC

8. Direct Installation Costs, $ (DIC) =0.282 x (EC+AddEC)

9. Indirect Installation Costs, $ (IIC) =0.22 x (EC + AddEC)

9. Operating labor rate, $/hr (LR) 51.26

10. Electricity cost, $/kWh (EC) 0.06998

11. Catalyst cost, $/ft^3 (Cc) 959

12. Pressure change, in of H2O (Pc) 6

13. Efficiency of fan and motor (Ef) 0.6

14. Capital recovery factors = [i x (1 + i)a

] / [(1 + i)a - 1], where i = interest rate, a = 

equipment life

 a. Catalyst CRF, 2-yr life, 7% interest

 b. Equipment CRF, 20-yr life, 7% interest

15. Cost index

 a. 2008 525.4

 b. 1990 390.6

16. Space Velocity in 1/h (Sv) 12000

17. Retrofit Factor 1.4

Total Capital Investment

B. 1. $ =(EC + AddEC + DIC + IIC) x (577.4/390.6) x Retrofit Cost

2. $/scfm

= $ / Q

C. 1. Electricity

 a. Power of Fan (Pf) =(0.000117 x AF x Pc)/0.6

 b. Cost of Electricity =Pf x H x EC

2. Operating labor = H/8 x 0.5 x LR

3. Supervisory labor = 0.15 x (operating labor)

4. Maintenance labor = Operating labor

5. Maintenance materials = Maintenance labor

6. Catalyst Replacement

 a. Catalyst Replacement Volume, ft3 (CRV) =AF x 60/Sv

 b. Catalyst Replacement Cost =CRV x Cc x Catalyst CRF
Appendix H: Oxidation Catalyst

Parameters/Costs Equation

1. Overhead = 0.6 x (electricity + operating labor + supervisory labor + 

maintenance labor + maintenance materials + catalyst 

replacement)

D. 2. Property taxes, insurance, and administration = 0.04 x TCI

3. Capital recovery = Equipment CRF x (TCI - 1.08 x catalyst replacement cost)

E. Total Annual Cost

1. $/yr = Direct Annual Costs + Indirect Annual Costs

2. ($/yr) / dscfm = ($/yr) / Q

Sources:

1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 2. EPA/452/B-02-001, January 2002.
Appendix J: Carbon Bed Adsorber

Parameters/Costs Equation Fuel Category F-Factor

Bagasse 9420

A. Parameters Coal 9780

1. Boiler design capacity, mmBtu/hr (C) Combined for all RFG units at facility Dry Biomass 9240

2. kW Capacity, kW (kW) = C*(1000/3.413)

3. Annual operating hours, hr/yr (H) 8400 Gas 1 8710

4. Exhaust gas flow rate, dscfm (Q) calculated per boiler, see Section 2.0 of the memo. Gas 2 8710

5. Hg Floor, lb/mmBtu (Hgf) assigned per fuel category Heavy Liquid 9190

6. Hg Baseline, lb/mmBtu (Hgb) calculated per boiler Light Liquid 9190

7. F-Factor assigned per fuel category Wet Biomass 9600

8. Controlled Hg Concentration, lb/mmBtu (Hgc) = Hgf x 1000000 x 453.59 x 35.315/F-Factor

9. Uncontrolled Hg, lb/mmBtu (Hgu) = Hgb x 1000000 x 453.59 x 35.315/F-Factor

10. Hg Efficiency (Hge) = (Hgu - Hgc)/Hgu

11. Hg Adjustment Factor for >90% = He/0.90

12 Uncontrolled Hg Concentration, mg/yr = Hgc x Q x 1/35.315 x 60 x H

13. Carbon Consumption, lb/yr (AC) = 338 x (Q/35.315) /1000/453.593 x 60 x H x Hg 

Adjustment Factor

14. Labor Rate, $/hr (LR) $51.26

15. Carbon cost, $/lb (ACC) $1.38

16. Spent Carbon Landfill Cost, $/ton (SCC) $42.14

17. Capital recovery factors = [i x (1 + i)a

] / [(1 + i)a - 1], 

where i = interest rate, a = equipment life

 a. Equipment CRF, 15-yr life, 7% interest

18. Retrofit Factor Constant (RF) = 1.6

B. Total Capital Investment

1. TCI, $ = 30 x kW x RF

C. Direct Annual Operating Costs, $/yr

1. Operating labor = 0.5 x H x LR

2. Supervisory labor = 0.15 x (operating labor)

3. Maintenance labor = 0.5/8 x H x (LR x 1.1)

4. Maintenance materials = Maintenance labor

5. Carbon Replacement = AC x ACC

6. Carbon Disposal = AC x SCC/2000

D. Indirect Annual Operating Costs, $/yr

1. Overhead = 0.6 x (operating labor + supervisory labor + 

maintenance labor + maintenance materials)

2. Property taxes, insurance, and administration = 0.04 x TCI

3. Capital recovery = Equipment CRF x (TCI)

4. Engineering = 0.1 x TCI

5. Construction/Field Experience = 0.05 x TCI

6. Contractor Fees = 0.1 x TCI

7. Contingencies = 0.3 x TCI

E. Total Annual Cost

1. $/yr = Direct Annual Costs + Indirect Annual Costs

Source:

Holloway, Tom. RTI International. Revised Baseline Operating Costs for Existing HMIWI Memo. June 19, 2009. 
Boiler/Process Heater Design Capacity (mmBtu/hr)

Liquid 

Fuel?

Cost per 

Testing Trip Pollutants Tested For

>=100 no 37000 PM, HCl, Hg, D/F

>=100 yes 10000 PM, D/F

<100 no 44000 CO, PM, HCl, Hg, D/F

<100 yes 16000 CO, PM, D/F

REFINERY GAS 7000 Hg

Appendix J-1: Summary of Testing Costs

Notes:

Testing:

Testing Costs were estimated by ERG Air Laboratory Staff in March 2009 and assume that the testing 

contractor will make a single trip to the facility to conduct all necessary tests.

A basic range of testing costs was applied to various pollutants. Tests for PM (filterable), CO, HCl, could be 

completed with manual testing methods, and these manual methods were estimated to range from 

approximately $5,000 - $7,000. For the tests that involve more lab analysis (e.g., Hg), the testing costs 

were estimated to range from approximately $10,000 - $15,000. Tests for dioxins/furans were estimated to 

range from $15,000 to $50,000. 

Although these cost ranges can be applied as is for cases where a single pollutant is being measured, 

estimating costs for facilities that need test data for more than one pollutant is more difficult and uncertain. 

For example, if a facility needs PM data and CO data, the test costs would not be twice the $5,000 - $7,000 

range because some of the costs are associated with getting to the site and setting up the equipment. 

Such costs are one-time costs and would not be duplicated no matter how many pollutants are to be 

tested). Therefore, if a facility had more than one of the simpler tests to run (e.g., PM and CO or PM and 

HCl), then the site-specific cost would start in the $5,000 - $7,000 with a few $1,000 added for subsequent 

pollutants. If a facility needed PM data and dioxin/furan data, then the site-specific cost would be the sum 

of the test in the $5,000 - $7,000 range and the $15,000 - $50,000 range. 

For units less than 100 mmBtu/hr, sources were expected to test for CO, and units greater than 100 

mmBtu/hr were expected to monitoring CO emissions with a CO CEMS so the testing costs for CO were 

subtracted from the total testing costs.

For liquid fuels, it was assumed that units would comply using a fuel analysis (or by receiving a certified 

fuel analysis from the fuel supplier for HCl and Hg), so the costs for these two tests for Hg and HCl were 

subtracted from the total testing costs.

Since existing refinery gas units are only subject to a mercury limit, only the cost to conduct a mercury test 

were included in the cost impacts analysis.
Analyzers BEFORE AFTER

 CO 0 1

 SO2 0 0

 NOX 0 0

 HCl 0 0

 Mercury (and CO2/O2) 0 0

 CO2 0 0

 O2 0 0

 THC 0 0

Summary of Costs

First Costs Labor Test ODCs Total

 Planning 4,835 0 352 5,187

 Select Equipment 20,313 0 3,067 23,380

 Support Facilities 0 0 19,065 19,065

 Purchase CEMS Hardware 0 0 61,070 61,070

 Install and Check CEMS 6,534 0 11,979 18,513

 Performance Specification Tests 3,907 11,230 503 15,640

 QA/QC Plan 4,679 14,546 692 19,917

40,269 25,777 96,727 162,773 TCI

Annual Costs

 Day-to-Day Activities 7,503 0 1,000 8,503

 Annual RATA 1,337 10,642 0 11,980

 PM Monitor RCA 0 0 0 0

 PM Monitor RRA 0 0 0 0

 Cylinder Gas Audits (ACA/SVA for PM) 2,034 0 1,069 3,103

 Recordkeeping and Reporting 1,822 0 160 1,982

 Annual QA & O&M Review and Update 3,399 0 1,161 4,560

 Capital Recovery (i=7%, monitor life = 10 years) 5,734 3,671 13,774 23,179

 Total w/o capital recovery 16,095 10,642 3,390 30,128

 Total with capital recovery 21,830 14,313 17,164 53,307 TAC

Source:

U.S. EPA CEMS Cost Model. 03/07/2007. http://www.epa.gov/ttn/emc/cem.html

Appendix J-2: Summary of CO CEMS
Appendix J-3: Other Monitoring Costs for Boilers and Process Heaters

Parameters/Costs Equation

A. Parameters

1. Recording lime/carbon flow, min/4-hr period2. Annual operating hours, hr/yr (H)3. Cost index a. 2008 575.4 575.4 575.4 

 b. 2006 499.6 All costs 

are in $2006

499.6 All costs 

are in $2006

 c. 1998

 d. 1997 386.5 All other costs are 

$1997

 e. 1993 359.2 Equipment costs, are 

$1993

 f. 19924. Operating labor wage rate, $/hr (LR)

$34.60 $34.60 $34.60 

5. Capital recovery factor, 20-yr equipment life, 7% interest (CRF)

= [i x (1 + i)a] / [(1 + i)a - 1], where i = interest rate, a = equipment life 0.09439 0.09439 0.09439 

B. Total Capital Investment, $ (TCI)

1. Planning $700 $800 $9002. Select type of equipment $400 $4,500 $12,2003. Provide support facilities $1,500 $500 $5004. Purchased equipment cost (PEC) $19,300 $14,100 $73,5005. Install and check equipment $1,000 $4,800 $19,5006. Perf. spec. tests (certif.) $700 $0 $35,5007. Prepare QA/QC plan $700 $800 $15,4008. Total capital cost = Planning + selecting equipment + support facilities + PEC + installation + perf. spec. 

tests + QA/QC plan

$24,300 $25,500 $158,000 

C. Annual Costs, $/yr

1. Operating labor = (5 min to record lime/carbon flow/4-hr period) x (1 hr/60 min) x H x LR2. Maintenance materials = 0.02 x TCI $500 

3. Operation & maintenance = Day-to-day activities + annual RATA + CGA + annual QA + O&M review and update $6,000 $27,3004. Recordkeeping and reporting = $1,000 x (525.4/386.5) $1,500 $200 $6,300 5. Overhead = 0.6 x (labor + maintenance materials) $3006. Property taxes, insurance, and administration

= 0.04 x TCI $1,000

7. Capital recovery = CRF x TCI $2,300 $3,500 $22,500 8. Total annual cost = Operating labor + maintenance materials + recordkeeping and reporting + overhead 

+ property taxes, insurance, and administration + capital recovery

$5,600 $9,700 $56,100 

WS Bag leak detector PM CEMS 
Appendix J-3: Other Monitoring Costs for Boilers and Process Heaters

Notes:1. Monitoring costs have been rounded to the nearest $100 to be consistent with level of rounding in original costs.2. Costs to be replaced include: (a) bag leak detector replacing opacity test; (b) CO CEMS replacing CO test and secondary chamber temperature monitor;(c) HCl CEMS replacing HCl test, HCl sorbent monitor (dry scrubbers) and scrubber liquor pH monitor (wet scrubbers); (d) PM CEMS replacing PM andopacity tests and and pressure drop monitor (wet scrubbers); (e) multi-metal/Hg CEMS replacing flue gas temperature monitor (wet scrubbers); (f) dioxinsorbent trap biweekly monitoring replacing fabric filter inlet temperature monitor; and (g) Hg sorbent trap biweekly monitoring replacing flue gas temperaturemonitor (wet scrubbers).Sources:1. Hospital/Medical/Infectious Waste Incinerators (HMIWI) [EPA-HQ-OAR-2006-0534] Testing and Monitoring Options and Costs Memo (IV-B-66).2. E-mail from Dan Bivins, EPA, to Mary Johnson, EPA. July 28, 2006. Some Preliminary Thoughts on the HWI Monitoring.3. Memorandum from Thomas Holloway, Midwest Research Institute, to Rick Copland, U.S. Environmental Protection Agency, Revised Testing and Monitoring Options and Costs for Medical Waste Incinerators (MWI’s) - Methodology and Assumptions. March 17, 1997.