MEMORANDUM
TO: Brian Shrager, U.S. Envir onmental Protection Agency, OAQPS
FROM: Eastern Research Group, Inc.

DATE: November 2011
SUBJECT: Revised (November 2011) Met hodology for Estimating Control Costs for Industrial, Commercial, Institutional Boilers and Process Heaters 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 energy audits. The a dd-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 Test Plan,” as well as other voluntary data submitted as part of this rulemaking. A data dicti onary and description of all the fields contained in the database of reported industry da ta are summarized in other memoranda. 3 The standardization of reported emission data and the methodology used to assign baseline emission
factors to each boiler and process heater in the unit inve ntory are also described in other
memoranda. 4, 5

This memorandum is organized as follows:
1.0 Introduction
2.0 Inputs for Cost Algorithms3.0 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 Contro l Technology (MACT) floor emission limits 6 and analyzed for the impacts analysis include the fabric filter, electrostatic precipitator (ESP), packed bed scrubber, dry injection/ fa bric filter systems (DIFF), ac tivated carbon in jection (ACI), replacement burners (assumed to be low-nitrogen oxide [NO x ] burners), linkageless boiler management system, and carbon monoxide (CO) oxi dation catalyst. In addition, for units that reported to have a scrubber alr eady installed, the impacts analysis also analyzed the costs of increasing the caustic flowrate on an existing scr ubber in order to improve scrubber efficiency. Also, for units with selective catalytic reducti on (SCR) and a scrubber installed, implementation of halogen addition and/or slurry additive systems were analyzed.



### 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 Chemi cal Engineering Plant Cost index. The cost equations for ACI provided cost estimates at 2009 do llars, which were left as is rather than deescalating to an older year. 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—Cost Component Cost (2008$) Source
Version 7.5 Cost Factor for Caustic ($/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, dry injection/fabric filter, ESP and a CO oxidation catalyst as well as any
duct work associated with the installation of th ese control devices. Per guidance in the mercurybackground document, a retrofit factor of 1 wa s used for ACI costs as ACI systems do not typically require significant amounts of additional space. 10 A factor of 1.3 in the EPA CueCost model represents a retrofit of medium difficulty.


### 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, DIFF CO oxida tion catalysts, and ESPs.
This annual hour estimate was used to avoid und erestimating the variable operating costs. The operating hours reported in the survey were used for the activated carbon injection, low-NO x burners (LNB), and increased scrubber caus tic, as these technologies lack large capital expenditures and their cost estimates are mo re 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 this represents full-ti me operation accounting with a two-week downtime period 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 ofhydrogen 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 compos ition, 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 CalculationsCoal 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 Dry Injection/Fabr ic Filter (DIFF)
The inclusion of dry injection prior to a fabric filter offe rs emission control for hydrogen chloride (HCl). The algorithms used to estima te capital and annual costs of DIFF systems were based on those 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 annual a nd capital costs are provided in Appendix I-1. The algorithms estimate the capita l cost of the equipment based on the exhaust flowrate. Annual costs include lime, water, dust disposal, electri city, maintenance, labo r, bag replacement, maintenance labor, compressed air, capital reco very costs, overhead, administrative costs, property taxes, and insurance.


### 3.3 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.



### 3.4 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.

### 3.5 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.


### 3.6 Activated Carbon Injection Activated carbon injection (AC I) offers emission control for Hg. Cost estimates for ACI were derived from a Sargent & Lundy report which presents recent cost estimates based on industry experience. 10 This same methodology was also used for the Utility NESHAP ACI cost
calculations. 28 While the Sargent & Lundy report provi ded example calculations for coal only, their analysis was applied to all subcategorie s (e.g. biomass and hea vy liquid) for the Boiler MACT cost estimates. Appropria te fuel-specific information including HHV and ash content, was gathered for other fuel types to input into the equations, while this information for coal was kept consistent with the Sargent & Lundy repor t values. The cost estimate assumed all carbon and fly ash waste was disposed of and calculate d the cost of waste disposal; this provided a
conservative estimate since no beneficial use for the fly ash was considered. The carbon feed rate was based off the type of control device cu rrently available. If a boiler had an existing fabric filter then 2 lb/MMacf (pounds per millio n actual cubic feet) was used, otherwise a value
of 5 lb/MMacf was selected fo r the carbon feed rate. See Appendix F-1 for the methodology in calculating ACI capital and annual costs.


### 3.7 Slurry Additive and Halogen Addition Systems The Sargent & Lundy report provid ed alternatives for reducing mercury in lieu of the use
of ACI if certain criteria are met. 10 These alternatives includ e slurry additive and halogenaddition systems. These alternatives are applicab le if a boiler has an S CR already installed and it
is estimated that a wet scrubber would be installe d to meet the HCl limit. A co-benefit between the SCR and wet scrubber during simultaneous op eration would allow up to 80% reduction in mercury. To achieve the proper co-benefit a slurry additive is necessary, however. Furthermore,
if the boiler fires sub-bituminous or lignite coal then a halogen addition system is required in order for the chemistry of the interactions to work. See the Sargent & Lundy report for the full background on the slurry additive and halogen ad dition systems. It is noted for the Boiler MACT cost analysis that none of the boilers me t the criteria for the co -benefit of SCR and wet scrubber operation. See Appendices F-2 and F- 3 for the methodology related to the slurry additive and halogen addition syst ems capital and annual costs.



### 3.8 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 efficiency. 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.

### 3.9 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


### 3.10 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.


### 3.11 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, andit 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 st andard in lieu of an
emission limit for small boilers less than 10 mmB tu/hr, limited use boilers (operating less than 876 hours per year), and natural gas and refinery gas-fired boilers of al l sizes. For all other boilers greater than 10 mmBtu/hr there is a work practice standard for dioxin/furan in addition to numeric emission limits for the other pollutants.
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 pe r boiler in initial se t-up costs was annualized over five years and added to the subsequent year costs for an annual tune-up. Although the ru le allows a biennialtune-up in some circumstances we used the annual tune-up as the basis for this analysis to be
conservative. Annual Tune-up Cost ($2008) = {[C $2004 * (X 2008 / X 2004 ) * i * (1+ i ) y ] / [(1+ i ) y – 1)]} + [Z $2004 * (X 2008 / X 2004 )] = $2,875 (Equation 1) Where: C $2004 = Average set-up cost, $5,000 (from 2004) X 2008 = 2008 cost index, 575.4 X 2004 = 2004 cost index, 442.2 i = interest rate, 7% y = length of annuity, 5 years Z $2004 = annual tuning cost, $1,000 (from 2004)
Biennial tune-up costs would pr ovide some cost savings, although the costs of the initial tune-up set-up must be factored in to both of the work practice freque ncies, so this analysis used a single tune-up cost, which is ba sed on an annual frequency. The a nnualized cost for a biennial tune-up is $2,228 per boiler, as shown in Equation 2.

Biennial Tune-up Cost ($2008) = {[C $2004 * (X 2008 /X 2004 ) * i * (1+ i ) y ] / [(1+ i ) y – 1)]} + [(Z $2004 / 2) * (X 2008 /X 2004 )] = $2,228 (Equation 2) Where: C $2004 = Average set-up cost, $5,000 (from 2004) X 2008 = 2008 cost index, 575.4 X 2004 = 2004 cost index, 442.2 i = interest rate, 7% y = length of annuity, 5 years Z $2004 = annual tuning cost, $1,000 (from 2004)

For new model boilers with a rated heat capacity less than 5 00,000 Btu per hour, a tuneup cost of $200 was selected. We did not estimate this smaller cost for existing units because the ICR survey asked questions about groups of sma ll units that were less than 10 mmBtu/hr and we
do not know the exact size of these small units. This value was based on research of tune-up costs for similarly sized home boiler programs, which suggested the costs of a tune-up ranged from $60 to $150. 26,27 The USI study and other literature sugg est that annual boiler tune-ups can improve combustion efficiency between 1 and 5 pe rcent, and often the fuel savings cover the cost of conducting a tune-up. The cost estimate for the tune-up in this analysis includes inspection of the burner, clean ing and repairs 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. We used the NAICS code to dete rmine the length and cost of the audit, since the length of the audit in the proposal is tiered based on facility energy consumption.
Sector NAICS Codes Industrial 221, 311, 312, 313, 314, 316, 321, 322, 323, 324, 325, 326, 327, 331, 332, 333, 334, 335, 336, 337, & 339 Commercial 111, 113, 115, 211, 212, 423, 424, 441, 481, 482, 486, 488, 493, 531, 541, 561, 562, 611, 622, 623, 811, 921, & 928

For industrial facilities a cost of $75,000 wa s estimated for an energy audit. This estimate is based on costs presented to the 2009 Boiler Small Business Regulatory Flexibility Act panel by an affected small entity, Port Townsend Paper Company. The cost was annualized over five years at 7 percent interest to estimat e the annual cost impacts of the proposed rule; $18,292 annually. Commercial and instit utional 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 impact of energy audits for all NAICS codes representing commercial and institutional facilities. An average of $3,500 per facility was annualized over five years at 7 percent to obtain an annualized cost estimate for energy audits at commercial facilities; $854 annually.



### 4.3 Testing Capital and annual costs for testing include stack tests for PM, Hg, HCl, and CO. Additionally, capital and annual costs to repeat testing to meet the ‘worst case’ conditions in the proposed rule include the cost to stack test for Hg and HCl. The proposed rule provides a compliance alternative to conduct a fu el analysis in lieu of a stack test for HCl and Hg, if the fuel contains less mercury or chlo rine than the MACT floor emission limit for the appropriate subcategory. The proposed rule al so provides compliance flexibility to sources that consecutively test at 75 percent or less of the emission limits, or at or below the emission limit for limits that
are based on minimum detection levels. The flexibili ty allows these sources to test at two-year intervals instead of annually. Because the number of sources expected to qualify for the reducedtesting interval is unknown, and all sources must test annuall y for the first two years of compliance, this cost analysis is based on an annual testing frequency. The cost analysis also assumes that every solid fuel unit will conduct te sting for all pollutants annually, and liquid fuel units will conduct stack testing for PM and CO a nd fuel analysis for Hg and chlorine. Testing cost estimates were based on those used in the Phase II Test Plan and were adjusted downward slightly to account for a lower number of pollutants being tested. The testing costs assume that all pollutants will be tested simultaneously, or over the course of a single travel occurrence for a testing contractor. For the simp ler methods (e.g., PM), the testing costs range from $5,000 to $7,000. For the pollutants that involve more lab anal ysis (e.g., Hg), the testing costs range from $10,000 to $15,000. Although the cost ranges can be appl ied, as is done for cases where a single pollutant is being measured, estima ting costs for facilities that need test data for more than one pollutant is more difficult and unc ertain. For example, if a facil ity needs PM and CO data, the
test costs would not be twice th e $5,000 to $7,000 price, because some of the costs are associated with getting the testing contract or to the site and setting up th e equipment (these are one-time costs, such as port installa tion and scaffolding costs desc ribed below and would not be duplicated regardless of the number of pollutants test ed). 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 costs would start in the $5,000 to $7,000 range with a few thousand dollars added for the second pollutant. If a facility needed PM data and Hg da ta, then the site-specific 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 Phase II Test Plan for a discussion of the testing cost estimates. 2 A summary of the testing and monitoring 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. Annual costs were estimated for mercury fuel spec analyses for gaseous units as well. For certain boilers it is necessary to determine its mercury content on a m onthly basis in order todetermine if the fuel qualifies as a gas 1 fuel or if it is a gas 2 fuel subject to emission limits. The average monthly cost for the fuel analysis is es timated at $200 for an annual cost of $2,400.


### 4.4 Monitoring Monitoring costs are included for opacity mon itoring (for units wit hout scrubbers) or PM continuous emissions monitoring systems (CEMS) (f or certain units with an average annual heat input rate from solid fossil or h eavy liquids greater than 250 mmBtu /hr), bag leak detection (for units with fabric filters), scrubber parametric monitoring (for units with scrubbers), and O 2 monitors (for units greater than 10 mmBtu/hr). Cost estimates for O 2 monitors were based on in situ monitor costs from Chapter 4 of th e OAQPS Control Cost Manual, Sixth Edition 24 . 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 th e HMWI rulemaking, 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 relative accuracy test audit and writing the report; performing cylinder ga s audits; developing a QA/QC pl an; monitoring operations and maintenance; and performing capital recovery. Ba g leak detection, PM CEMS, and wet scrubber parametric monitoring were all annualized over a 20-year lifetime. A summary of the monitoring costs is presented 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. Eastern Research Group, Inc. Revised (N ovember 2011) Data Dictionary for Boiler, Process Heater, and Other Combustion Un it Survey Databases. November 2011.
4. Eastern Research Group, Inc. Revised (N ovember 2011) Standardization of Reported Data from the Questionnaire for Boilers, Process Heaters, Incinerators and Other Combustion Units. November 2011.
5. Eastern Research Group, Inc. Revised (November 2011) Development of Baseline Emission Factors for Boilers and Process Heaters at Commercial, Industrial and Institutional Facilities. November 2011.6. Eastern Research Group, Inc. Revised MA CT Floor Analysis (November 2011) for the Industrial, Commercial, Institutional Boile rs and Process Heaters National Emission Standards for Hazardous Air Pollutants – Major Source. November 2011.
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. Sargent & Lundy, IPM Model – Revisions to Co st and Performance for APC Technologies: Mercury Contro l Cost Development Methodology (Project 12301-009). March 2011.
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. Eastern Research Group, Inc. 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.pdf20. Eckerlin, Dr. H.M. and E.W. Soderberg , Industrial Extensio n Service USI boiler Efficiency Program. February 25, 2004. 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.
24. U.S. Environmental Protection Agency. EPA Air Pollution Control Cost Manual, Sixth Edition . EPA/452/B-02-001. Office of Air Quality Planning and Standards. January, 2002.
26. Ed’s Heating and Air, Inc. 1099 Pelto Path Woodbury, MN, 55129. http://www.merchantcircle.com/blogs /Eds.Heating.And.Air.Inc..Woodbury.MN.651-775- 7490/2008/10/Furnace-Tune-Up-Cost/126531
27. Five State Heating a nd Cooling, Charlotte, NC. http://www.fivestarheatingandcooling.com/
28. U.S. Environmental Protection Agency. NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating Units (D ocket # EPA-HQ-OAR-2009-0234). May 2011.