1 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 f or Industrial, Commercial, Institutional Boilers for the National Emission Standards for Hazardous Air Pollutants

– Area Source

1.0 INTRODUCTION

T his 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

ass essments , 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

e mission inputs for each model unit are summarized in other memoranda 1 ,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 References2 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 dr y 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 ho w model units were developed are contained in an other memorand um
. 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 dispo sal costs

. The methodology used to assign baseline emission factors and estimate the MACT floor emissions for each subcategory is discussed in separate memoranda 2,3

. In order to assign the appropriate inlet and emission rates to each model boiler in the co st analysis, a VLOOKUP table was created in Excel to map the appropriate emission value to each mode l unit , based on the boiler fuel type, control devices installed, and combustor design. Information on excess air (in percent) and exhaust temperature (in d egrees Fahrenheit (F)) was reviewed in an EPA publication on fossil fuel industrial boilers 4 and data reported in the Internal Combustion Coordinated Rulemaking ( ICCR ) for non

- fossil fuel industrial boilers. 5, 6 Based on review of these documents, distill ate 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 t han 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. Model3 un its 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 b oiler 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 m odel 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 Kinetic s Calculations Coal Subituminous Coal Sub

- Bituminous over 400 MMBtu/hr Light Liquid Distillate Liquids Heavy Liquid Residual Liquids

Biomass Biomass (wet)

A verage 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 p ounds 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 Proce ss 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 information4 available about the control devices currently installed at area source boil ers. Permit databases in Wisconsin and Pennsylvania include information on control devices utilized by coal and biomass boilers. Further, a pproximately 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 ad vanced 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 re presentative of the boilers at commercial and institutional sources. When l ooking 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 perc ent 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 anal ysis include the fabric filter , low NOx burner , linkageless boiler management system, and multicl one . 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 “ Re vised 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 an d 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 we re
es calated 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, Institution al Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants

– Major Source. ” 85 For Energy Assessments at area source facilities , each facilit y ’ 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 c ost 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

assessm ent , 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 an ticipated 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 flowrate s 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 ex haust 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 an nual operation and maintenance, and

were u pdated to 2008$. G iven the basic cost estimate available for multiclones, and the variation in size among aff ected 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.6 

### 4.0 **COST FOR TUNE -**  **UPS**

The cost for tune

- ups were based on quotes obtained from the Industrial Extension Service USI Boiler Efficiency Program 12 . 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 bie nn i al tune

- ups . The total estimated capital cost with the conservative tune

- up estimate was $1.3 billion . When using the $200 es t imate 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 approp riate subcategory. The final rule also provides compliance flexibili ty 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 wil l con duct 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 s imultaneously, 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 diffi cult and uncertain. For example, if a facility needs PM data and CO data, the test costs would not be twice the $5,000

-7 $7,000 price because some of the cost s are associated with getting the testing contractor to the site and setting up the equipment (th ese 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 wit h 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 estima ted, 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 t o 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 $1 1,000 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 ) . B ag leak detection and oxygen monitoring f or 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. 1 0 Cost estimates for oxygen monitoring were based on Chapter 4 of the OAQPS Control Cost Manual, Sixth Edition 11

. 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 Appendi ces A

- 4 and A

- 5

. 

### 6

**. 0**  **REFER E**  **NCES**

1. Singleton, A., ERG. Methodology for Developing Model Units for Industrial, Commercial, and Institutional Boilers National Emission Standards for Hazardous Air8 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 A nalysis 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 In formation: 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 Analys is 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 40 th 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 201 1

. 9

. Holloway, Thomas. RTI International. E

- mail with attachment: HMWI Fabric Filter Control Cost Spreadsheet , July 2009
10

. Holloway, Thomas. Midwe st 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. En vironmental 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 Eff iciency Program. Summary of the Findings and Recommendations of Evaluations of State

- Owned Boiler Facilities. February 25, 2004.