### MEMORANDUM
TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS
FROM: Amanda Singleton and Susan McClutchey, ERG
DATE: April 2010
SUBJECT: Methodology for Estimating Cont rol Costs for Industrial, Commercial, Institutional Boilers and Process He aters National Emission Standards for Hazardous Air Pollutants – Major Source



# 1.0 Introduction

This memorandum discusses the algorithms and inputs used to estimate capital and annual control costs for the Major Source Industr ial, Commercial, and Institutional Boilers and
Process Heaters for the National Emission Standard s for Hazardous Air Pollutants. Cost impacts were calculated for add-on control technologies, te sting and monitoring, and work practices such as tune-ups and facility-wide energy audits. The add-on control costs were estimated for each individual boiler and process heater based on a combination of reported and standardized data, including fuel types, unit sizes, current c ontrol devices, and baseline emission values. Characteristics necessary to estimate control cost s were assigned to specific units based on data reported by industry in the 2008 Questionnaire for Boilers, Process Heaters, Incinerators and
Other Combustion Units 1 

### (ICR No. 2286.01, OMB Control No. 2060-0616, EPA Form No. 5900-122), herein referred to as th e “Boiler Survey,” a nd the data reported in the 2009 Test Plan
for Boilers and Process Heaters 2 

### (ICR No. 2286.03, OMB Control No. 2060-0616, EPA Form No. 5900-122), herein referred to as the “Phase II Te st Plan.” A data dict ionary and description
of all the fields contained in the database of reported industry data are summarized in other
memoranda. 3 

### The standardization of reported emissi on data and the methodology used to assign baseline emission factors to each boiler and pr ocess heater in the un it inventory are also
described in other memoranda. 4, 5

### This memorandum is organized as follows:
1.0 Introduction
2.0 Inputs for Cost Algorithms
3.0 Cost Algorithms for Add-on Control Devices
4.0 Cost Algorithms and Inputs for Work Practices, Testing, and Monitoring
5.0 References List of Appendices: Appendix A: Example Calculation of Exha ust Flow Rate, Percent Moisture, and
Percent O 2 

### . Appendices B to I: Detailed Control Cost Algorithms Appendix J: Detailed Testing a nd Monitoring Cost Estimates

# 2.0 Inputs for Cost Algorithms

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. The boiler survey data include information on control devices currently installe d on each combustion unit. Based on a review of
controls installed on the boilers a nd process heaters, the controls e xpected to be needed to meet the proposed Maximum Achievable Control Technology MACT floor emission limits and analyzed for the impacts analysis include the fabric filter, electrostatic precipitator (ESP), packed bed scrubber, activated carbon inje ction, carbon bed adsorbers, replacement burners (assumed to be low-nitrogen oxide [NO x 

### ] burners), linkageless boiler management system, and carbon monoxide (CO) oxidation catalyst. In addition, for units that reporte d to have a scrubber already installed, the impacts analysis also analyzed th e costs of increasing the caustic flowrate on an existing scrubber in order to improve scrubber efficiency.



## 2.1 Components of Control Cost Algorithms

When add-on technologies are us ed, consideration must be gi ven to added expenses such as ductwork and associated equipment. The discu ssion of the algorithms used to calculate capital and annual costs of these devices and the inputs to the algorithms are pres ented in this section. Components of capital costs incorpor ated into the algorithms include:

 Purchased equipment cost of the primary device and auxiliary equipment

 Instrumentation

 Sales tax and freight

 Installation costs. Installa tion costs include structural needs such as foundations and support, handling and erection, pi ping, insulation, painting, engineering, construction, field expenses, contractor fees, start-up, performance tests, and contingencies. Components of annual cost include:

 Raw materials (e.g., catalysts)

 Utilities (e.g., electricity, fuel, steam, air, water)

 Waste treatment and disposal

###  Labor (operating, supervisory, maintenance)

 Maintenance materials

 Replacement parts

 Overhead

 Property taxes

 Insurance

 Administration charges

 Capital recovery costs

For this analysis, all costs were estimated in 2008 dollars and annuali zed using an interest rate of 7 percent over th e life of the equipment. Costs origin ally provided in years other than 2008 were escalated to 2008 dollars using the Chemical Engineering Plant Cost index. Table 1 gives the costs for components comm on to the costing algorithms for multiple control devices, along with the source of the information.

Table 1: Costs of Common Components Used in Cost Estimate Algorithms Cost Component Cost (2008$) Source Weighted Labor Rate 51.26 U.S. Dept. of Labor—Bureau of Labor Statistics Electricity ($/kWh) 0.070 Energy Information Administration Water ($/gal) .0006 Electric Power Research Institute Waste Water Disposal ($/gal) .0054 Air Compliance Advisor User Guide— Version 7.5 Cost Factor for Caustic ($/ton) 600 Purchasing.com
Activated Carbon ($/lb) 1.38 The Innovation Group. Chemical Profiles: Carbon, Activated. 2002 and Norit vendor data. Dust Disposal ($/ton) 42.14 NSWMA’s 2005 Tip Fee Survey Compressed Air ($/1000 ft 3 

### ) 0.31 P2Pays.Org Energy Tips Catalyst Cost ($/ft 3 

### ) 959.25 OAQPS Control Cost Manual—Chapter 2

The labor rate was based on the May 2008 hour ly mean wage reported for occupational code for Stationary Engineers and Boiler Op erators (SOC code 518021) across the following

### four industries: Electric Po wer Generation, Transmission and Distribution (221100); Pulp, Paper and Paperboard Mills (322100); Chemical Manuf acturing (325000); and Colleges, Universities and Professional Schools (611300). All of these industries have severa l facilities expected to be subject to the proposed standard. The average ra w wage for these four industries was $24.41, and
to account for benefits and overh ead, a factor of 110 pe rcent of the raw wa ge was applied to estimate a loaded hourly wage. The cost for caustic has ranged widely over th e last several years due to rapid swings in the national economy. Caustic costs have range d from $300 to $800 per ton. A mid-range value of $600 per ton was used for this impacts analysis. The cost algorithms for the control devices were obtained primarily from previous EPA studies and regulatory devel opment projects, including the OAQPS Control Cost Manual (OCCM) 7 

### ; the 2009 Hospital Medical Waste Incinerato r New Source Performance Standards and Emission Guidelines (HMWI) 8 

### ; and the algorithms used to es timate the cost impacts under the vacated NESHAP for Industrial, Commercial, a nd Institutional Boilers and Process Heaters 9 

### . The OCCM contains the detailed cost procedures and algorithms for each control device. The appendices to this memorandum include cost algo rithms reduced/simplified to basic equations
from the EPA studies. Installing air pollution control devices on exis ting boilers requires additional costs to retrofit the equipment. These cost s are not included in the cost estimates of the OCCM or other sources. For this analysis, a factor of 1.4 was app lied to the costs of inst alling a fabric filter, packed-bed scrubber, electrostati c precipitator and a CO oxidation catalyst as well as any duct
work associated with the inst allation of these control device s. A factor of 1.3 in the EPA CueCost model represents a retrof it of medium difficulty. A factor of 1.2 was applied to the costs of installing activated ca rbon injection since this retrofit does not typi cally require a lot of additional space. A factor of 1.6 was applied to the costs of installing carbon adsorption technology. Because this technology is expected to be used predominantly at refineries, this higher factor, which represents a “difficult retr ofit” in the EPA CueCost model, was used to account for the space constraints th at often exist at refineries. 10


## 2.2 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 devi ce; target MACT floor emission rate or concentration; unit design capacity; and hours of operation. These inputs we re either reported by industry in the 2008 Boiler Survey or 2009 Phase II testing, or they were calculated from the reported data.


## 2.2.1 Reported Data Inputs

Unit design capacity was reported in the Bo iler Survey and standardized to million British Thermal Units per hours (mmBtu/hr). Discussions of how this parameter was
standardized are contained in other memoranda. 4 

### The Boiler Survey collected data on small gasfired units less than 10 mmBtu/hr, in aggregate, and the cost analysis assumed a design capacity
size of 5 mmBtu/hr hour to estimate the co sts of controlling these small boilers. Although hours of operation were reported for most of the units in the Boiler Survey, the cost analysis assumes 8,400 hours per year of ope ration for add-on controls with large capital expenditures, such as packed scrubbers, fabric filters, carbon bed adsorbers, CO oxidation catalysts, and electrostatic pr ecipitators. This annual hour estimate was used to avoid underestimating the variable operating costs. Th e operating hours reported in the survey were
used for the activated carbon injection, low-NO x 

### burners (LNB), and increased scrubber caustic, as these technologies lack large capital expenditure s and their cost estimates are more sensitive to the hours of operation of the combustion device . If hours of operation were not reported in the survey, 8,400 hours was used as the default, as th is represents full-time operation accounting for a two-week downtime pe riod for maintenance.


## 2.2.2 Calculated Data Inputs

Baseline Emissions and MACT Floor Emissions Some control cost algorithms require a pollutant removal ef ficiency as an input to estimate variable operating costs. For example, scrubbers designed to remove 20 percent of hydrogen chloride (HCl) will operate at lower pump ing rates and use less caustic than scrubbers designed to remove 85 percent of HCl emissi ons. The methodology used to assign baseline
emission factors and estimate the MACT floor em issions for each subcategory is discussed in separate memoranda 5, 6 

### . To assign the appropriate inlet and outlet emission rates to each boiler in the cost analysis, a VLOOKUP table was created in Excel to map the appropriate emission value to each boiler based on the boiler fuel type, co ntrol devices installed, and combustor design.

### Excess Air and Exhaust Temperature Information concerning excess air (in percen t) and exhaust temperature (in degrees Fahrenheit [°F]) was reviewed in an EP A publication on fossil fu el industrial boilers 11 

### and in data reported in the Internal Combustion C oordinated Rulemaking ICCR for non-fossil fuel
industrial boilers. 12, 23 

### Based on the review of these information sources, gas and distillate oil model units were assigned a typical excess air va lue of 15 percent and an exhaust temperature of 350°F. Residual oil model units were assigned a typical excess air value of 15 percent and an exhaust temperature of 400°F. Coal model units less than 400 MMBtu/hr we re assigned a typical excess air value of 50 percent a nd an exhaust temperature of 400° F. Coal model units greater than 400 MMBtu/hr were assigned a typical ex cess air value of 30 percent and an exhaust temperature of 400°F. Model units with non-fossil ma terial combinations we re assigned a typical excess air value of 50 percent and an exhaust temperature of 400°F.

Exhaust Flowrate, Moisture and Percent Oxygen Information on exhaust gas flowrate, moisture content, and percent oxygen for boilers and process heaters was reported in the Boiler Survey on a limited basis, or in most cases, was not available. Therefore, these parameters were calculated from the combustion kinetics of burning the primary fuels. For this calc ulation, the hydrogen, carbon, nitrogen, oxygen, and water composition of the primary fuel is necessary. The primary fuel of each boiler and process heater was identified according to the 10 percent fuel category listed in the Boiler Survey database. Th e methodology used to assign each combustion unit to a fuel category is discussed in another memorandum. 5 

### Next; each fuel category was assigned a fuel com position, as indicated in Table 2.

Table 2: Boiler and Process Heater Fuel Cate gories in Database and their Corresponding Fuel Composition Equations
Fuel Category from Boiler and Process Heater Inventory Fuel Composition Assumption for Combustion Kinetics Calculations Coal Sub-bituminous Coal Sub-bituminous over 400 MMBtu/hr Light Liquid Distillate Liquids Heavy Liquid Residual Liquids Dry Biomass Biomass (dry) Wet Biomass, Bagasse Biomass (wet) Gas 1 (NG only), Gas 1 (Oth er), Gas 2 Natural Gas

### 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. 13 

### These average percentages and the elements’ molecular weights were used to calculate the theoretical amount of oxygen (in moles per hundred pounds of fuel [m ole/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 pe rcentage and exhaust temperatur e (discussed in Section 3.3) for gas model units were used to calculate the exhaus t flowrate (actual cubic feet per minute [acfm]), exhaust moisture content (%), and exhaust oxygen content (%, dry basis) for gas model units. An example calculation is provided in Appendix A. 

# 3.0 Cost Algorithms for Add-on Control Devices

3.1 Fabric Filter Fabric filters offer emission control for me rcury (Hg), particulate matter (PM), and nonHg metallic HAP. The algorithms used to estimate cap ital and annual costs of fabric filters were
based on those used in the October 2008 memo entitled Compliance Costs and Economic Inputs for Existing Hospital/Medical/Infectious Waste Incinerators 14 

### (see Docket EPA–HQ–OAR– 2006–0534). The cost algorithms for estimating a nnual and capital costs are provided in Appendix B-1. The algorithms estimate the costs for a pulse-jet type fabric filter using felt bags. When fabric filters are applied to certain boilers designed to fire biomass fuels, a flame-retardant spray may be required to reduce fire hazards. The cost for the flame retardant has not been included in this cost analysis. Capital costs are based on the gross cloth area of the fabric filter, which is a function of the gas inlet flowrate. Annual costs incl ude dust disposal, electricity, maintenance, labor, bag replacement, maintenance labor, compressed air, capital recovery costs, overhead, administrative costs, pr operty taxes, and insurance.


## 3.2 Electrostatic Precipitator The Electrostatic Precipitator, or ESP, is commonly used to control PM emissions. The algorithms used to estimate cap ital and annual costs of ESPs came from Chapter 6 of the
OCCM 7 

### . The ESP costs are based on a cold-side, dr y-type ESP. Few, if any, hot-side ESPs are being specified for purchase. Capital costs are ba sed on the total collecti on plate area, which is calculated from the gas inlet flowrate and the re quired removal efficiency. The cost algorithms

### for estimating capital and annual costs of ESPs reduced to basic equations are provided in Appendix C-1. Annual costs include dust disposal, electricity, ma intenance materials, operating labor, maintenance labor, capital recovery costs, overhead, administrative, property taxes, and insurance. Appendix C-2 presents the values for the inputs used in this analysis.



## 3.3 Packed Bed Scrubber Packed bed scrubbers are generally used to lower emissions of HCl, hydrogen fluoride (HF), and sulfur dioxide (SO 2 

### ), although they also offer some Hg and PM control. The algorithms used to estimat e capital and annual costs of packed bed scrubbers were obtained from Chapter 8 of the OCCM 7 

### . The capital costs comprise the scru bber tower, packing, and pumps. Capital costs are based primarily on gas flowrate and required HC l removal efficiency to reduce the baseline HCl emissions to the targeted MACT floor emission limit. The cost algorithms for estimating capital and annual costs of packed scrubber equipment re duced to their basic equations for each are provided in Appendix D- 1. Annual costs include caustic, wastewater disposal, water, electricity, mainte nance, labor, capital recovery costs, overhead, administrative, property taxes, and insurance. Appendix D-2 pres ents the values for the inputs used in this analysis.



## 3.4 Increased Caustic Rate Emissions of acid gases such as HCl can be re duced further by increa sing the feed rate of lime or sodium bicarbonate (NaHCO 3 

### ) caustic prior to the fabric filter. The cost to increase lime flow were estimated using the equations from the July 2009 analysis for the HMWI rulemaking. In the HMWI analysis, the costs for makeup lime and dust disposal were estimated for a dry sorbent injection system followed by a fabric filter (DIFF). These costs range from approximately $200/yr to $20,900/yr. 15 

### Model costs to increase NaHCO 3 

### flow were estimated using similar equations, with a slight difference based on the stoichiometry and molecular weight
for NaHCO 3 

### . These costs range from approximately $800/yr to $81,600/yr. 15 

### . To estimate the increase in the caustic rate, the baseline HCl c oncentration was compared to the target MACT floor emission rate. Appendix E-1 presents the va lues for the inputs and the equations used to estimate the annual costs used in this analysis. There are no capital costs associated with this control option, as this incrementa l control is used in the cost analysis only when units with existing scrubbers or injection tec hnologies need to increase the efficiency of those systems to
meet the MACT floor emission limit.

## 3.5 Activated Carbon Injection Activated carbon injection (AC I) offers emission control for Hg and can be used in addition to a fabric filter (ACI/FF) to increase Hg collection efficienc y. ACI/FF is installed on two coal-fired boilers (OHRitt manSalt). In addition, injecti on of activated carbon has been
demonstrated to remove dioxin/furan emissions from combustion equipment. Cost estimates for ACI were derived from the 2009 analysis for the HMWI rulemaking 15 

### , which was based on a 90 percent reduction in Hg emissions and 98 percen t reduction in dioxin/furan. Because some of the percent reductions required fo r boilers and process heaters to meet the proposed Hg or
dioxin/furan MACT floor emission limits differ from 90 percent, a cost adjustment factor was created to scale these costs up or down. The cost adjustment factor represented the ratio of the pollutant removal efficiency required to meet the MACT floor emission limit over the 90 percent. For example, if a boiler required an Hg removal efficiency of 95 percent, the cost adjustment factor would be 0.95/0.9, or 1.05. The cost estimates used in the HMWI rulemaking would be multiplied by 1.05 for this particular boile r to account for an increase in pollutant removal efficiencies. Appendix F-1 shows the in puts to the algorithm and the equations to estimate the capital and annual costs of ACI.



## 3.6 Low-NO x



## Burner/Replacement Burner The quality and efficiency of combustion ca n be improved by replacing old burners with new replacement burners. This cost analysis assumes that a facility would replace a burner with a
new LNB. Modern LNBs can reduce emissions of NO x 

### , and CO. Not all combustor designs
utilize a burner that can be re placed with a LNB. For example, stoker boilers and Dutch ovens use a grate to support the fuel instead of havi ng a replaceable burner. Therefore, a replacement LNB was only considered to be a feasible contro l option for pulverized co al boilers and oil and gas boilers and process heaters. The equations us ed to estimate the costs of LNBs comes from vendor quotes provided in a 2005 memo titled, “Ana lysis of Combustion Controls for Reducing
NO x 

### Emissions from Coal-Fired EGUs in the WRAP Region.” 16 

### According to this memo, capital costs for retrofitting boilers with LNBs ranged from $6 to $24 per kW capacity of the boiler, in 2004$. Because these costs were based on utility -scale boilers, an upper end of the range—$20 per kW capacity of the boiler—was used in this analysis and scaled to 2008$. The reported boiler design capacity was converted into a kW capacity to estimate the total capital investment cost. Fixed and variable annual costs to operate th e burner are minimal. Annual operations and
maintenance costs from the burner retrofit are a balance of the increased costs from additional

### auxiliary fan power consumption, increased diffi culty of maintaining steam temperatures over the load range at reduced excess air, and hi gher maintenance demands, combined with cost savings as a result of increased boiler efficien cy. The capital recovery factor for a LNB was based on a 15-year equipment life. The inputs and equations to es timate the capital and annual costs of a LNB are shown in Appendix G-1.


## 3.7 Linkageless Boiler Management System The linkageless boiler management system (L BMS) improves the efficiency of a boiler and offers control of CO and other organic HAP using microprocessor technology to monitor data for several individually controlled channels such as fuel, air, flue-gas recirculation, and atomizing air. By monitoring and adjusting thes e parameters, an LBMS can be programmed to adjust the fuel-to-air ratios on the burner to maximize combustion efficiency. In addition, an LBMS employs separate individual , programmable fuel curves for each fuel type, eliminating the need to readjust the ratios when switching fuels. Further, when firing rate s change, the individual stepper motors for each fuel and air function adju st to allow a burner to run minimal excess-air levels throughout the firing range. A 2008 quote from the U.S. Department of En ergy provided the estimated cost of an
LBMS. 17 

### The quote included a note that LBMS costs ar e relatively fixed, regardless of the size of the boiler. A capital investment of $19,127 in 2008 dollars was used for the LBMS cost
estimate in all cases where the in stallation of an LBMS was an a ppropriate control option for CO emissions. An annualized cost of $2,100 per boiler was estimated based on the capital recovery over a 15-year period at an interest rate of 7 percent. Literature in dicates that the efficiency gains of an LBMS may offset any addi tional costs associated with installing the system, depending on the burner’s age, quality, and design, but these co st savings were considered under a separate section of the cost analysis. 18


## 3.8 CO Oxidation Catalyst The algorithms used to estimate capital and a nnual costs of a CO oxi dation catalyst were based on the costs for catalytic oxidizers in Chapter 2 of the OCCM 7 

### . The algorithms in the OCCM were specific to a broad size range of incineration units. Although the exhaust flowrates
for some of the boilers for which control cost es timates were being made fell outside that size range, the equations were used in all cases because they offered the best available estimate. The algorithms used to estimate the capital and annual costs of a catalytic ox idizer are included in

### Appendix H-1. The capital cost is based primarily on exhaust flow rate. Annual costs include catalyst, electricity, maintenance, labor, capit al recovery costs, overhead, administrative, property taxes, and insurance.



## 3.9 Carbon Adsorber Beds Activated carbon bed adsorption was reported to be used at three faci lities on 11 different boilers and process heater s in the Boiler Survey:

 

### CTElectric Boat—nine boilers firi ng natural gas and fuel oil

 

### NYAESGreenidgeDresden—one coal-fired boiler

 

### TXMOTIVAEnterprisesPortA rthur—one refinery gas- fired process heater Carbon adsorption is used to filter volatile organic contaminants out of gas streams with low to medium pollutant concentrations. Chapter 3 of the OCCM 7 

### discusses the design and costs associated with fixed bed and canister adsorption systems. Activated carbon adsorption has been used to treat digester gases upstream of combusti on for siloxanes and other gas contaminants that may foul combustion equipment. Other combus tion equipment, such as the 2009 HWMI rule, identified carbon adsorption being used to contro l mercury at East Caro lina University. Some technical limitations to mercury adsorption exist when there are low concentrations of mercury in the flue gas. Carbon bed adsorbers are common ly used as mercury control on gas fields in Eastern Europe an Asia where mercury concentrations range between 193 and 3,000 μ g/Nm 3



### . As a beyond-the-floor option for Hg contro l, EPA estimated the costs to reduce Hg emissions from refinery gas units using carbon ad sorption. In estimating th e annual cost of the carbon for the carbon bed, the amount required was assu med to be equivalent to that used in the
ACI calculation in section 3.5 of this memo randum. The cost estimates are based on a centralized carbon adsorption system that would tr eat the refinery gas prior to it being combusted in boilers or process heaters co -located at the same facilit y. The costs do not reflect carbon regeneration; instead, the cost es timates include costs to purchase virgin carbon and dispose of spent carbon. The costs for disposal and car bon purchase are shown in Table 1 of this
memorandum. The direct annual costs and overhea d costs are based on estimates provided in a June 19, 2009 memo for the HMWI rule. 15 

### Indirect annual costs for property taxes, insurance, construction, contractor fees, a nd contingencies were developed using factors from Table 1.3 of Chapter 3 of the OCCM 6 

### . The capital costs for installing a fixed carbon bed adsorption system were estimated using a factor of $20 to $30 per kW of installed capacity, based on literature for an integrated plasma gasification combined cycle system. 19 

### The upper end of this range ($30 per

### kW) was used for this cost analysis. The inputs and equations used to estimate the capital and
annual costs of a carbon adsorber are included in Appendix I-1.


## 3.10 Duct Work and Auxiliary Equipment The algorithms used to estimate capital and a nnual costs of ductwork were obtained from Chapter 10 of the OCCM. 7 

### Capital costs include ductwork for any ESP, packed bed scrubber, or
fabric filter installed on the unit. The number of duct lines is based on the exhaust flowrate, and
it is estimated that 500 feet of duct work is required for every 154,042 of exhaust (in acfm) per
control device. The 500 feet of ductwork was based on engineer ing judgment and previous experience on the distance between emission point s and control devices in chemical facilities. Costs are based on ductwork diameter, which is a function of flue gas flowrate. Costs for
ductwork also include elbows to c onnect the duct joints and fans to move the exhaust through the ductwork. The cost algorithms for estimating capital and annual costs for ductwork and auxiliary equipment are included in the individual append ices for Fabric Filters, Packed Bed Scrubbers, and ESP. Annual costs include electricity, ma intenance and labor, cap ital recovery costs, overhead, administrative, prope rty taxes, and insurance. 

# 4.0 Cost Algorithms and Inputs for Work Practices, Testing, and Monitoring Some boilers were found to be emitting po llutant amounts very close to the allowable level. In these cases, add-on controls may not be necessary if less costly practices, such as regular tune-ups to ensure optimum equipmen t efficiency or occasional energy audits, are initiated. Further, under the proposed rule, ther e is a work practice standard in lieu of an
emission limit for small boilers less than 10 mmB tu/hr and natural gas and refinery gas-fired
boilers of all sizes.
To demonstrate initial and c ontinuous compliance with the proposed rule, testing, fuel analysis, and monitoring are required to vary ing degrees for certain affected sources. Consequently, tune-ups, energy audits, and testin g and monitoring costs were incorporated into the cost estimates, which are discussed in this section.


## 4.1 Tune-ups The estimated cost to conduct an annual tune-up on an industrial, commercial, or
institutional boiler is based on the cost estimate provided by Dr. H.M. Eckerlin and E.W. Soderberg of the Industrial Extension Service USI Boiler Efficiency Program. 20 

### Their report

### summarizes the findings and reco mmendations of an evaluation of boilers in state-owned facilities. Their report indicates that the initial set-up fo r a boiler tune-up ranges from $3,000 to $7,000 per boiler, and thereafter, an annual tune -up costs $1,000 per boiler per year. For this analysis, an average of $5,000 per boiler initial se t-up cost was annualized over five years for an annualized cost of $1,580 per boiler. The USI st udy and other literature suggest that annual boiler tune-ups can improve combustion efficiency between 1 and 5 percent, and often the fuel savings cover the cost of conducting a tune-up. The co st estimate for the tune-up in this analysis includes inspection of the burner, cleaning and re pairs to the burner as necessary, inspection and adjustment of the flame patter n, inspection and calibration of th e air-to-fuel ratio controls, minimizing total emissions of CO consistent with the manufacturer’s specifications, and
measurement of CO emissions be fore and after the tune-up.


## 4.2 Energy Audits An energy audit provides a detailed assessmen t of the pattern of energy use within a facility, as well as a comprehens ive energy-saving and costing analys is. A detailed description of relevant energy-saving technologies may also be included to help identify opportunities to reduce energy consumption. The cost of an energy audit de pends on the area of a facility and the types of equipment installed there. Energy audits are conducted on a fa cility level rather than per
combustion unit. For industrial faciliti es identified by NAICS codes 211, 212, 311, 312, 313, 314, 316, 321, a cost of $75,000 was estimated for an energy audit. This estimate is based on costs presented to the 2009 Boiler Small Busi ness Regulatory Flexibility Act panel by an affected small entity, Port Townsend Paper Compa ny. The cost was annualized over five years at 7 percent interest to estimate the annual cost impacts of the proposed rule. Commercial and institutional facilities are expected to pay substantially less than industrial facilities for energy audits. An estimate of $2,000 to $5,000 per energy audit was obtained from two utilities. This
estimate was used to determine the cost im pact of energy audits for all NAICS codes representing commercial and in stitutional facilities. An aver age of $3,500 per facility was annualized over five years at 7 percent to obtain an annualized cost estimat e for energy audits at
commercial facilities.

## 4.3 Testing Capital and annual costs for testing include stack tests for PM, Hg, HCl, CO, and dioxin/furan. The proposed rule provides a complian ce alternative to conduct a fuel analysis in lieu of a stack test for HCl and Hg, if the fuel contains less mercury or chlorine than the MACT floor emission limit for the appropriate subcategor y. The proposed rule also provides compliance flexibility to sources that consecutively test at 90 percent or less of the emission limits. The flexibility allows these sources to test at thre e-year intervals instead of annually. Because the number of sources expected to qualify for the three-year interval is unknown, and all sources must test annually for the first th ree years of compliance, this cost analysis is based on an annual testing frequency. The cost analysis also assumes that every solid fuel un it will conduct testing for all pollutants annually, and liquid fuel un its will conduct stack testing for PM, CO, and dioxin/furan and fuel analysis for Hg and chlori ne. Testing cost estimates were based on those used in the Phase II Test Plan and were adju sted downward slightly to account for a lower number of pollutants being tested. The testing co sts assume that all pollutants will be tested simultaneously, or over the course of a single trav el occurrence for a testing contractor. For the simpler methods (e.g., PM), the testing costs ra nge from $5,000 to $7,000. For the pollutants that involve more lab analysis (e.g., Hg), the testing costs range from $10,000 to $15,000. Although the cost ranges can be applied, as is done 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 a nd CO data, the test costs would not be twice the $5,000 to $7,000 price, because some of the costs are associated with getting the testing
contractor to the site and sett ing up the equipment (these are on e-time costs, such as port installation and scaffolding costs described belo w and would not be duplicated regardless of the number of pollutants tested). Ther efore, if a facility had more than one of the simpler tests to run (e.g., PM and CO or PM and HCl), then the s ite-specific costs would start in the $5,000 to $7,000 range with a few thousand dollars added for th e second pollutant. If a facility needed PM data and dioxin/furan data, then the site-specifi c costs would be the sum of the tests in the $5,000 to $7,000 and $10,000 to $15,000 ranges. See the 2009 Phas e II Test Plan for a discussion of the testing cost estimates. 2 

### A summary of the testing and monitori ng costs used in this cost analysis is presented in Appendix J-1. 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.


## 4.4 Monitoring Monitoring costs are included for opacity mon itoring (for units wit hout scrubbers) or PM continuous emissions monitoring systems (CEMS) (for units greater th an 250 mmBtu/hr), bag leak detection (for units with fabric filters), scrubber para metric monitoring (for units with scrubbers), and CO monitors (f or units greater than 100 mmBtu/ hr). Cost estimates for CO monitors were developed usi ng the 2007 EPA CEMS cost model. 21 

### Cost estimates for bag leak detection, PM CEMS, and wet scrubber parametric monitoring were based on estimates used in the 2009 HMWI rulemaking. 13 

### Cost estimates for opacity monitoring were based on a 1997 memorandum prepared for the HMWI rule making, and escalated to 2008 dollars. 22 

### Monitoring costs include the costs for pl anning, selecting, and installing monitoring equipment and support facilities; conducting an annual re lative accuracy test audit an d writing the report; performing cylinder gas audits; de veloping a QA/QC plan; monitoring op erations and maintenance; and performing capital recovery. CO monitors were annualized over a 10-year lifetime using guidance from the 2007 EPA CEMS cost model. Bag leak detection, PM CEMS, and wet scrubber parametric monitoring we re all annualized over a 20-year lifetime. A summary of the monitoring costs is presente d in Appendices J-2 and J-3.


# 5.0 References

1. U.S. Environmental Protection Agency. 2008 Qu estionnaire for Boilers, Process Heaters, Incinerators and Other Combustion Units (ICR No. 2286.01, OMB Control No. 2060- 0616, EPA Form No. 5900-122)
2. U.S. Environmental Protection Agency. 2009 Te st Plan for Boilers and Process Heaters ICR No. 2286.03, OMB Control No. 2060-0616, EPA Form No. 5900-122

### 3. McClutchey. S, and G. Gibson, ERG. Data Dictionary for Boiler, Process Heater, and Other Combustion Unit Survey Databases. April 2010.
4. Gibson, G., ERG. Standardization of Reporte d Data from the Questionnaire for Boilers, Process Heaters, Incinerators a nd Other Combustion Units, April 2010.
5. Gibson, G. and A. Singleton, ERG. Devel opment of Baseline Emission Factors for Boilers and Process Heaters at Commercial, In dustrial and Institutio nal Facilities. April 2010.
6. Singleton, A., ERG. MACT Floor Analysis fo r the Industrial, Comm ercial, Institutional Boilers and Process Heaters National Emissi on Standards for Hazardous Air Pollutants – Major Source, April 2010.
7. U.S. Environmental Protection Agency, EP A Air Pollution Control Cost manual, Sixth Edition. EPA/452/B-02-001, January 2002.
8. Holloway, Thomas. RTI International. E-mail with attachment: HMWI Fabric Filter Control Cost Spreadsheet, July 2009.
9. Oommen, Roy. Methodology for Estimati ng Control Costs for the Industrial, Commercial, and Institutional Boilers and Pr ocess Heaters Nationa l Emission Standards for Hazardous Air Pollutants, October 2002.
10. U.S. Environmental Protection Agency. Coal Utility Environm ental Cost Version 5.0

. EPA/600/R-09/131. Office of Research and De velopment Air Pollution Prevention and Control Division. September 2009. www.epa.gov/ttncatc1/products.html

. 11. 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.
12. 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.

13. Babcock and Wilcox. Steam its generation and use 40 th 

### edition . 1992.
14. Holloway, Thomas. RTI International, Me mo to Mary Johnson, U.S. Environmental Protection Agency, Compliance Costs and Ec onomic Inputs for Existing HMWI. October 24, 2008.
15. Holloway, Thomas. RTI International. Revi sed Baseline Operating Costs for Existing HMWI Memo. June 19, 2009.

16. ERG. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-Fired EGUs in the WRAP Region. September 5, 2005.

### 17. Phone conversation between Aman da Singleton, ERG and Gil McCoy

, 

### U.S. Department of Energy, Energy Efficiency and Rene wable Energy. October 27, 2008 for quote on a Linkageless Boiler Management System.
18. Cairnie, D. 2008. Linkageless Burner C ontrol. Heating/Piping/Air Conditioning Engineering, on-line edition: http://hpac.com/heating/ linkageless_burner_control/
19. Global Environmental Solutions Inc., The U tilization of Integrated Plasma Gasification Combined Cycle System. www.gesi-solutions.com/resources/GESI-- THE+UTILIZATION+OF+INTEGRATED+PLASMA+GASIFICATION+COMBINED +CYCLE+SYSTEM.pdf
20. Eckerlin, Dr. H.M. and E.W. Soderberg , Industrial Extensio n Service USI boiler Efficiency Program. February 25, 2004.15, www.energync.net/programs/docs/usi/om/boilers/ssr.pdf

. 21. Research Triangle Institute, 2007, “U.S. EPA Continuous Emission Monitoring System (CEMS) Cost Model.” www.epa.gov/ttn/emc/cem.html

. 22. 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 (MWI’s ) - Methodology and Assumptions. March 17, 1997
23. 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.Appendix A: Example Calculation of Exhaust Flow Rate, Percent Moisture and Percent OxygenC 70.6 Excess Air (%) 15H222.7Temperature (std.) 350N25.7Heating Value (Btu/lb) 22027S --Ash --O21Calculate Theoretical Oxygen Requirement in Combustion Air:Element % by weightMolecular weightMole/100 lb offuel=%/MWResultingProductRequiredmoles ofOx/ 100 lbfuelC 70.612 5.9 CO2 5.9H222.72 11.4 H2O 5.7N25.728 0.2O2132 0.03 -0.03Total 10011.622027 Btu/lb fuel x 100/100 lb fuel x MMBtu/1000000 Btu = 2.2MMBtu/ 100 lb fuel15 = 100 x (O2 - 11.6)/11.6O2 = 13.3 molesO2/100 lb fuelMaterial Analysis Average Values for Natural Gas from SteamFuel Values and Combustion UnitAssumptionsCalculate Heat Content of Natural Gas per 100 lb of fuelSolve for Required Moles of O2/100 lb fuel at 15% excess airAppendix A: Example Calculation of Exhaust Flow Rate, Percent Moisture and Percent OxygenRatio of N2 to O2 in the Atmosphere - 3.77 [moles N2 to moles O2]N2 = 13.3 moles O2/100 lb fuel x 3.77 moles N2/1.0 mole O2N2 = 50.1 moles/100 lb fuelCalculate Exhaust TotalsElement Basis Exhaust (moles/100 lb fuel)CO2 5.9 C 5.9H20 11.4 H2 11.4O2 13.3 - 11.6 1.7N2 0.2+50.1 50.3Total69.3Calculate Exhaust Volume acf/lb fuelPressure x Volume = Moles x Constant x TemperatureExhaust Volume = Moles x constant x Temperature / PressureConstant = 10.73 psia-ft3/lb-mole-deg RTemperature Conversion deg R = deg F + 460Calculate Exhaust Volume acf/MMBtuExhaust Volume = Volume in acf/lb fuel x Heat Content per 100 lb fuelExhuast Volume = 409 acf / lb fuel x 100 lb fuel / 2.2 MM Btu = 18590 acf/MMBtu at 15% excess airCalculate Exhaust Flow Rate from Exhaust Volume using Example Capacity of 5 MMBtu/hrExhaust Flow rate = Exhaust Volume in acf/MMBtu x Capacity in MMBtu/hr x 1 hr/60 minutesExhaust Flow Rate = 18590 acf/MMBtu x 5 MMBtu/hr x 1/60 = 1549 acfmCalculate Percent Moisture in ExhaustExhaust Moisture (%) = (11.4 moles H2O/100 lb fuel) / 69.3 total moles/100 lb fuel x 100% = 16.5 %Calculate Percent Oxygen in ExhaustExhaust Moisture (%) = (1.7 moles O2/100 lb fuel) / 69.3 total moles/100 lb fuel x 100% = 2.5 %Sources:Alvis, Jeanette, C. Burlew and R. Oommen, ERG. Development of Model Units for the Industrial/Commercial/Institutional Boilersand Process Heaters National EmisionStandards for Hazardous Air Pollutants. October 2002.Exhuast Volume = 69.3 lb-moles / 100 lb fuel x 10.73 psia-ft3/lb-mole-deg R x (1/14.7psia) x (350 deg F + 460) = 409 acf / lb fuelCalculate Moles of N2/100 lb fuel in Combustion AirAppendix B: Fabric Filter Costs Parameters/Costs Equation

A. Parameters 1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 mmBtu/hr) 2. Annual operating hours, hr/yr (H) used Boiler Survey data as input 3. Exhaust gas flow rate, dscfm (Q) calculated per boiler, see Section 2.0 of the memo. 4. PM concentration, gr/dscf (PM) calculated baseline emission factor for PM (lb/mmBtu)*C*(7000/60)/Q 5. Water vapor in gas (% by weight) (%M) estimated per boiler, see Section 2.0 of the memo. a. lb/min = Q / ( 385 ft 3 /lb-mol ) x ( 29 lb/lb-mol ) x %M b. scfm = ( lb/min ) / ( 18 lb/lb-mol ) x ( 385 ft 3 / lb-mol )
a. Dry gas from incinerator, Btu/lb air = [7.010 x (300°F - 77°F) - 7.554 x (1800°F - 77°F)] / (29 lb/lb-mol)
b. Water vapor from incinerator, Btu/lb water vapor = [8.154 x (300°F - 77°F) - 9.215 x (1800°F - 77°F)] / (18 lb/lb-mol)
c. Total gas stream, Btu/yr = [(Btu/lb air) x Q / (385 ft3/lb-mol) x (29 lb/lb-mol) x (60 min/hr) x H] + [(Btu/lb water vapor) x Q x (0.00753 lb water vapor/ft3) x (60 min/hr) x H] d. Cooling water i. Heat of vaporization at 77 °F, Btu/lb ii. Sensible heat for vapor, Btu/lb iii. Total, Btu/lb water 7. Cooling water evaporated, lb/yr a. lb/yr = [enthalpy change (total gas stream, Btu/yr)] / [enthalpy change (cooling water, Btu/lb)] b. scfm = [cooling water evaporated (lb/yr)] / (18 lb/lb-mol) x (385 ft3/lb-mol) / (H * 60 min/hr) 8. Actual gas flow into fabric filter, acfm (AQ) = [Q + (water vapor in gas from incinerator, scfm) + (water vapor added in quench, i.e., cooling water evaporated, scfm)] x [(300 °F + 460°F)/528°R] 9. Operating labor rate, $/hr (LR) 51.26 10. Electricity cost, $/kWh (EC) 0.069981 11. Water cost, $/gal (WC) 0.000559 12. Com p ressed air cost, $/1,000 ft 3 ( CAC ) 0.31 13. Dust disposal cost, $/ton (DDC) 42.14 14. Capital recovery factors = [i x (1 + i) a ] / [(1 + i) a - 1], where i = interest rate, a = equipment life
a. Bag CRF, 2-yr life, 7% interest b. Cage CRF, 4-yr life, 7% interest c. Equipment CRF, 20-yr life, 7% interest
d. Duct CRF, 20-yr life, 7% interest 15. Cost index a. 2008 525.4 b. 1989 357.5 16. Retrofit Factor 1.4 17. Gas transport velocity, ft/min (ut) assigned constant, 3000 18. Diameter of duct, ft (Dd) =1.128 x (Q/ut)^1/2 19. Number of Duct Lines, (ND) if Q < 154042 acfm =1 if Q > 154042 acfm = Q/154042 acfm 20. Length of ductwork (L) assigned constant, 500 21. # of elbows per length of duct (Ne/Ld) assigned constant, 0.02 22. Fan coefficient (af) assigned constant, 22.1 23. Fan Diameter, inches (Df) assigned constant, 36.5 24. Fan exponent (b) assigned constant, 1.55
B. Total Capital Investment 1. TCIduct, $ =(1.458 x ((0.39 x ((Dd/ND)^2) x 3.14159 x L)+(74.2 x L x Ne/Ld x EXP(0.8016 x (Dd/ND))) + (23 x EXP(0.6804 x (Dd/ND))) + (af x (Df^b)))) 2. TCI $ = (TCIduct + 47.0 x Q + 306,720) x (Retrofit Factor) x (525.4/357.5)

3. $/dscfm = $ / Q
C. Direct Annual Operating Costs, $/yr 1. Electricity = (0.746 kW/hp) x hp (0.0072 x Q + 3.20) x H x EC 2. Electricity - Ducts a. Friction loss factor for elbow (k) assigned constant, 0.19 b. Efficiency of fan (ef) assigned constant, 0.70 c. Pressure drop through duct, in.H2O (Pd) =0.136 x (1/Dd)^1.18 x (ut/1000)^1.8 + (L/100) x (L x Ne/Ld x k x (ut/4016)^2) f. Electricity for Fan use, kW (Efan) =((0.000117 x Q x H x Pd)/ef) g. Cost of Electricity, $/yr =EC x Efan 3. Evaporative cooler water = (0.1007 x Q + 23.1506) gal/min x (60 min/hr) x H x WC 4. Operating labor = (1 hr/shift) x (1 shift/8 hr) x H x LR 5. Supervisory labor = 0.15 x (operating labor) 6. Maintenance labor = (0.5 hr/shift) x (1 shift/8 hr) x H x (LR x 1.1) 7. Maintenance materials = 0.02 x TCI 8. Compressed air = AQ x ( 2 ft 3 air/1,000 ft 3 filtered ) x ( 60 min/hr ) x H x CAC 9. Dust disposal = (PM gr/dscf x Q x 60 min/hr x 1 lb/7,000 gr) x (1 ton/2,000 lb) x H x DDC 10. Bag replacement a. Bag cost = AQ x ($2.5/ft 2 ) x (525.4/317.4) x (1.08 taxes and freight ratio)/(3.5 ft/min G/C ratio ) b. Bag replacement labor cost = AQ x ( 0.15 hr/ba g) / ( 18 ft 2 ba g area ) / ( 3.5 ft/min G/C ratio ) x LR c. Bag replacement cost = Bag CRF x [(total bag cost) + (bag replacement labor cost)] 11. Cage replacement a. Number of bags = AQ/ ( 3.5 ft/min G/C ratio ) / ( 18 ft 2 ba g area ) b. Cage replacement labor cost = bag replacement labor cost c. Cage replacement cost = Cage CRF x [single-cage cost (4.941+ 0.163 x 18 ft 2 bag area) x (number of bags) x (525.4/317.4) + (cage replacement labor cost)]

D. Indirect Annual Costs, $/yr 6. Enthalpy change in quench (1800°F to 300°F)Appendix B: Fabric Filter Costs Parameters/Costs Equation 1. Overhead = 0.6 x (labor + maintenance materials) 2. Property taxes, insurance, and administration = 0.04 x TCI
3. Capital recovery = Equipment CRF x (TCI - bag replacement cost - cage replacement cost) 4. Duct TAC a.TACductwork =TCIduct x (0.04 + CRFduct) b. Duct_cap recov =TACductwork x 0.7 c. Duct_admin =TACductwork x 0.1498 d. Duct_prop tax =TACductwork x 0.0749 e. Duct_insurance =TACductwork x 0.0749 f. Total TACduct =Duct_cap recov + Duct_admin + Duct_prop tax + Duct_insurance

E. Total Annual Cost 1. $/yr = Direct Annual Costs + Indirect Annual Costs + Total TACduct 2. ($/yr) / dscfm = ($/yr) / Q

Sources:

3. Electricity cost: Energy Information Administration. Average Industrial Retail Price of Electricity: October 2009. 4. Water cost: Air Compliance Advisor, version 7.5. 5. Compressed air cost: P2Pays.org. Energy Tips – Compressed Air. Compressed Air Tip Sheet #1. August 2004. 6. Dust disposal cost: NSWMA’s 2005 Tip Fee Survey 1. Cost equations: Hospital/Medical/Infectious Waste Incinerators (HMIWI) [EPA-HQ-OAR-2006-0534] Model Plant Description and Cost Report (II-A-112); and Dry Injection Fabric Filter Cost Memorandum (IV-B-32). 2. Operating labor rate: Bureau of Labor Statistics, Occupational Employment Statistics, May 2008 National Industry-Specific Occupational Employment and Wage Estimates

### Appendix C: ESP Costs Parameters/Costs Equation

A. Parameters 1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 mmBtu/hr) 2. Annual operating hours, hr/yr (H) used Boiler Survey data as input 3. Exhaust gas flow rate, acfm (Q) calculated per boiler, see Section 2.0 of the memo. 4. PM concentration, gr/dscf (PM) calculated baseline emission factor for PM (lb/mmBtu)*C*(7000/60)/Q 5. Efficiency, % (E) =100*(1-(PM emission limit/PM)) 6. Temperature (T) assigned based on fuel type, see Section 2.2.2 of the memo 7. Inlet Moisutrue, % (IM) assigned constant, see Appendix C-2 8. Specific Collection Area ratio (SCA) assigned based on efficiency, see Appendix C-2 9. PM Migration velocity (Mv) assigned constant, see Appendix C-2 10. Total Collection Place area, ft2 (TCP) =(Q/1000) x ((-508*LN(1-(E/100)))/Mv) x SCA 11. Equipment Cost of ESP, $ (EC) if TCP<50,000 =614.55(TCP)^0.6276 if TCP>50,000 =57.87(TCP)^0.8431 12. Factor to convert from FRP to other material (m) assigned constant, see Appendix C-2

13. Cost index a. 2008 525.4 b. 1998 389.5 14. Capital recovery factors = [i x (1 + i) a ] / [(1 + i) a - 1], where i = interest rate, a = equipment life
Equipment CRF, 20-yr life, 7% interest Duct CRF, 20-yr life, 7% interest 15. Operating labor rate, $/hr (LR) SEE cost input summary 16. Electricity cost, $/kWh (EC) SEE cost input summary 17. Dust disposal cost, $/ton (DDC) SEE cost input summary 18. Retrofit Factor 1.4 19. Gas transport velocity, ft/min (ut) assigned constant, see Appendix C-2 20. Diameter of duct, ft (Dd) =1.128 x (Q/ut)^1/2 21. Number of Duct Lines, (ND) if Q < 154042 acfm =1 if Q > 154042 acfm = Q/154042 acfm 22. Length of ductwork (L) assigned constant, see Appendix C-2 23. # of elbows per length of duct (Ne/Ld) assigned constant, see Appendix C-2 24. Fan coefficient (af) assigned constant, see Appendix C-2 25. Fan Diameter, inches (Df) assigned constant, see Appendix C-2 26. Fan exponent (b) assigned constant, see Appendix C-2
B. Total Capital Investment (TCI) 1. TCIduct, $ =(1.458 x ((0.39 x ((Dd/ND)^2) x 3.14159 x L)+(74.2 x L x Ne/Ld x EXP(0.8016 x (Dd/ND))) + (23 x EXP(0.6804 x (Dd/ND))) + (af x (Df^b))))*(575.4/389.5)*Retrofit Factor 2. $ =3.8326 x m x EC x Retrofit Factor + TCIduct 3. $/acfm = $ / Q
C. Direct Annual Operating Costs, $/yr 1. Electricity a. Friction loss factor for elbow (k) assigned constant, see Appendix C-2 b. Efficiency of fan (ef) assigned constant, see Appendix C-2 c. Pressure drop through duct, in.H2O (Pd) =0.136 x (1/Dd)^1.18 x (ut/1000)^1.8 + (L/100) x (L x Ne/Ld x k x (ut/4016)^2) d. Pressure drop through ESP, in.H2O (Pesp) assigned constant, see Appendix C-2
e. Pressure drop of gas, in.H2O (Pg) =Pesp+Pd f. Electricity for Fan use, kW (Efan) =((0.000117 x Q x H x Pg)/ef) + 0.00194 x TCP x H g. Cost of Electricity, $/yr =EC x Efan 2. Dust disposal =0.00000429 x H x DDC x PM x Q x E 3. Labor a. If TCP < 10,000 then Of =0 b. If TCP > or = 10,000 then Of=1 c. Cost of Labor, $/yr (LC) = 0.1854 x H x LR x Of 4. Maintenance Cost, $/yr (MC) a. If TCP<50,0000 =4125 + 0.004464 x TCI b. If TCP> or = 50,000 =0.0825 x TCP + 0.00446 x TCI
D. Indirect Annual Costs, $/yr 1. Overhead = 0.6 x (LC + MC) 2. Property taxes = 0.01 x TCI 3. Capital recovery = Equipment CRF x (TCI) 4. Administrative cost =0.02 x TCI 5. Insurance =0.01 x TCI 6. Duct TAC a.TACductwork =TCIduct x (0.04 + CRFduct) b. Duct_cap recov =TACductwork x 0.7 c. Duct_admin =TACductwork x 0.1498 d. Duct_prop tax =TACductwork x 0.0749

### Appendix C: ESP Costs Parameters/Costs Equation e. Duct_insurance =TACductwork x 0.0749 f. Total TACduct =Duct_cap recov + Duct_admin + Duct_prop tax + Duct_insurance

E. Total Annual Cost 1. $/yr = Direct Annual Costs + Indirect Annual Costs + Total TACduct 2. ($/yr) / dscfm = ($/yr) / Q

Sources: 1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 6. EPA/452/B-02-001, Ja nuary 200 2 2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, October 2002.

## Appendix C: ESP Costs

Var COMMON DEFAULTS - ESP I I = interest rate 0.07 Ne_Ld Ne/LD = # of elbows per length of duct 0.02 L L = length of ductwork 500 ut ut = gas transport velocity, ft/min 3000

Var DEFAULTS- TOTAL ANNUAL COST -- ESP n n = life of equipment, yrs 20 Op_ESP Op_ESP = operating hours/year 8400 CFdd CFdd = cost factor for dust disposal, $/ton 42.14111 CFlab CFlab = cost factor for labor, $/hr 51.26

Ps = DEFAULTS - ELECTRICITY - ESP CFelec CFelec = cost factor for electricy, $/kw-hr 0.06998 Pesp Pesp = pressure drop through esp, in H2O 0.38 k k = friction loss factor for elbow 0.19 E f Ef = efficiency of fan 0.7

DEFAULTS - DUCTWORK - ESP af af = fan coefficient 22.1 b b = fan exponent 1.55 Df Df = fan diameter, inches 36.5 n_duct n_duct = life of equipment, yrs 20

DEFAULTS -TCI - ESP Fone Fone = special add-on factor 1 Ftwo Ftwo = no special add-on factor 0 m m = factor to convert from FRP to other mat. 1 Mv Mv = PM migration velocity, cm/s 16

Sources: ESP DEFAULTS

1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 6. EPA/452/B-02-001, January 2002.
2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, October 2002.

### Appendix D: Packed Bed Scrubber Parameters/Costs Equation

A. Parameters 1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 mmBtu/hr) 2. Annual operating hours, hr/yr (H) used Boiler Survey data as input 3. Exhaust gas flow rate, acfm (AQ) calculated per boiler, see Section 2.0 of the memo. 4. PM filterable baseline emission, lb/mmBtu (PMb) used Boiler Survey data as input
5. HCl Baseline, lb/mmbtu (HClb) used Boiler Survey data as input 6. Temperature (T) assigned based on fuel type, see Section 2.2.2 of the memo 7. Inlet Moisutrue, % (IM) calculated per fuel type, see Appendix D-2 8. HCl Floor, lb/mmBtu (HClf) assigned based on fuel 9. Efficiency (E) = 100 x (1 - (HClf/HClb)) 10. Inlet HCl Loading, lb/hr (In HCl) =HClb x C 11. Inlet PM loading, lb/hr (In PM) = PMb x C 12. Inlet HCl loading, mole fraction (In HClm) =InHCl x (T = 460) / (2958.12 x AQ) 13. Inlet PM loading, gr/acfm (InPMg) =InPM / AQ x 116.7 14. Packing Cost Factor, $/ft3 (Cp) constant, see Appendix D-2 15. Scrubber Diameter Component (SDC) a. ratio of solvent density to water density (mm) defined in Appendix D-2 b. packing factor (Fp) defined in Appendix D-2 c. viscosity of liquid, lb/ft-hr (ui) defined in Appendix D-2 d. flooding factor (f) defined in Appendix D-2 e. minimum wetting rate, ft2/hr (MWR) defined in Appendix D-2 f. packing constant, ft2/ft3 (ap) defined in Appendix D-2 g. SDC '=(-0.915 - SQRT(-1.144359 -(1.188 x (LOG((mm x Fp x ((ui / 2.42) ^ 0.2) x MWR^2 x ap^2) / (12960000 x f^2 x 32.2),10)))))/-0.594 16. Scrubber Diameter, ft (Ds) a. density of liquid, lb/ft3 (Dl) defined in Appendix D-2 b. density of gas, lb/ft3 (Dg) defined in Appendix D-2 c. Ds =(SQRT((240 x Dg x AQ x 10^SDC)/(MWR x Dl x ap x PI x SQRT((Dg/Dl))))) 17. Height of packing, ft (Hpack) a. packing constant (BBB) defined in Appendix D-2 b. packing constant (X) defined in Appendix D-2 c. HpackA = X x (240 x Dg x AQ) / (PI x Ds^2) d. packing constant (g) defined in Appendix D-2 e. HpackB = (MWR x D x ap)^g f. viscosity of gas, lb/ft-hr (ug) defined in Appendix D-2 h. diffusivity of gas, ft2/hr (Dfg) defined in Appendix D-2 i. HpackC = SQRT(ug/(Dg*Dfg) j. packing constant (BB) defined in Appendix D-2 k. HpackD =((MWR x Dl x ap)/ui)^BB l. liquid diffusivity, ft2/hr (Dfl) defined in Appendix D-2 m. HpackE = SQRT(ui/(Dl x Dfl)) n. pollutant mole fraction exiting scrubber(Out HClm) =In HClm x (100-E)/(100 - (In HClm x E))
o. adsorption factor (AF) defined in Appendix D-2 p. packing constant (t) defined in Appendix D-2 q. Hpack =Ln(In HClm/Out HClm) x (HpackA/HpackB^BBB) x HpackC + 1/AF x (t x HpackE^BB) x HpackE 18. Cost factor for pump, $/gpm (Cfpump) defined in Appendix D-2 19. Factor to convert FRP to another material defined in Appendix D-2 20. Cost Index a. 2008 525.4 b. 1998 389.5 21. Capital recovery factor (CRF) = [i x (1 + i) a ] / [(1 + i) a - 1], where i = interest rate, a = equipment life
Equipment CRF, 20-yr life, 7% interest Duct CRF, 20-yr life, 7% interest 22. Operating labor rate, $/hr (CFlab) $51.26 23. Electricity cost, $/kWh (CFelec) $0.069981 24. Water cost, $/gal (CFw) $0.00059889 25. Wastewater disposal cost, $/gal (CFww) $0.005439 26. Pump Cost Factor, $/gpm (CFp) $23.64 27. Cost Factor for Caustic, $/ton (CFcaus) $600 28. Moles of caustic/moles pollutant (SR1) defined in Appendix D-2

### Appendix D: Packed Bed Scrubber Parameters/Costs Equation 29. Caustic mole weight, lb/lbmole (MWcaustic) defined in Appendix D-2 30. Gas molecular weight, lb/lb-mole (MWg) defined in Appendix D-2 31. Moles salt/moles HCl (SR2) defined in Appendix D-2 32. Salt molecular weight, lb/lbmole (MWsalt) defined in Appendix D-2 33. Fraction of waste stream treated (BF) defined in Appendix D-2 34. Maintenance labor rate, $/hr (Cfmain) $51.26 35. Retrofit Factor 1.4 19. Gas transport velocity, ft/min (ut) defined in Appendix D-2 20. Diameter of duct, ft (Dd) =1.128 x (Q/ut)^1/2 21. Number of Duct Lines, (ND) if Q < 154042 acfm =1 if Q > 154042 acfm = Q/154042 acfm 22. Length of ductwork (L) defined in Appendix D-2 23. # of elbows per length of duct (Ne/Ld) defined in Appendix D-2 24. Fan coefficient (af) defined in Appendix D-2 25. Fan Diameter, inches (Df) defined in Appendix D-2 26. Fan exponent (b) defined in Appendix D-2
B. Total Capital Investment (TCI) 1. TCItower, $ =(417.956 x m x PI x Ds x Hpack) + (453.7808 x m x PI x Ds^2) + (838.8974 x m x PI x Ds) 2. TCIp, $ =0.649 x Cp x Hpack x PI x Ds^2 3. TCIpump, $ =0.0312 x MWR x a x PI x Ds^2 x Cfpump x m 4. TCIduct, $ =(1.458 x ((0.39 x ((Dd/ND)^2) x 3.14159 x L)+(74.2 x L x Ne/Ld x EXP(0.8016 x (Dd/ND))) + (23 x EXP(0.6804 x (Dd/ND))) + (af x (Df^b)))) 5. Total TCI, $ = (TCItower + TCIpump + TCIp + TCIduct) x (525.4/389.5) x Retrofit Factor 6. $/acfm = $ / Q
C. Direct Annual Operating Costs, $/yr 1. Electricity a. Pressure of pump, ft of H2O (Pp) defined in Appendix D-2 b. Efficiency of pump (Ep) defined in Appendix D-2 c. Electricity for Pump use, kw (Epump) =(0.00000585 x H x PI x Ds^2 x MWR x ap x Pp) / Ep d. Friction loss factor for elbow (k) defined in Appendix D-2 e. Efficiency of fan (ef) defined in Appendix D-2 f. Pressure drop through duct, in.H2O (Pd) =0.136 x (1/Dd)^1.18 x (ut/1000)^1.8 + (L/100) x (L x Ne/Ld x k x (ut/4016)^2) g. packing constant (c) defined in Appendix D-2 h. packing constant (j) defined in Appendix D-2 i. Pressure drop through scrubber, in.H2O (Ps) =(Hpack x AQ^2 x c x Dg x [10^(j x MWR x Dl x ap / 3600)]) / (225 x PI^2 x Ds^4) j. Pressure drop of gas, in.H2O (Pg) =Ps+Pd k. Electricity for Fan use, kW (Efan) =((0.000117 x AQ x H x Pg)/ef) l. Cost of Electricity, $/yr (Ce) =EC x (Epump + Efan) 2. Caustic Cost ($/yr), Ccaustic =0.03 x AQ x Dg x (In HClm - Out HClm) x SR1 x MWcaustic x H x CFcaus / MWg 3. Cost of ww disposal, $/yr (Cww) =7.194 x AQ x Dg x (In HClm - Out HClm) x SR2 x Mwsalt x (1/BF) x H x CFww / MWg 4. Cost of water, $/yr (Cw) =Cww x (CFw / CFww) 5. Cost of Labor, $/yr (Clab) = 0.07188 x H x Cflab 6. Cost of Maintenance, $/yr (Cmain) =0.125 x H x Cfmain
D. Indirect Annual Costs, $/yr 1. Overhead = 0.6 x (CFlab + CFmain) 2. Property taxes = 0.01 x TCI 3. Capital recovery = Equipment CRF x (TCI) 4. Administrative cost =0.02 x TCI 5. Insurance =0.01 x TCI 6. Capital recovery = CRF x TCI 7. Duct TAC a.TACductwork =TCIduct x (0.04 + CRFduct) b. Duct_cap recov =TACductwork x 0.7 c. Duct_admin =TACductwork x 0.1498

### Appendix D: Packed Bed Scrubber Parameters/Costs Equation d. Duct_prop tax =TACductwork x 0.0749 e. Duct_insurance =TACductwork x 0.0749 f. Total TACduct =Duct_cap recov + Duct_admin + Duct_prop tax + Duct_insurance

E. Total Annual Cost 1. $/yr = Direct Annual Costs + Indirect Annual Costs + Total TACduct 2. ($/yr) / acfm = ($/yr) / AQ

Sources: 1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 8. EPA/452/B-02-001, Ja nuary 2002. 2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, October 2002.

## Appendix D: Packed Bed Scrubber

Var COMMON DEFAULTS - PACKED SCRUBBER I I = interest rate 0.07 Dg Dg = density of gas, lb/ft3 0.0709 Ne_Ld Ne/LD = # of elbows per length of duct 0.02 L L = length of ductwork 500 MWR MWR = minimum wetting rate, ft2/hr 1.3 ut ut = gas transport velocity, ft/min 3000 Dl Dl = density of liquid, lb/ft3 62.4 ap a = packing constant, ft2/ft3 28

Var DEFAULTS- TOTAL ANNUAL COST -- PACKED SCRUBBER n n = life of equipment, yrs 15 SR1 SR1 = moles caustic/moles pollutant 0.5 MWc MWc = caustic molec wt, lb/lb-mole 62 Op_Scr Op_Scr = operating hours/year 8400 CFc Cfc = cost factor for caustic, $/ton 440 MWg MWg = gas molecular weight, lb/lb-mole 29 SR2 SR2 = moles salt/moles HCl 1 MWs MWs = salt molecular weight, lb/lb-mole 58.5 BF BF = fraction of waste stream treated 0.1 CFww CFww = cost factor for ww disposal, $/gal 0.0054 CFw t CFwt = cost factor for water, $/ga l 0.00060 SR3 SR3 = adjustment for 76% Na2O solution 0.76 CFlab CFlab = cost factor for labor, $/hr 51.26 CFmain CFmain = cost factor for maintenance, $/h r 51.26

DEFAULTS - ELECTRICITY - PACKED SCRUBBER CFelec CFelec = cost factor for electricy, $/kw-hr 0.06998 Pp Pp = pressure of pump, ft of H20 60 Ep Ep = efficiency of pump 0.7 Op_pump Op_pump = operating hours/year 8000 cpc cpc = packing constant 0.24 j j = packing constant 0.17 k k = friction loss factor for elbow 0.35 ef ef = efficiency of fan 0.7

DEFAULTS - DUCTWORK - PACKED SCRUBBER af af = fan coefficient 22.1 b b = fan exponent 1.55 Df Df = fan diameter, inches 36.5 n_duc t n_duct = life of equipment, yr s 20 PACKED SCRUBBER DEFAULTS

## Appendix D: Packed Bed Scrubber DEFAULTS -TCI - PACKED SCRUBBER m m = factor to convert from FRP to other material 1
mm mm = ratio of solvent density to water density 1 Fp Fp = packing factor 65 ui ui = viscosity of liquid, lb/ft-hr 2.16 f f = flooding factor 0.7 ug ug = viscosity of gas, lb/ft-hr 0.044 Dfg Dfg = diffusivity of pollutant in gas, ft2/hr 0.725 Dfl Dfl = diffusivity of pollutant in liquid, ft2/hr 0.000102 AFT AFT = absorption factor 17 x x = packing constant 3.82 t t = packing constant 0.0125 g g = packing constant 0.45 BBB BBB = packing constant 0.41 bb b = packing constant 0.22 eff eff = efficiency of scrubber 99 Cp Cp = packing cost factor, $/ft3 20 CFpump CFpump = cost factor for pump, $/gpm 23.64 Site Site 0 Bldg Bldg 0

Sources:

2. Oommen, Roy. Methodology for Estimating Control Costs for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, October 2002. 1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 8. EPA/452/B-02-001, January 2002.

### Appendix E: Increased Caustic Parameters/Cost s Equation Fuel Categor y F-Factor Bagasse 9420 A. Parameters Coal 9780 1. Annual operating hours, hr/yr (H) used Boiler Survey data as input Dry Biomass 9240 2. Exhaust gas flow rate, acfm (AQ) calculated per boiler, see Section 2.0 of the memo. Gas 1 (NG Only) 8710 3. Exhaust gas flow rate, dscfm (Q) calculated per boiler, see Section 2.0 of the memo. Gas 1 (Other) 8710 4. Baseline HCl, units (lb/mmBtu) (HClb) calculated per boiler Gas 2 8710 5. Floor HCl level, (lb/mmBtu) (HClf) assigned by fuel category 6. F-Factor determined by fuel category, see index Heavy Liquid 9190 7. Uncontrolled HCl, ppmvd (HClu) =HClb x F-Factor x (1/36.4609) x 385.34 x 1000000 Light Liquid 9190 8. Controlled HCl, ppmvd (HClc) =HClf x F-Factor x (1/36.4609) x 385.34 x 1000000 Wet Biomass 9600 9. Operating Labor Rate, $/hr (LR) $51.26 10. Wastewater Blowdown, gpm (B) =Hclu/1000000 x Q x 1/385 x 1/1 x 58.2/1 x 1/0.1 x 1/8.33 11. Caustic Cost, $/ton (CC) $357 12. Sewage disposal, $/1000 gal (SDC) $5.40 13. Water Cost, $/1000 gal (WC) $0.60 14. Lime Cost, $/ton (LC) $95 15. Sodium Bicarbonate, $/ton (SBC) $440 16. Dust Disposal, $/ton (DDC) $34.29 17. Activated Carbon, $/lb (ACC) $1.38 18. Natural Gas, $/1000 ft3 (NGC) $9.58 19. Electricity Cost, $/kWh (EC) $0.07 20. Capital recovery factors = [i x (1 + i) a ] / [(1 + i) a - 1], where i = interest rate, a
= e q ui p ment lif e a. Bag CRF, 2-yr life, 7% interest b. Cage CRF, 4-yr life, 7% interest 15. Cost index a. 2008 525.4 b. 1984 317.4
B. Total Bag/Cage Cost 1. $ = AQ x 2.5 x (525.4/317.4) x (1.08/3.5) 2. Bag Replacement Labor Cost = AQ x 0.15/18/3.5 x LR 3. Cage Replacement Labor Cost = Bag Replacement Labor Cost 4. Total Cage Cost = Cage CRF x ((4.941 + 0.163 x 18) x (AQ/3.5/18) x (5.75.4/317.4) + Cage Labor Cost

C. Total Increased NaHCO3 Cost 1. Makeup NaHCO3 Cost, $ = 2.73x10-7 x Hclu x Q x 1/2000 x 60 x H x SBC 2. Dust Disposal Cost, $ =HCLu x Q x 60 x 2.1x10-7 x 1/2000 x H x DDC 3. Total Cost, $/yr/dscfm =(Makeup NaHCO3 + Dust Disposal Cost) /Q

D. Increased Carbon Cost 1. Activated Carbon Cost, $ =1.27x10-3 x Q x H x ACC 2.Dust Disposal Cost, $ =1.27x10-3 x Q x 1/2000 x H x DDC 3. Total Cost, $/yr/dscfm = (Activated Carbon Cost + Dust Disposal Cost)/Q

Sources: 1. Cost equations: Hospital/Medical/Infectious Waste Incinerators (HMIWI) [EPA-HQ-OAR-2006-0534] Model Plant Description and C ost Report (II-A-112); and Dry Injection Fabric Filter Cost Memorandum (IV-B-32).

## Appendix F: Activated Carbon Injection Model Costs Parameters/Costs Equation

A. Parameters 1. Incinerator capacity, lb/hr (C) converted based on reported heat input capacity
2. Annual operating hours, hr/yr (H) as reported in survey 3. Exhaust gas flow rate, dscfm (Q) calculated per boiler, see Section 2.0 of the memo. 4. Operating labor rate, $/hr (LR) $51.26 5. Activated carbon cost, $/lb (ACC) $1.38 6. Dust disposal cost, $/ton (DDC) $42.14 7. Capital recovery factor, 20-yr equipment life, 7% interest (CRF) = [i x (1 + i) a ] / [(1 + i) a - 1], where i = interest rate,
a = e q ui p ment life 8. Cost index a. 2008 

### 525.4 b. 1990 

### 390.6 9. ACI Adjustment Factor (AF) Calculated control efficiency (% reduction) to meet Hg or D/F limit/0.9
B. Total Capital Investment 1. $ = 4,500 x (Q/1,976) 0.6 x (1.2 retrofit factor) x ( 575.4/361.3 ) 2. $/dscfm = $ / Q
C. Direct Annual Costs, $/yr 1. Operating labor = (0.25 hr/8-hr shift) x H x LR 2. Supervisory labor = 0.15 x (operating labor) 3. Maintenance = 0.2 x TCI 4. Activated carbon = 0.00127 x Q x H x ACC x AF 5. Dust disposal = 0.00127 x Q x (1 ton/2,000 lb) x H x DDC x AF

D. Indirect Annual Costs, $/yr 1. Overhead = 0.6 x (labor + maintenance materials) 2. Property taxes, insurance, and administration = 0.04 x TCI
3. Capital recovery = CRF x TCI

E. Total Annual Cost 1. $/yr = Direct Annual Costs + Indirect Annual Costs 2. ($/yr) / dscfm = ($/yr) / Q

Note:

Sources:

4. Dust disposal cost: NSWMA’s 2005 Tip Fee Survey. Factor of 1.27 x 10 -3 for activated carbon is based on injecting carbon at a rate to achieve a carbon concentration of 338 mg/dscm (achieving reductions of 90% for Hg, 98% for CDD/CDF).

2. Operating labor rate: Bureau of Labor Statistics, Occupational Employment Statistics, May 2007 National Industry-Specific Occupational Employment and Wage Estimates. 1. Cost equations: Hospital/Medical/Infectious Waste Incinerators (HMIWI) [EPA-HQ-OAR-2006- 0534] Model Plant Description and Cost Report (II-A-112).

3. Activated carbon cost: The Innovation Group. Chemical Profiles: Carbon, Activated. 2002. Assumed 20% price increase based on online information from Norit, an activated carbon vendor.

### Appendix G: Low NOx Burners Parameters/Costs Equation

A. Parameters 1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 mmBtu/hr) 2. Annual operating hours, hr/yr (H) used Boiler Survey data as input 3. Unit Size, kW (kW) =C x (1000/3.413) 4. Unit Size, MW (MW) =C x (1/3.413) 5. Capital recovery factor = [i x (1 + i) a ] / [(1 + i) a - 1], where i = interest rate,
a = e q ui p ment life a. Equipment CRF, 15-yr life, 7% interest

15. Cost index a. 2008 525.4 b. 2004 444.2
B. Total Capital Investment TCI ($) =20 x kW x (300/MW)^0.359
C. Direct Annual Operating Costs, $/yr Variable O&M Costs = 0.000293 x H x C x (0.05/1000) x (575.4/444.2)

D. Indirect Annual Costs, $/yr 1. Fixed O&M Costs = 0.015 x TCI 2. Capital recovery = Equipment CRF x TCI

1. $/yr = Direct Annual Costs + Indirect Annual Costs

Source:

1. ERG, 2005. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-Fired EGUs in the WRAP Region September 6, 2005.

### Appendix H: Oxidation Catalyst Parameters/Costs Equation

A. Parameters 1. Boiler design capacity, mmBtu/hr (C) used Boiler Survey data as input, for small units (<10, used 5 mmBtu/hr ) 2. Annual o p eratin g hours
, hr/ y r ( H ) 8400 3. Exhaust g as flow rate, scfm ( Q ) calculated per boiler, see Section 2.0 of the memo

. 4. Percent additional fuel/air added (Aux) = Default of 0.05 5. Exhaust gas flow rate, scfm (AF) =Q x (1+Aux) 6. Equipment Cost, $ ( EC ) = 1105 x Q^0.5471 7. Additional Purchase Equipment Cost ( Instruments,taxes,frei g ht ) , $ ( AddEC ) = 0.35 x EC
8. Direct Installation Costs, $ ( DIC ) =0.282 x ( EC+AddEC ) 9. Indirect Installation Costs, $ ( IIC ) =0.22 x ( EC + AddEC ) 9. Operatin g labor rate, $/hr ( LR ) 51.26 10. Electricit y cost, $/kWh ( EC ) 0.06998 11. Catal y st cost, $/ft^3 ( Cc ) 959 12. Pressure chan g e, in of H2O ( Pc ) 6 13. Efficienc y of fan and motor ( Ef ) 0.6 14. Capital recovery factors = [i x (1 + i) a ] / [(1 + i) a - 1], where i = interest rate, a = equipment life a. Catal y st CRF, 2- y r life, 7% interes t b. Equipment CRF, 20- y r life, 7% interes t 15. Cost inde x a. 200 8 525.4 b. 1990 390.6

16. Space Velocity in 1/h (Sv) 12000

17. Retrofit Factor 1.4
Total Capital Investment B. 1. $ =(EC + AddEC + DIC + IIC) x (577.4/390.6) x Retrofit Cost
2. $/scfm = $ / Q

C. 1. Electricit y a. Power of Fan ( Pf ) = ( 0.000117 x AF x Pc ) /0.6 b. Cost of Electricit y =Pf x H x EC 2. Operatin g labo r = H/8 x 0.5 x LR 3. Supervisor y labo r = 0.15 x ( operatin g labor ) 4. Maintenance labo r = Operatin g labo r 5. Maintenance material s = Maintenance labo r 6. Catal y st Replacemen t a. Catal y st Replacement Volume, ft3 ( CRV ) =AF x 60/Sv b. Catal y st Replacement Cos t =CRV x Cc x Catal y st CRF

### Appendix H: Oxidation Catalyst Parameters/Costs Equation 1. Overhead = 0.6 x (electricity + operating labor + supervisory labor + maintenance labor + maintenance materials + catalyst replacement ) D. 2. Property taxes, insurance, and administration = 0.04 x TCI
3. Capital recovery = Equipment CRF x (TCI - 1.08 x catalyst replacement cost)

E. Total Annual Cost 1. $/yr = Direct Annual Costs + Indirect Annual Cost s 2. ($/yr) / dscfm = ($/yr) / Q

Sources: 1. U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. Chapter 2. EPA/452/B-02-001, Ja nuary 2002.Appendix J: Carbon Bed Adsorbe r Parameters/Cost s Equation Fuel Categor y F-Factor Bagasse 9420 A. Parameters Coal 9780 1. Boiler design capacity, mmBtu/hr (C) Combined for all RFG units at facility Dry Biomass 9240 2. kW Capacity, kW (kW) = C*(1000/3.413) 3. Annual operating hours, hr/yr (H) 8400 Gas 1 8710 4. Exhaust gas flow rate, dscfm (Q) calculated per boiler, see Section 2.0 of the memo. Gas 2 8710 5. Hg Floor, lb/mmBtu (Hgf) assigned per fuel category Heavy Liquid 9190 6. Hg Baseline, lb/mmBtu (Hgb) calculated per boiler Light Liquid 9190 7. F-Factor assigned per fuel category Wet Biomass 9600 8. Controlled Hg Concentration, lb/mmBtu (Hgc) = Hgf x 1000000 x 453.59 x 35.315/F-Factor 9. Uncontrolled Hg, lb/mmBtu (Hgu) = Hgb x 1000000 x 453.59 x 35.315/F-Factor 10. Hg Efficiency (Hge) = (Hgu - Hgc)/Hgu 11. Hg Adjustment Factor for >90% = He/0.90 12 Uncontrolled Hg Concentration, mg/yr = Hgc x Q x 1/35.315 x 60 x H 13. Carbon Consumption, lb/yr (AC) = 338 x (Q/35.315) /1000/453.593 x 60 x H x Hg Adjustment Factor 14. Labor Rate, $/hr (LR) $51.26 15. Carbon cost, $/lb (ACC) $1.38 16. Spent Carbon Landfill Cost, $/ton (SCC) $42.14 17. Capital recovery factors = [i x (1 + i) a ] / [(1 + i) a - 1], where i = interest rate, a = equipment life a. Equipment CRF, 15-yr life, 7% interest 18. Retrofit Factor Constant (RF) = 1.6
B. Total Capital Investment 1. TCI, $ = 30 x kW x RF
C. Direct Annual Operating Costs, $/yr 1. Operating labor = 0.5 x H x LR 2. Supervisory labor = 0.15 x (operating labor) 3. Maintenance labor = 0.5/8 x H x (LR x 1.1) 4. Maintenance materials = Maintenance labor 5. Carbon Replacement = AC x ACC 6. Carbon Disposal = AC x SCC/2000
D. Indirect Annual Operating Costs, $/yr 1. Overhead = 0.6 x (operating labor + supervisory labor + maintenance labor + maintenance materials) 2. Property taxes, insurance, and administration = 0.04 x TCI 3. Capital recovery = Equipment CRF x (TCI) 4. Engineering = 0.1 x TCI 5. Construction/Field Experience = 0.05 x TCI 6. Contractor Fees = 0.1 x TCI 7. Contingencies = 0.3 x TCI

E. Total Annual Cost 1. $/y r = Direct Annual Costs + Indirect Annual Costs

Source: Holloway, Tom. RTI International. Revised Baseline Operating Costs for Existing HMIWI Memo. June 19, 2009.Boiler/Process Heater Design Capacity (mmBtu/hr) Liquid Fuel? Cost per Testing Trip Pollutants Tested For >=100 no 37000 PM, HCl, Hg, D/F >=100 yes 10000 PM, D/F <100 no 44000 CO, PM, HCl, Hg, D/F <100 yes 16000 CO, PM, D/F REFINERY GAS 7000 Hg Appendix J-1: Summary of Testing Costs

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), CO, HCl, 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. Tests for dioxins/furans were estimated to range from $15,000 to $50,000.
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 or PM and HCl), then the site-specific cost would start in the $5,000 - $7,000 with a few $1,000 added for subsequent pollutants. If a facility needed PM data and dioxin/furan data, then the site-specific cost would be the sum of the test in the $5,000 - $7,000 range and the $15,000 - $50,000 range.
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.
Since existing refinery gas units are only subject to a mercury limit, only the cost to conduct a mercury test were included in the cost impacts analysis.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 J-2: Summary of CO CEMSAppendix J-3: Other Monitoring Costs for Boilers and Process HeatersParameters/Costs EquationA. Parameters1. Recording lime/carbon flow, min/4-hr period52. Annual operating hours, hr/yr (H)3. Cost indexa. 2008575.4 575.4 575.4 575.4 All costsare in$2008575.4b. 2006499.6 All costsare in$2006499.6 All costsare in$2006c. 1998389.5All costsare in$1997d. 1997386.5 All other costs are$1997e. 1993359.2 Equipment costs, are$1993f. 19924. Operating labor wage rate, $/hr(LR)$34.60 $34.60 $34.60 $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 life0.09439 0.09439 0.09439 0.09439B. Total Capital Investment, $ (TCI)1. Planning$700 $800 $9002. Select type of equipment$400 $4,500 $12,2003. Provide support facilities$1,500 $500 $5004. Purchased equipment cost (PEC)$19,300 $14,100 $73,5005. Install and check equipment$1,000 $4,800 $19,5006. Perf. spec. tests (certif.)$700 $0 $35,5007. Prepare QA/QC plan$700 $800 $15,4008. Total capital cost = Planning + selecting equipment + support facilities + PEC + installation + perf. spec.tests + QA/QC plan$24,300 $25,500 $158,000 $115,000 $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$500$1,4773. Operation & maintenance = Day-to-day activities + annual RATA + CGA + annual QA + O&M review and update $6,000 $27,300$5,9094. Recordkeeping and reporting = $1,000 x (525.4/386.5) $1,500 $200 $6,300 $1,4775. Overhead = 0.6 x (labor + maintenance materials) $3006. Property taxes, insurance, andadministration= 0.04 x TCI$1,000$1,7257. Capital recovery = CRF x TCI$2,300 $3,500 $22,500 $4,0718. Total annual cost = Operating labor + maintenance materials + recordkeeping and reporting + overhead+ property taxes, insurance, and administration + capital recovery$5,600 $9,700 $56,100 $14,661Based on hrs/yrOpacityAs reported insurveyBased on hrs/yrBased on hrs/yrWS Bag leak detector PM CEMS ACIAppendix J-3: Other Monitoring Costs for Boilers and Process HeatersNotes: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 and Monitoring Options and Costs for Medical Waste Incinerators(MWI’s) - Methodology and Assumptions. March 17, 1997.