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MEMORANDUM

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

FROM: Amanda Singleton and Susan McClutchey, ERG

DATE: January 2011

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

Institutional Boilers for the National Emission Standards for Hazardous Air 

Pollutants – Area Source

1.0 INTRODUCTION

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

annual control costs for area source industrial, commercial, institutional boilers subject to the 

National Emission Standards for Hazardous Air Pollutants. Cost impacts were calculated for 

add-on control technologies as well as practices such as tune-ups, facility-wide energy 

assessments, testing and monitoring. The add-on control costs were estimated for a group of 

model boilers, based on a the distribution of boilers in the 13-state boiler inspector inventory 

database, which was extrapolated to a national estimate using EIA fuel consumption data for the 

remaining 13 states. The methodology used to develop model units and establish baseline 

emission inputs for each model unit are summarized in other memoranda1,2. 

This memorandum is organized as follows:

1.0 Introduction

2.0 Inputs to Control Cost Algorithms

3.0 Cost Algorithms for Add-on Control Devices

4.0 Costs for Tune-ups

5.0 Cost Algorithms for Operating Practices, Testing and Monitoring

6.0 References
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Appendices: Detailed Cost Algorithms and Inputs

2.0 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 Maximum Achievable Control Technology 

(MACT) floor or Generally Achievable Control Technology (GACT) emission rate or 

concentration; unit design capacity; and hours of operation were estimated using data reported in 

the 13-state boiler inspector inventory. 

Model boilers were created to represent boilers of various sizes firing biomass, coal, and 

liquid fuels. These model units included an average boiler design capacity, standardized to 

million British Thermal Units per hours (mmBtu/hr). Discussions of the how model units were 

developed are contained in another memorandum.

1 Annual operating schedule was not reported 

in the boiler inspector inventories, and since the annual costs increase with additional operating 

hours, this cost analysis assumes 8,400 hours per year of operation to conservatively estimate 

year-round operation accounting for a two week downtime period for maintenance.

Some control cost algorithms require a pollutant inlet rate to estimate variable operating 

costs, such as dust disposal costs. The methodology used to assign baseline emission factors and 

estimate the MACT floor emissions for each subcategory is discussed in separate memoranda2,3. 

In order to assign the appropriate inlet and emission rates to each model boiler in the cost 

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

model unit, based on the boiler fuel type, control devices installed, and combustor design.

Information on excess air (in percent) and exhaust temperature (in degrees Fahrenheit 

(F)) was reviewed in an EPA publication on fossil fuel industrial boilers4 and data reported in the 

Internal Combustion Coordinated Rulemaking (ICCR) for non-fossil fuel industrial boilers.5, 6 

Based on review of these documents, distillate oil model units were assigned a typical excess air 

value of 15% and an exhaust temperature of 350 degrees F. Residual oil model units were 

assigned a typical excess air value of 15% and an exhaust temperature of 400 degrees F. Coal 

model units less than 400 MMBtu/hr were assigned a typical excess air value of 50% and an 

exhaust temperature of 400 degrees F. Coal model units greater than 400 MMBtu/hr were 

assigned a typical excess air value of 30% and an exhaust temperature of 400 degrees F. Model 
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units with non-fossil material combinations were assigned a typical excess air value of 50% and 

an exhaust temperature of 400 degrees F. 

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

boilers were not available in the boiler inspector inventory. 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 associated with 

the model boiler is necessary.

Since the moisture content of area source boilers firing biomass fuels is unknown, the 

biomass model boilers were assigned to the fuel composition of wet biomass, since that would 

conservatively estimate a higher exhaust flowrate for the cost analysis. Next, the fuel category 

was assigned to a fuel composition according to Table 1 below:

Table 1: Boiler Fuel Categories in Database and their Corresponding Fuel Composition Equations

Fuel Category from 

Boiler Inventory

Fuel Composition Assumption for 

Combustion Kinetics Calculations

Coal Subituminous

Coal Sub-Bituminous over 400 MMBtu/hr

Light Liquid Distillate Liquids

Heavy Liquid Residual Liquids

Biomass Biomass (wet)

Average heating value and material analysis data (in percent by weight) were obtained 

for hydrogen, carbon, nitrogen, ash, sulfur, and oxygen for each fuel.7 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. An example calculation is presented in Appendix A-1 of the 

memorandum “Revised Methodology for Estimating Control Costs for Industrial, Commercial, 

Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air 

Pollutants – Major Source.”8

3.0 COST ALGORITHMS FOR ADD-ON TECHNOLOGIES

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. There is limited information 
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available about the control devices currently installed at area source boilers. Permit databases in 

Wisconsin and Pennsylvania include information on control devices utilized by coal and biomass 

boilers. Further, approximately 664 area source boilers were reported in the 2008 Combustion 

Survey and the majority (69 percent) of the 104 biomass boilers were reported have a multiclone 

installed or were uncontrolled. 98 percent of the liquid boilers were reported to be uncontrolled, 

and 37 percent of coal-fired boilers were reported to be uncontrolled. A few larger boilers have 

more advanced controls installed including a fabric filter, electrostatic precipitator (ESP), venturi

scrubber or wet scrubbers. However these sources with advanced controls tend to be located at 

larger area source boilers at industrial facilities and are not representative of the boilers at 

commercial and institutional sources. When looking at the boilers with design capacities less 

than 10 mmBtu/hr, all liquid and coal boilers are uncontrolled and the majority of biomass 

boilers are uncontrolled, with 36 percent of the units reported to have multiclones installed. No 

units less than 10 mmBtu/hr have any advanced controls. 

The controls analyzed for the impacts analysis include the fabric filter, low NOx burner, 

linkageless boiler management system, and multiclone. In addition, when add-on technologies 

are used, consideration must be given to added expenses such as ductwork and associated 

equipment. All of these control devices, with the exception of a multiclone, were discussed in 

detail in the memorandum “Revised Methodology for Estimating Control Costs for Industrial, 

Commercial, Institutional Boilers and Process Heaters National Emission Standards for 

Hazardous Air Pollutants – Major Source.” Additional discussion on the algorithms used to 

calculate capital and annual costs of multiclones and the inputs used in that algorithm are 

presented in this section. 

Similar to the cost estimate analysis prepared for the major source rule, all costs were 

escalated to 2008 dollars. When capital recovery costs were calculated, an interest rate of 7 

percent was applied over the life of the equipment

3.1 Fabric Filter, Electrostatic Precipitator, Low NOx Burner/Replacement 

burner/Linkageless Boiler Management Systems, and Energy Assessments

A description of the assumptions, inputs, and calculations used to estimate the costs for 

each of these control technologies are described in the “Revised Methodology for Estimating 

Control Costs for Industrial, Commercial, Institutional Boilers and Process Heaters National 

Emission Standards for Hazardous Air Pollutants – Major Source.”

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For Energy Assessments at area source facilities, each facility’s NAICS code was 

unknown. Instead, the cost of the assessment was determined according to the distribution of 

two-digit SIC codes in the boiler-inspector inventory. SIC codes 24 and 26, representing the 

wood products and pulp and paper products industries, respectively, were estimated to require an 

industrial-scale Energy Assessment, at a cost of $75,000 per facility. The remaining SIC codes 

expected to be affected by the final rule represent facilities in the commercial and institutional 

sectors (such as schools, hospitals, and churches) and were estimated to require a smaller-scale 

assessment, at an average cost of $3,500 per facility. The cost of each assessment was annualized 

over 5 years at 7 percent to obtain an annualized cost estimate for energy assessments. Appendix 

A-1 details the energy assessment costs assigned to each SIC code anticipated to be affected by 

the area source boiler rule. 

3.2 Multiclone

A multiclone aids in the reduction of PM emissions. These controls are most effective at 

capturing PM emissions from large particles (>10 μm in aerodynamic diameter); they also 

achieve modest reductions for PM emissions between 10 and 2.5 μm in aerodynamic diameter. 

The costs for multiclones were developed using a U.S. EPA Air Pollution Control Technology 

Fact Sheet (EPA 452/F03-005). According to this factsheet, typical exhaust gas flowrates 

through a cyclone have a minimum flowrate of 1,060 standard cubic feet per minute. Some of the 

model boilers created for area source units are small enough that a multiclone control technology 

may not be feasible. If the calculated exhaust gas flowrate of a boiler was less than 1,060 scfm, 

no multiclone control costs were estimated for the model boiler. The fact sheet presents a range 

of costs in 2002$ for both initial capital investment and annual operation and maintenance, and 

were updated to 2008$. Given the basic cost estimate available for multiclones, and the variation 

in size among affected area source boilers, the upper range of capital cost and operating and 

maintenance cost ranges was used to estimate a more conservative cost. The cost estimates do 

not include dust disposal, which could be added to the current cost estimates by calculating the 

quantity of dust collected by the multiclone in tons per year and multiplying this tonnage by a 

solid waste disposal fee of $42.14 per ton. The capital recovery estimates were calculated 

assuming a 20-year-life. Appendix A-2 details the equations used to estimate the cost to install

and operate a multiclone.
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4.0 COST FOR TUNE-UPS

The cost for tune-ups were based on quotes obtained from the Industrial Extension 

Service USI Boiler Efficiency Program12. The initial tune-up capital costs range from $200 for 

very small boilers to $8000 for larger boilers. A conservative average of $5000 was used, which 

became $6,477 when adjusted to $2008. The Total Annual Cost was estimated to be $2,228 by 

assuming 7% interest over 5 years for biennial tune-ups. The total estimated capital cost with the 

conservative tune-up estimate was $1.3 billion. When using the $200 estimate for very small 

units, this number was reduced to $800 million.

5.0 COST ALGORITHMS FOR OPERATING PRACTICES, TESTING 

AND MONITORING

Capital and annual costs for testing include stack tests for PM, Hg, and CO. The final rule 

provides a compliance alternative to conduct a fuel analysis in lieu of a stack test for mercury, if 

the fuel contains less mercury than the MACT floor emission limit for the appropriate 

subcategory. The final rule also provides compliance flexibility to sources that consecutively 

test at 75 percent or less of the emission limits to test at 3-year intervals instead of annual testing. 

Since the number of sources expected to qualify for the 3-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 coal-fired unit will conduct 

testing for all pollutants annually, and new liquid fuel and biomass units will conduct stack 

testing for PM . Testing cost estimates were based on estimates used in the Phase II test plan and 

were adjusted down slightly to account for lesser 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 approximately $5,000 to $7,000. For the pollutants that involve more lab analysis (e.g., 

mercury), the testing costs range from approximately $10,000 - $15,000. Although the 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 -
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$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 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), then the site-specific cost would start in the $5,000 -

$7,000 with a few $1,000 added for the second pollutant. A summary of the testing costs used in 

this cost analysis are presented in Appendix A-3.

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.

Monitoring costs are included for opacity monitoring (for units without bag leak 

detectors). Bag leak detection and oxygen monitoring for units in the chosen option with fabric 

filters. Cost estimates for bag leak detection were based on estimates used in the 2009 HMWI 

rulemaking.9 Cost estimates for opacity monitoring were based on a 1997 memorandum prepared 

for the HMWI rulemaking, and escalated to 2008.10 Cost estimates for oxygen monitoring were 

based on Chapter 4 of the OAQPS Control Cost Manual, Sixth Edition11. Monitoring costs 

include the cost of planning, selecting and installing monitoring equipment and support facilities; 

conducting an annual relative accuracy test audit and writing the report; cylinder gas audits; 

developing a QA/QC plan; monitor O&M; and capital recovery. Bag leak detection and opacity 

monitoring were all annualized over a 20-year lifetime. A summary of the monitoring costs are 

presented in Appendices A-4 and A-5.

6.0 REFERENCES

1. Singleton, A., ERG. Methodology for Developing Model Units for Industrial, 

Commercial, and Institutional Boilers National Emission Standards for Hazardous Air 
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Pollutants – Area Source. April, 2010.

2. Gibson, G. and A. Singleton, ERG. Revised Development of Baseline Emission Factors 

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

January, 2011.

3. Singleton, A. and B. Long, ERG. Revised MACT Floor and GACT Analysis for the 

Industrial, Commercial, and Institutional Boilers National Emission Standards for 

Hazardous Air Pollutants – Area Source. January, 2011

4. 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.

5. 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.

6. 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.

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

8. Singleton, A., and S. McClutchey. Revised Methodology for Estimating Control Costs 

for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission 

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

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

Control Cost Spreadsheet, July 2009

10. 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

11. 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.

12. Eckerlin, Dr. H.M. and E.W. Soderberg. Industrial Extension Service. USI Boiler 

Efficiency Program. Summary of the Findings and Recommendations of Evaluations of 

State-Owned Boiler Facilities. February 25, 2004.