MEMORANDUM

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

FROM: Amanda Singleton and Susan McClutchey, ERG

DATE: 24 March 2010

SUBJECT: DRAFT Methodology for Estimating Control Costs for the Area Source 

Industrial, Commercial and Institutional Boilers National Emission Standards for 

Hazardous Air Pollutants

1.0 INTRODUCTION

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

annual control costs for area source industrial, commercial and institutional boilers. Cost 

impacts were calculated for add-on control technologies as well as practices such as tune-ups, 

facility-wide energy audits, 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 divided into the following sections:

1.0 Introduction

2.0 Inputs for Cost Algorithms

3.0 Cost Algorithms for Add-on Control Devices

4.0 Cost Algorithms for Operating Practices, Testing and Monitoring

5.0 References

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 MACT floor 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 this model units 

were developed is contained in another memorandum.

(model unit memo). 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 

memoranda(Gibson,Baseline and Singleton MACT Floor memos) . 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 units, based on the boiler fuel type, control 

devices installed, and combustor design.
Information concerning excess air (in percent) and exhaust temperature (in degrees 

Fahrenheit (F)) was reviewed in an EPA publications on fossil fuel industrial boilersxx and data 

reported in the ICCR for non-fossil fuel industrial boilers.(Alvis, ICCR database) 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 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 was 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 2 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)

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.(STEAM, its generation and uses, 40th Ed)
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 presented in Appendix A-1 of the 

memorandum Methodology for Estimating Control Costs for the Major Source Industrial, 

Commercial and Institutional Boilers and Process Heaters National Emission Standards for 

Hazardous Air Pollutants.”(cite major source control memo)

.

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 

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, 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, 

while 36 percent of the units are 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 “Methodology for Estimating Control Costs for the Major Source 

Industrial, Commercial and Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants.” Additional discussion 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.

2.1 Fabric Filter, Low NOx Burner/Replacement burner/Linkageless Boiler 

Management Systems, and Energy Audits

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

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

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

National Emission Standards for Hazardous Air Pollutants.”(cite major source control memo)

For Energy Audits at area source facilities, each facility’s NAICS code was unknown. 

Instead, the cost of the audit 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 

Audit, at a cost of $75,000 per facility. The remaining SIC codes expected to be affected by the 

proposed rule represent facilities in the commercial and institutional sectors (such as schools, 

hospitals, and churches) and were estimated to require a smaller-scale audit, at an average cost of 

$3,500 per facility. The cost of each audit was annualized over 5 years at 7 percent to obtain an 

annualized cost estimate for energy audits. Appendix A-2 details the energy audit costs assigned 

to each SIC code anticipated to be affected by the area source boiler rule. 

2.2 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), but these 

controls 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 very small, and 

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. 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-1details the equations used to estimate the cost to install

and operate a multiclone.

4.0 COST ALGORITHMS FOR TESTING AND MONITORING

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

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 proposed rule also provides compliance flexibility to sources that 

consecutively test at 90 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 solid 

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

testing for PM and CO but will conduct fuel analysis for mercury. 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 - $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 A3.

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

detectors), bag leak detection (for units with fabric filters), and CO monitors (for units greater 

than 100 mmBtu/hr). Cost estimates for CO monitors were developed using the 2007 EPA 

CEMS cost model.(See 2007 CEMS COST TOOL) Cost estimates for bag leak detection were based on 

estimates used in the 2009 HMWI rulemaking.(SEE JUlY 2009 HWMI memo) Cost estimates for opacity 

monitoring were based on a 1997 memorandum prepared for the HMWI rulemaking, and 

escalated to 2008.(1997 holloway memo) 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. CO monitors were annualized over a 10-year lifetime, using guidance from 

the 2007 EPA CEMS cost model. 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.

5. 0 REFERENCES

[UNDER DEVELOPMENT]