MEMORANDUM 

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

FROM: Amanda Singleton and Susan McClutchey, ERG 

DATE: April 2010 

SUBJECT: 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 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 organized as follows: 

1.0 Introduction 

2.0 Inputs to Control 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 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 this model units 

were developed is 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 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 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 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.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. 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.”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 

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, 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 Industrial, 

Commercial, Institutional Boilers 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, Electrostatic Precipitator, 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.”8 

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. 

 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 (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.9

 Cost estimates for bag leak detection were based on estimates used in the 

2009 HMWI rulemaking.10 Cost estimates for opacity monitoring were based on a 1997 

memorandum prepared for the HMWI rulemaking, and escalated to 2008.11 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. 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 

1. Singleton, A., ERG. Developing Model Units for Boiler Area Sources. April 2010. 

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

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

2010. 

3. Singleton, A., ERG. MACT Floor Analysis for the Industrial, Commercial, Institutional 
Boilers National Emission Standards for Hazardous Air Pollutants – Area Source, April 

2010 

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. Methodology for Estimating Control Costs for 

Industrial, Commercial, Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source. April 2010. 

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

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

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

Control Cost Spreadsheet, July 2009 

11. 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 
Appendix A-1: Equations Used to Estimate Capital and Annual Costs of a Multiclone

Parameters/Costs Equation

A. Parameters

1. Exhaust Gas Flow Rate, acfm (AQ) calculated per boiler, see Section 2.0 of the memo.

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

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

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

15. Cost index

 a. 2008 545.4

 b. 2002 395.6

B. Total Capital Investment

TCI ($) = 3.5 x AQ x (545.4/395.6)

where AQ> 1,060

C. Annual Operating Costs, $/yr

O&M Costs = 8.5 x AQ x (545.4/395.6)

where AQ> 1,060

D. Annualized Costs

=O&M Costs + TCI x CRF

Source:

1. U.S. Environmental Protection Agency. Air Pollution Control Technology Fact Sheet. EPA-452/F-03-005. http://www.epa.gov/ttn/catc/dir1/fcyclon.pdf
Appendix A-2: Summary of Energy Audit Costs by SIC Code

SIC Code Description

Energy Audit 

Cost at 7%

01 Agricultural Production - Crops 854

02 Agricultural Production--Livestock 854

07 Agricultural Services 854

09 Fishing, Hunting, And Trapping 854

14 Nonmetallic Minerals, Except Fuels 854

16 Heavy Construction, Ex. Building 854

17 Special Trade Contractors 854

20 Food And Kindred Products 854

23 Apparel And Other Textile Products 854

24 Lumber And Wood Products 18292

26 Paper And Allied Products 18292

40 Railroad Transportation 854

41 Local And Interurban Passenger Transit 854

42 Trucking And Warehousing 854

43 U.S. Postal Service 854

44 Water Transportation 854

45 Transportation By Air, Water Transportation Services 854

47 Transportation Services 854

48 Communication 854

50 Wholesale Trade--Durable Goods 854

51 Wholesale Trade--Nondurable Goods 854

52 Building Materials & Garden Supplies 854

53 General Merchandise Stores 854

54 Food Stores 854

55 Automotive Dealers & Service Stations 854

56 Apparel And Accessory Stores 854

57 Furniture And Homefurnishings Stores 854

58 Eating And Drinking Places 854

59 Miscellaneous Retail 854

60 Depository Institutions 854

64 Insurance Agents, Brokers, & Service 854

65 Real Estate 854

70 Hotels And Other Lodging Places 854

72 Personal Services, Membership-Basis Organization Hotels 854

73 Business Services 854

75 Auto Repair, Services, And Parking 854

76

Miscellaneous Repair Services, Automotive Services, except 

Repair 854

79 Amusement & Recreation Services, Video Tape Rental 854

80 Health Services 854

81 Legal Services 854

82 Educational Services 854

83 Social Services 854

84 Museums, Botanical, Zoological Gardens 854

86 Membership Organizations 854

87 Engineering & Management Services 854

91 to 98 Government-Owned Buildings (State, Local, and Federal) 854

Unknown Unknown 854
Appendix A-3: Summary of Testing Costs at Area Source Boilers

OPTION 3

Model Unit

Design Capacity 

(mmBtu/hr)

Fuel 

Category

Total Testing 

(TCI and 

TAC) PM Hg CO - Test

CO-Monitor 

(TCI)

CO-Monitor 

(TAC) 7%

CO-Monitor 

(TAC) 3%

Total Testing 

(TCI and 

TAC)

Distillate Unit 1 0.06 Liquid 14,600 8,000 600 6,000 - - 6,000 

Distillate Unit 2 0.31 Liquid 14,600 8,000 600 6,000 - - 6,000 

Distillate Unit 3 0.74 Liquid 14,600 8,000 600 6,000 - - 6,000 

Distillate Unit 4 2.47 Liquid 14,600 8,000 600 6,000 - - 6,000 

Distillate Unit 5 6.76 Liquid 14,600 8,000 600 6,000 - - 6,000 

Distillate Unit 6 25.31 Liquid 14,600 8,000 600 6,000 - - 6,000 

Distillate Unit 7 173.44 Liquid 8,600 8,000 600 - 53,303 162,773 49,210 

Residual Unit 1 0.04 Liquid 14,600 8,000 600 6,000 - - 6,000 

Residual Unit 2 0.29 Liquid 14,600 8,000 600 6,000 - - 6,000 

Residual Unit 3 0.74 Liquid 14,600 8,000 600 6,000 - - 6,000 

Residual Unit 4 2.68 Liquid 14,600 8,000 600 6,000 - - 6,000 

Residual Unit 5 5.95 Liquid 14,600 8,000 600 6,000 - - 6,000 

Residual Unit 6 17.56 Liquid 14,600 8,000 600 6,000 - - 6,000 

Residual Unit 7 126.00 Liquid 8,600 8,000 600 - 53,303 162,773 49,210 

Biomass Unit 1 0.06 Biomass 19,000 8,000 5,000 6,000 - - 6,000 

Biomass Unit 2 0.28 Biomass 19,000 8,000 5,000 6,000 - - 6,000 

Biomass Unit 3 0.79 Biomass 19,000 8,000 5,000 6,000 - - 6,000 

Biomass Unit 4 2.46 Biomass 19,000 8,000 5,000 6,000 - - 6,000 

Biomass Unit 5 7.45 Biomass 19,000 8,000 5,000 6,000 - - 6,000 

Biomass Unit 6 21.04 Biomass 19,000 8,000 5,000 6,000 - - 6,000 

Biomass Unit 7 131.00 Biomass 14,000 8,000 6,000 - 53,303 162,773 49,210 

Coal Unit 1 0.02 Coal 19,000 8,000 5,000 6,000 - - 11,000 

Coal Unit 2 0.25 Coal 19,000 8,000 5,000 6,000 - - 11,000 

Coal Unit 3 0.78 Coal 19,000 8,000 5,000 6,000 - - 11,000 

Coal Unit 4 2.26 Coal 19,000 8,000 5,000 6,000 - - 11,000 

Coal Unit 5 6.68 Coal 19,000 8,000 5,000 6,000 - - 11,000 

Coal Unit 6 23.49 Coal 19,000 8,000 5,000 6,000 - - 11,000 

OPTIONS 1,2

Notes:

Testing:

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

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

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

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

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

estimated to range from approximately $10,000 - $15,000. 

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

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

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

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

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

Therefore, if a facility had more than one of the simpler tests to run (e.g., PM and CO, then the site-specific 

cost would start in the $5,000 - $7,000 with a few $1,000 added for subsequent pollutants. 

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

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

subtracted from the total testing costs.

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

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

subtracted from the total testing costs. Fuel analysis was estimated to cost $600 per year, although some 

boilers my request that their fuel supplier submit fuel analysis documentation instead of conducting the 

analysis at the facility.
Analyzers BEFORE AFTER

 CO 0 1

 SO2 0 0

 NOX 0 0

 HCl 0 0

 Mercury (and CO2/O2) 0 0

 CO2 0 0

 O2 0 0

 THC 0 0

Summary of Costs

First Costs Labor Test ODCs Total

 Planning 4,835 0 352 5,187

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

 Support Facilities 0 0 19,065 19,065

 Purchase CEMS Hardware 0 0 61,070 61,070

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

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

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

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

Annual Costs

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

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

 PM Monitor RCA 0 0 0 0

 PM Monitor RRA 0 0 0 0

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

 Recordkeeping and Reporting 1,822 0 160 1,982

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

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

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

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

Source:

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

Appendix A-4: Summary of CO CEMS
Appendix A-5: Other Monitoring Costs for Boilers

Parameters/Costs Equation

A. Parameters

1. Recording lime/carbon flow, min/4-hr period2. Annual operating hours, hr/yr (H)3. Cost index a. 2008 575.4 575.4 b. 2006 499.6 All costs 

are in $2006

 c. 1998

389.5

All costs are in $1997

 d. 1997 e. 1993 f. 19924. Operating labor wage rate, $/hr (LR)

$34.60

5. Capital recovery factor, 20-yr equipment life, 7% interest (CRF)

= [i x (1 + i)a] / [(1 + i)a - 1], where i = interest rate, a = equipment life 0.09439

B. Total Capital Investment, $ (TCI)

1. Planning $8002. Select type of equipment $4,5003. Provide support facilities $5004. Purchased equipment cost (PEC) $14,1005. Install and check equipment $4,8006. Perf. spec. tests (certif.) $07. Prepare QA/QC plan $8008. Total capital cost = Planning + selecting equipment + support facilities + PEC + installation + perf. spec. 

tests + QA/QC plan

$25,500 $43,137

C. Annual Costs, $/yr

1. Operating labor = (5 min to record lime/carbon flow/4-hr period) x (1 hr/60 min) x H x LR2. Maintenance materials = 0.02 x TCI $1,4773. Operation & maintenance = Day-to-day activities + annual RATA + CGA + annual QA + O&M review and update $6,000

$5,909

4. Recordkeeping and reporting = $1,000 x (525.4/386.5) $200 $1,4775. Overhead = 0.6 x (labor + maintenance materials)6. Property taxes, insurance, and administration

= 0.04 x TCI

$1,725

7. Capital recovery = CRF x TCI $3,500 $4,0718. Total annual cost = Operating labor + maintenance materials + recordkeeping and reporting + overhead 

+ property taxes, insurance, and administration + capital recovery

$9,700 $14,661

Bag leak detector Opacity
Appendix A-5: Other Monitoring Costs for Boilers

Notes:1. Monitoring costs have been rounded to the nearest $100 to be consistent with level of rounding in original costs.2. Costs to be replaced include: (a) bag leak detector replacing opacity test; (b) CO CEMS replacing CO test and secondary chamber temperature monitor;(c) HCl CEMS replacing HCl test, HCl sorbent monitor (dry scrubbers) and scrubber liquor pH monitor (wet scrubbers); (d) PM CEMS replacing PM andopacity tests and and pressure drop monitor (wet scrubbers); (e) multi-metal/Hg CEMS replacing flue gas temperature monitor (wet scrubbers); (f) dioxinsorbent trap biweekly monitoring replacing fabric filter inlet temperature monitor; and (g) Hg sorbent trap biweekly monitoring replacing flue gas temperaturemonitor (wet scrubbers).Sources:1. Hospital/Medical/Infectious Waste Incinerators (HMIWI) [EPA-HQ-OAR-2006-0534] Testing and Monitoring Options and Costs Memo (IV-B-66).2. E-mail from Dan Bivins, EPA, to Mary Johnson, EPA. July 28, 2006. Some Preliminary Thoughts on the HWI Monitoring.3. Memorandum from Thomas Holloway, Midwest Research Institute, to Rick Copland, U.S. Environmental Protection Agency, Revised Testing and Monitoring Options and Costs for Medical Waste Incinerators (MWI’s) - Methodology and Assumptions. March 17, 1997.