### 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 Cont rol Costs for Industrial, Commercial, Institutional Boilers for the Nationa l 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, co mmercial, institutional boilers subject to the

National Emission Standards for Hazardous Air Po llutants. Cost impacts were calculated for add-on control technologies as well as practices such as tune-ups, facili ty-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 boile rs in the 13-state boiler insp ector inventory database, which was extrapolated to a national estimate using EI A 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 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 Cost Algorithms for Operating Pr actices, 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 imp acts include primary fuel type, exhaust gas flow rate (on both an actual and dry standard basis); flue gas temperat ure, oxygen, and moisture; baseline emissions entering the control device ; target Maximum Achiev able Control Technology (MACT) floor or Generally Achievable C ontrol 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 firi ng 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 tw o week downtime period for maintenance. Some control cost algorithms re quire a pollutant inlet rate to estimate variable operating costs, such as dust disposal costs. The methodol ogy used to assign baseline emission factors and

estimate the MACT floor emissions for each subc ategory is discussed in separate memoranda 2,3



### . In order to assign the appropria te 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, c ontrol devices installe d, and combustor design. Information concerning excess air (in percen t) and exhaust temperature (in degrees Fahrenheit (F)) was reviewed in an EPA pub lications on fossil fuel industrial boilers 4 

### and data reported in the Internal Combustion Coordi nated 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 va lue 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 we re assigned a typical excess air value of 50% and an exhaust temperatur e 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, moistu re content, and per cent oxygen for model boilers was not available in the boiler inspecto r inventory. Therefore, these parameters were

calculated from the combustion kine tics of burning the primary fuels. For this calculation, the hydrogen, carbon, nitrogen, oxygen, and water compositi on 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 compositi on according to Table 2 below:

Table 1: Boiler Fuel Categories in Database an d 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 analys is data (in percent by weight) were obtained for hydrogen, carbon, nitrogen, ash, sulf ur, 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 fu el (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 per centage 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 (%), a nd exhaust Oxygen content (%, dry basis) for gas model units. An example calculation is pr esented in Appendix A-1 of the memorandum Methodology for Estimating Control Costs for th e Major Source Industrial, Commercial and

Institutional Boilers and Pro cess Heaters National Emission Standards for Hazardous Air

Pollutants.” 8

## 3.0 COST ALGORITHMS FO R ADD-ON TECHNOLOGIES

Add-on control technologies are t hose 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 inst alled at area source boile rs. 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 we re reported to be uncontrolled, and 37 percent of coal-fired boilers were reporte d to be uncontrolled. A few larger boilers have

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

scrubber or wet scrubbers. Howeve r these sources with advanced controls tend to be located at larger area source boilers at indus trial facilities and are not representative 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, while 36 percent of the un its 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 fi lter, low NOx burner, linkageless boiler management system, and multic lone. 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 Emi ssion Standards for Hazardous Air Pollutants.” Additional discussion the algorithms used to ca lculate capital and annual costs of multiclones and the inputs used in that algorithm ar e presented in this section. Similar to the cost estimate analysis prepar ed for the major source rule, all costs were

escalated to 2008 dollars. When capital recovery costs were ca lculated, an inte rest rate of 7 percent was applied over th e life of the equipment.

### 2.1 Fabric Filter, Electrostatic Prec ipitator, Low NOx Burner/Replacement burner/Linkageless Boiler Management Systems, and Energy Audits A description of the assumptions, inputs, and ca lculations used to estimate the costs for each of these control technologies are descri bed 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 facilitie s, each facility’s NAICS code was unknown. Instead, the cost of the audit wa s determined according to the dist ribution of two-digit SIC codes in the boiler-inspecto r inventory. SIC codes 24 and 26, repr esenting 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 remain ing SIC codes expected to be affected by the proposed rule represent facilities in the commer cial and institutional se ctors (such as schools, hospitals, and churches) and were es timated to require a smaller-scale audit, at an average cost of $3,500 per facility. The cost of each audit was annualized over 5 year s at 7 percent to obtain an annualized cost estimate for energy audits. Append ix A-2 details the energy audit costs assigned to each SIC code anticipated to be a ffected by the area source boiler rule.

2.2 Multiclone

A multiclone aids in the reduction of PM emi ssions. These controls are most effective at capturing PM emissions from large particles (>10 μ m in aerodynamic diameter), but these

controls also achieve modest reducti ons for PM emissions between 10 and 2.5 μ m in aerodynamic diameter. The costs for multiclone s 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 mini mum flowrate of 1,060 standard cubic feet per minute. Some of th e model boilers created for area s ource 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 contro l 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. Give n the basic cost estimate ava ilable for multiclones, and the variation in size among affected ar ea 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 adde d to the current cost estimates by calculating the quantity of dust collected by th e multiclone in tons per year and multiplying this tonnage by a solid waste disposal fee of $42.14 per ton. The capital recovery estim ates were calculated assuming a 20-year-life. Appendix A-1details the e quations 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 altern ative 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 pr oposed rule also provides complian ce flexibility to sources that consecutively test at 90 percent or less of the emi ssion limits to test at 3-year intervals instead of annual testing. Since the number of sources expe cted to qualify for th e 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 tes ting frequency. The cost analysis also assumes that every solid fuel unit will conduct testing for all pollutants an nually, and liquid fuel un its 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 test ing costs assume that all pollutants will be tested simultaneously, or over the course of a sing le 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 analys is (e.g., mercury), the testing costs range from approximately $10,000 - $15,000. Although the cost range s can be applied as is for cases where a single pollutant is being measure d, 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 setti ng up the equipment (these are one-time costs and would not be duplicated re gardless of the number of pollutants tested). Therefore, if a facility had more than one of the simpler test s 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 ar e presented in Appendix A3. The costs associated with installing test por ts and renting scaffolding for stacks without test ports were also estimate d, based on a preliminary engineer ing estimate provided by ERG Air Laboratory Staff. The assumptions included the installa tion 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 expe nses 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 estimat ed $11,000 per boiler to inst all ports for testing. The cost of temporary scaffolding was also incl uded in the cost estimate for testing. An assumption of three weeks of scaffolding to in stall ports and two add itional 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 mo nitors were developed using the 2007 EPA

CEMS cost model. 9 

### Cost estimates for bag leak detecti on 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 instal ling monitoring equipment and support facilities; conducting an annual relative accuracy test audi t and writing the report; cylinder gas audits; developing a QA/QC plan; monitor O&M; and cap ital recovery. CO mon itors were annualized over a 10-year lifetime, using guidance from the 2007 EPA CEMS cost model. Bag leak detection and opacity monitoring we re all annualized over a 20-year lifetime. A summary of the monitoring costs are presente d 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. Devel opment of Baseline Emission Factors for Boilers and Process Heaters at Commercial, In dustrial 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 Materi als 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 40 th 

### edition . 1992.

8. Singleton, A., and S. McClutchey. Met hodology for Estimating Control Costs for Industrial, Commercial, Institutional Boile rs 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 Internati onal. E-mail with attachment: HMWI Fabric Filter Control Cost Spreadsheet , July 2009

11. Holloway, Thomas. Midwest Research In stitute, Memo to Rick Copland, U.S. Environmental Protection Agency, Revised Testing and Monitoring Options and Costs for Medical Waste Incinerators (M WI’s) - Methodology and Assumptions . March 17, 1997Appendix A-1: Equations Used to Estimate Capital and Annual Costs of a Multiclon e 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/tt n/catc/dir1/fcyclon.pdfAppendix A-2: Summary of Energy Audit Costs by SIC Cod e

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 854Appendix A-3: Summary of Testing Costs at Area Source Boiler s 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 - 162,773 53,303 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 - 162,773 53,303 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 - 162,773 53,303 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.

A lthough 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 recover y 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 CEMSAppendix A-5: Other Monitoring Costs for BoilersParameters/Costs EquationA. Parameters1. Recording lime/carbon flow, min/4-hr period2. Annual operating hours, hr/yr (H)3. Cost indexa. 2008575.4 575.4b. 2006499.6 All costsare in$2006c. 1998389.5All costsare in$1997d. 1997e. 1993f. 19924. Operating labor wage rate, $/hr(LR)$34.605. Capital recovery factor, 20-yrequipment life, 7% interest (CRF)= [i x (1 + i)a] / [(1 + i)a- 1], where i = interest rate, a = equipment life0.09439B. 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 $43,137C. Annual Costs, $/yr1. 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$5,9094. Recordkeeping and reporting = $1,000 x (525.4/386.5) $200 $1,4775. Overhead = 0.6 x (labor + maintenance materials)6. Property taxes, insurance, andadministration= 0.04 x TCI$1,7257. 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 $14,661OpacityBag leak detectorAppendix A-5: Other Monitoring Costs for BoilersNotes: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 monitoringreplacing 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, RevisedTesting andMonitoring Options and Costs for Medical Waste Incinerators (MWI’s) - Methodology and Assumptions. March 17, 1997.