MEMORANDUM 

TO: Brian Shrager, U.S. Environmental Protection Agency, OAQPS 

FROM: Eastern Research Group, Inc. 

DATE: November 2011 

SUBJECT: Revised (November 2011) 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 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,” as well as other voluntary data 

submitted as part of this rulemaking. 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 limits6

 and 

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

bed scrubber, dry injection/ fabric filter systems (DIFF), activated carbon injection (ACI), 

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. 

Also, for units with selective catalytic reduction (SCR) and a scrubber installed, implementation 

of halogen addition and/or slurry additive systems were analyzed. 

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. The cost 

equations for ACI provided cost estimates at 2009 dollars, which were left as is rather than deescalating to an older year. 

 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 ($/gal) .0054 Air Compliance Advisor User Guide—
Cost Component Cost (2008$) Source 

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, dry injection/fabric filter, ESP and a CO oxidation catalyst as well as any 

duct work associated with the installation of these control devices. Per guidance in the mercury 
background document, a retrofit factor of 1 was used for ACI costs as ACI systems do not 

typically require significant amounts of additional space.10 A factor of 1.3 in the EPA CueCost 

model represents a retrofit of medium difficulty. 

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, DIFF CO oxidation catalysts, and ESPs. 

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 with 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 Dry Injection/Fabric Filter (DIFF) 

The inclusion of dry injection prior to a fabric filter offers emission control for hydrogen 

chloride (HCl). The algorithms used to estimate capital and annual costs of DIFF systems were 

based on those 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 I-1. 

The algorithms estimate the capital cost of the equipment based on the exhaust flowrate. Annual 

costs include lime, water, dust disposal, electricity, maintenance, labor, bag replacement, 

maintenance labor, compressed air, capital recovery costs, overhead, administrative costs, 

property taxes, and insurance. 

3.3 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. 

3.4 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. 
3.5 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. 

3.6 Activated Carbon Injection 

Activated carbon injection (ACI) offers emission control for Hg. Cost estimates for ACI 

were derived from a Sargent & Lundy report which presents recent cost estimates based on 

industry experience.10 This same methodology was also used for the Utility NESHAP ACI cost 

calculations.28 While the Sargent & Lundy report provided example calculations for coal only, 

their analysis was applied to all subcategories (e.g. biomass and heavy liquid) for the Boiler 

MACT cost estimates. Appropriate fuel-specific information including HHV and ash content, 

was gathered for other fuel types to input into the equations, while this information for coal was 

kept consistent with the Sargent & Lundy report values. The cost estimate assumed all carbon 

and fly ash waste was disposed of and calculated the cost of waste disposal; this provided a 

conservative estimate since no beneficial use for the fly ash was considered. The carbon feed 

rate was based off the type of control device currently available. If a boiler had an existing 

fabric filter then 2 lb/MMacf (pounds per million actual cubic feet) was used, otherwise a value 

of 5 lb/MMacf was selected for the carbon feed rate. See Appendix F-1 for the methodology in 

calculating ACI capital and annual costs. 

3.7 Slurry Additive and Halogen Addition Systems 

The Sargent & Lundy report provided alternatives for reducing mercury in lieu of the use 

of ACI if certain criteria are met.10 These alternatives include slurry additive and halogen 
addition systems. These alternatives are applicable if a boiler has an SCR already installed and it 

is estimated that a wet scrubber would be installed to meet the HCl limit. A co-benefit between 

the SCR and wet scrubber during simultaneous operation would allow up to 80% reduction in 

mercury. To achieve the proper co-benefit a slurry additive is necessary, however. Furthermore, 

if the boiler fires sub-bituminous or lignite coal then a halogen addition system is required in 

order for the chemistry of the interactions to work. See the Sargent & Lundy report for the full 

background on the slurry additive and halogen addition systems. It is noted for the Boiler 

MACT cost analysis that none of the boilers met the criteria for the co-benefit of SCR and wet 

scrubber operation. See Appendices F-2 and F-3 for the methodology related to the slurry 

additive and halogen addition systems capital and annual costs. 

3.8 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. 
3.9 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 

3.10 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. 

3.11 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, limited use boilers (operating less than 

876 hours per year), and natural gas and refinery gas-fired boilers of all sizes. For all other 

boilers greater than 10 mmBtu/hr there is a work practice standard for dioxin/furan in addition to 

numeric emission limits for the other pollutants. 

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 in initial set-up costs was annualized over five years 

and added to the subsequent year costs for an annual tune-up. Although the rule allows a biennial 
tune-up in some circumstances we used the annual tune-up as the basis for this analysis to be 

conservative. 

Annual Tune-up Cost ($2008) = {[C$2004 * (X2008 / X2004) * i * (1+i)

y

] / [(1+i)

y

 – 1)]} + 

[Z$2004 * (X2008 / X2004)] = $2,875 (Equation 1)

Where: 

C$2004 = Average set-up cost, $5,000 (from 2004) 

X2008 = 2008 cost index, 575.4 

X2004 = 2004 cost index, 442.2 

i = interest rate, 7% 

y = length of annuity, 5 years 

Z$2004 = annual tuning cost, $1,000 (from 2004) 

Biennial tune-up costs would provide some cost savings, although the costs of the initial 

tune-up set-up must be factored into both of the work practice frequencies, so this analysis used a 

single tune-up cost, which is based on an annual frequency. The annualized cost for a biennial 

tune-up is $2,228 per boiler, as shown in Equation 2. 

Biennial Tune-up Cost ($2008) = {[C$2004 * (X2008/X2004) * i * (1+i)

y

] / [(1+i)

y

 – 1)]} + 

[(Z$2004 / 2) * (X2008/X2004)] = $2,228 (Equation 2)

Where: 

C$2004 = Average set-up cost, $5,000 (from 2004) 

X2008 = 2008 cost index, 575.4 

X2004 = 2004 cost index, 442.2 

i = interest rate, 7% 

y = length of annuity, 5 years 

Z$2004 = annual tuning cost, $1,000 (from 2004) 

 For new model boilers with a rated heat capacity less than 500,000 Btu per hour, a tuneup cost of $200 was selected. We did not estimate this smaller cost for existing units because the 

ICR survey asked questions about groups of small units that were less than 10 mmBtu/hr and we 

do not know the exact size of these small units. This value was based on research of tune-up 

costs for similarly sized home boiler programs, which suggested the costs of a tune-up ranged 

from $60 to $150.26,27 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. We used the NAICS code to determine the length and cost of the audit, since 

the length of the audit in the proposal is tiered based on facility energy consumption. 

Sector NAICS Codes 

Industrial 221, 311, 312, 313, 314, 316, 321, 322, 323, 324, 325, 326, 327, 331, 332, 

333, 334, 335, 336, 337, & 339 

Commercial 111, 113, 115, 211, 212, 423, 424, 441, 481, 482, 486, 488, 493, 531, 541, 

561, 562, 611, 622, 623, 811, 921, & 928 

For industrial facilities 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; 

$18,292 annually. 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; $854 annually. 

 

4.3 Testing 

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

Additionally, capital and annual costs to repeat testing to meet the ‘worst case’ conditions in the 

proposed rule include the cost to stack test for Hg and HCl. 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 75 percent or less of the emission limits, or at or below the emission limit for limits that 

are based on minimum detection levels. The flexibility allows these sources to test at two-year 

intervals instead of annually. Because the number of sources expected to qualify for the reduced 
testing interval is unknown, and all sources must test annually for the first two 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 and CO 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 Hg 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. 

Annual costs were estimated for mercury fuel spec analyses for gaseous units as well. 

For certain boilers it is necessary to determine its mercury content on a monthly basis in order to 
determine if the fuel qualifies as a gas 1 fuel or if it is a gas 2 fuel subject to emission limits. The 

average monthly cost for the fuel analysis is estimated at $200 for an annual cost of $2,400. 

4.4 Monitoring 

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

continuous emissions monitoring systems (CEMS) (for certain units with an average annual heat 

input rate from solid fossil or heavy liquids greater than 250 mmBtu/hr), bag leak detection (for 

units with fabric filters), scrubber parametric monitoring (for units with scrubbers), and O2

monitors (for units greater than 10 mmBtu/hr). Cost estimates for O2 monitors were based on in 

situ monitor costs from Chapter 4 of the OAQPS Control Cost Manual, Sixth Edition24. 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. 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. Eastern Research Group, Inc. Revised (November 2011) Data Dictionary for Boiler, 

Process Heater, and Other Combustion Unit Survey Databases. November 2011. 

4. Eastern Research Group, Inc. Revised (November 2011) Standardization of Reported 

Data from the Questionnaire for Boilers, Process Heaters, Incinerators and Other 

Combustion Units. November 2011. 

5. Eastern Research Group, Inc. Revised (November 2011) Development of Baseline 

Emission Factors for Boilers and Process Heaters at Commercial, Industrial and 

Institutional Facilities. November 2011. 
6. Eastern Research Group, Inc. Revised MACT Floor Analysis (November 2011) for the 

Industrial, Commercial, Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source. November 2011. 

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. Sargent & Lundy, IPM Model – Revisions to Cost and Performance for APC 

Technologies: Mercury Control Cost Development Methodology (Project 12301-009). 

March 2011. 

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. Eastern Research Group, Inc. 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. 

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. 

 

24. U.S. Environmental Protection Agency. EPA Air Pollution Control Cost Manual, Sixth 

Edition. EPA/452/B-02-001. Office of Air Quality Planning and Standards. January, 

2002. 

26. Ed’s Heating and Air, Inc. 1099 Pelto Path Woodbury, MN, 55129. 

http://www.merchantcircle.com/blogs/Eds.Heating.And.Air.Inc..Woodbury.MN.651-775-

7490/2008/10/Furnace-Tune-Up-Cost/126531

27. Five State Heating and Cooling, Charlotte, NC. 

http://www.fivestarheatingandcooling.com/

28. U.S. Environmental Protection Agency. NESHAP for Coal- and Oil-Fired Electric 

Utility Steam Generating Units (Docket # EPA-HQ-OAR-2009-0234). May 2011.