1 

MEMORANDUM 

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

FROM: Eastern Research Group, Inc. 

DATE: August 2012 

SUBJECT: Revised (August 2012) Methodology for Estimating Cost and Emissions Impacts 

for Industrial, Commercial, Institutional Boilers and Process Heaters National 

Emission Standards for Hazardous Air Pollutants – Major Source 

1.0 INTRODUCTION 

The purpose of this memorandum is to discuss the revised methodology used to estimate 

the costs, emission reductions, and secondary impacts from industrial, commercial, and 

institutional boilers at major sources of hazardous air pollutants (HAP). These impacts were 

calculated for existing units and new units projected to be operational by the year 2015, three 

years after the rule is expected to be promulgated. The results of the impacts analysis are 

presented for the regulatory option contained in the amended final rule. The development of the 

maximum achievable control technology (MACT) floor level of control, projection of new units, 

and a detailed description of the cost equations used to estimate costs for various control 

technologies is presented in other memoranda.1,2,3 This memorandum is organized as follows: 

1.0 Introduction 

2.0 Overview of Regulatory Options 

3.0 Estimating Cost Impacts 

4.0 Methodology for Estimating Emission Reductions 

5.0 Methodology for Estimating Secondary Impacts 

6.0 Incremental Impacts Since March, 2011 Rule Notice 

7.0 References 
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2.0 OVERVIEW OF REGULATORY OPTIONS 

 Two control options were considered for existing boilers and process heaters at major 

sources of HAP. A description of the two options is included in this section. 

2.1 Existing Units 

The recommended option is the option presented in the preamble and amended final rule. 

In this option, all boilers and process heaters are subject to work practice standards for 

dioxin/furan emissions. Small boilers and process heaters (less than 10 mmBtu per hour), limited 

use boilers and process heaters (operating less than 876 hours per year), and boilers burning 

natural gas, refinery gas, or other on-spec gaseous fuels are subject to work practice standards in 

lieu of numeric emission limitations for all pollutants. The work practice standard for very small 

(less than 5 MMBtu/hr) units designed to burn light liquid or gaseous fuels is one tune-up every 

five years. The work practice standard for other small and limited use units is a biennial tune-up. 

The work practice standard for large units (greater than or equal to 10 mmBtu per hour) is an 

annual boiler tune-up. 

In addition to the work practice standard for dioxin/furan, large boilers and process 

heaters that are not in the unit designed to burn natural gas, refinery gas, or other on-spec 

gaseous fuels subcategories are subject to numeric emission limitations for Hg, PM (or a total 

selected non-mercury metals (TSM8, which is composed of the metals As, Be, Cd, Cr, Pb, Mn, 

Ni, and Se) alternative), HCl, and CO. Boilers combusting at least 10 percent solid fuels (either 

coal, other fossil solids, or biomass), or at least 10 percent liquid fuels (either heavy liquid, light 

liquid, or units located in non-continental States and United States Territories designed to burn 

liquid fuels) are grouped into a single solid or liquid fuel subcategory, respectively, and are 

subject to identical emission limitations for the fuel-based pollutants Hg and HCl. For units 

designed to combust biomass/bio-based solids, separate combustor design subcategories are 

considered for the combustion-based pollutants PM (or TSM8) and CO. For units designed to 

combust coal/fossil solid, combustor design subcategories are considered for CO only. Emissions 

of PM (and TSM8) are not expected to vary with the differing combustor designs for coal-fired 

boilers, and thus all units firing coal/fossil solid are grouped into a single coal subcategory for 

the regulation of these pollutants. For units designed to burn liquid fuels, separate combustor 
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design subcategories are considered for PM and CO. Units burning off-spec gaseous fuels (other 

process gases) have a single subcategory for both fuel and combustion-based HAP. 

Based on conversations with regulated entities, it is likely that several large units firing 

liquid fuels in continental states that have access to natural gas supplies will switch to natural gas 

combustion in lieu of installing controls and demonstrating compliance with the emission limits 

for their respective subcategory. If the liquid-fired unit is in a continental state, is not a limited 

use unit, and reported the capability to combust natural gas for at least 10 percent of the total 

reported annual operating hours for the unit, it is assumed for the purposes of this impacts 

analysis that the unit will convert to 100 percent natural gas combustion. A total of 258 units 

firing liquid fuels were assumed to meet these criteria and switch to natural gas combustion. 

These units would be subject to the same work practice standards as existing units burning 

natural gas, refinery gas, or other on-spec gaseous fuels after making the switch to natural gas. 

 The alternative option is identical to the recommended option except that a TSM8 

alternative standard is not included for the liquid subcategories under this alternative, and 

no liquid units are assumed to switch to natural gas combustion as a compliance strategy. 

Instead, these liquid units are assumed to install controls to meet the emission limits. 

2.2 New Units 

The same two control options for existing units were used for new units. A total of 1,844 

total new boilers are projected to be constructed by 2015. Of these projected new boilers, 82 are 

projected to combust biomass. The methods and assumptions used in projecting new units is 

detailed in another memorandum.3 No new liquid-fired boilers were projected, and thus no 

impacts were estimated for new liquid-fired units switching to natural gas in order to 

demonstrate compliance. 

3.0 ESTIMATING COST IMPACTS 

The cost impacts analysis compares the baseline emissions for each unit to the 

corresponding proposed emission limit for the unit’s subcategory. A control device was applied 

to the unit if its baseline emissions exceeded their applicable proposed emission limit. A 

comparison of the overall capital and annualized costs of the promulgated option is presented in 
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Table 3-5. The detailed equations used to estimate the control, testing, monitoring, and work 

practice costs are discussed in another memorandum.2

 The following logic was used to apply 

control, testing, and monitoring costs to each boiler or process heater: 

3.1 Recommended Option 

The recommended option represents an option with a consolidated subcategory for fuelbased HAP from solid fuel units, where every unit must meet numerical emission limits and 

demonstrate compliance with performance stack testing, monitoring, and fuel analysis with a few 

exceptions. Units in the gas 1 subcategory, small units (less than 10 mmBtu/hr), and limited use 

units (less than 876 operating hours per year), qualify for work practices under Section 112(h) of 

the CAA and work practices for all pollutants consisting of an annual, biennial, or every 5 year 

tune-up replace the traditional compliance demonstrations associated with numeric emission 

limits. Other units qualify for a work practice for dioxin/furan which consists of an annual tuneup, but are also subject to numerical emission limits for four pollutants. 

There were late changes to the Hg, HCl, PM, and CO MACT floor emission limits for 

several subcategories. It was determined that the non-continental liquid units were not initially 

properly factored into the calculation of the Hg limit for liquid units, resulting in a revised Hg 

limit for existing liquid-fired boilers. Additionally, it was determined that five boilers in the 

liquid subcategory and one boiler in the pulverized coal subcategory were permanently 

shutdown. After removing the units from the MACT floor rankings, only the HCl emission limit 

for solid-fired boilers was affected. The revised limit was still more stringent than the calculated 

new source emission limit for the same subcategory, and thus the revised HCl limit was used for 

both existing and new solid-fired boilers. Although new unit projections are based on the counts 

of existing sources in each subcategory, the new unit projections were not changed based on the 

shutdown units. Further, minimum CO MACT floor emission levels were investigated in 

response to several stakeholder comments. For several subcategories, preliminary adjustments 

were made to the CO emission limit based on paired formaldehyde tests and these adjusted 

numbers were used in the estimation of cost and emission impacts. A summary of the 

development of minimum CO standards is provided in section 4.0 of the memorandum 

discussing the methods and procedures used to develop MACT floor emission limits.1 A revision 

to the representative detection level (RDL) for PM also affected several of the PM emission 

limits. 
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Appendices to this memorandum provide summaries of the cost, emission, and secondary 

impacts calculated both prior to and following the revisions to the aforementioned emission 

limits. The tabular summaries in the body of this memorandum, as well as the cost, emission, 

and secondary impacts sections of the preamble to the amended final rule, reflect the impacts 

analyses conducted following the revision of the limit. The appendices correlating to these 

analyses are labeled as the “Revised Recommended Option”. However, the results of the 

analyses conducted prior to the revision of the limits are reflected in the RIA update 

memorandum and the economic and health benefits section of the preamble to the amended final 

rule. The appendices correlating to these analyses are labeled as the “Old Recommended 

Option”. Table 3-1 provides a comparison of the old and revised MACT floor emission 

limitations discussed in this section. Further, the “Revised Recommended Option” is based on an 

inventory of 14,136 units and 1,700 facilities to account for the six shutdown boilers while the 

“Old Recommended Option” is based on an inventory of 14,142 units and 1,702 facilities. 

Table 3-1: Comparison of Emission Limits Used in Various Impacts Analyses

Pollutant Subcategory 

Emission Limit Used 

for RIA Memo and 

Economic and Health 

Benefits Sections of 

Preamble 

(“Old Recommended 

Option”) 

Emission Limit Used 

in Cost, Emission, and 

Secondary Impacts 

Sections of Preamble 

(“Revised 

Recommended 

Option”) 

Mercury (Hg) Existing – Liquid 4.9E-07 lb/MMBtu 2.0E-06 lb/MMBtu 

Hydrogen Chloride 

(HCl) Existing – Solid 0.021 lb/MMBtu 0.022 lb/MMBtu 

Hydrogen Chloride 

(HCl) New – Solid 0.021 lb/MMBtu 0.022 lb/MMBtu 

Carbon Monoxide (CO) Existing – Coal FB 49 ppm @ 3% O2 240 ppm @ 3% O2

Carbon Monoxide (CO) Existing – Coal 

Stoker/Other 160 ppm @ 3% O2 350 ppm @ 3% O2

Carbon Monoxide (CO) Existing – Heavy Liquid 12 ppm @ 3% O2 25 ppm @ 3% O2

Carbon Monoxide (CO) Existing – Light Liquid 6 ppm @ 3% O2 78 ppm @ 3% O2

Carbon Monoxide (CO) New – Coal FB 25 ppm @ 3% O2 240 ppm @ 3% O2

Carbon Monoxide (CO) New – Coal 

Stoker/Other 19 ppm @ 3% O2 350 ppm @ 3% O2

Carbon Monoxide (CO) Existing – Heavy Liquid 12 ppm @ 3% O2 25 ppm @ 3% O2

Carbon Monoxide (CO) Existing – Light Liquid 3 ppm @ 3% O2 78 ppm @ 3% O2

Particulate Matter (PM) Existing – Coal 3.9E-02 lb/MMBtu 4.0E-02 lb/MMBtu 

Particulate Matter (PM) Existing – Biomass 

Ducth Oven/Pile Burner 1.8E-02 lb/MMBtu 2.8E-02 lb/MMBtu 
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Particulate Matter (PM) 

Existing – 

Stoker/Sloped 

Grate/Other Designed to 

Burn Wet Biomass 

3.4E-02 lb/MMBtu 3.7E-02 lb/MMBtu 

Particulate Matter (PM) New – Coal 1.7E-03 lb/MMBtu 1.1E-03 lb/MMBtu 

Particulate Matter (PM) New – Biomass Ducth 

Oven/Pile Burner 3.1E-03 lb/MMBtu 3.2E-03 lb/MMBtu 

Particulate Matter (PM) New – Biomass FB 1.0E-02 lb/MMBtu 9.8E-03 lb/MMBtu 

Particulate Matter (PM) New – Biomass 

Suspension Burner 3.0E-02 lb/MMBtu 5.1E-02 lb/MMBtu 

Particulate Matter (PM) 

Existing – 

Stoker/Sloped 

Grate/Other Designed to 

Burn Wet Biomass 

3.0E-02 lb/MMBtu 3.7E-02 lb/MMBtu 

The preliminary adjustments to the minimum CO emission limits shown in Table 3-1 

were further refined after the impacts estimates were calculated. Thus, for certain subcategories, 

the CO emission limit used to calculate the impacts differ from the emission limit in the final 

amended rule. Table 3-2 provides a comparison of the CO emission limits presented in the 

recommended option for the impacts estimates and the limits in the final amended rule. 

The final amended rule CO emission limits for existing coal-fired fluidized bed, existing 

coal-fired stoker, and new coal-fired stoker units became more stringent than the CO limits used 

in the impacts analysis. Therefore, for these units, the cost and emission impacts presented in the 

recommended option are underestimated. For the remaining affected subcategories, the cost and 

emission impacts are conservative overestimates. 

Table 3-2: Comparison of CO Emission Limits Used in Impacts Analysis and Final Rule

Subcategory

CO Emission Limit Used in 

Cost, Emission, and Secondary 

Impacts Sections of Preamble 

(“Revised Recommended 

Option”) 

(ppm @ 3% O2)

CO Emission Limit in Final 

Rule 

(ppm @ 3% O2)

Existing – Coal FB 240 130 

Existing – Coal PC 62 130 

Existing – Coal Stoker/Other 350 160 

Existing – Heavy Liquid 25 130 

Existing – Light Liquid 78 130 

Existing – Non-Continental 

Liquid 32 130 

Existing – Process Gas 5 130 

New – Coal Stoker/Other 350 130 
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New – Heavy Liquid 25 130 

New – Light Liquid 78 130 

New – Process Gas 5 130 

A final late change to the analysis concerned baseline emissions for total hydrocarbons 

(THC). The estimation of THC baselines were revised based on revised methodology to account 

for instrumental measurement detection capabilities for instrumental emissions testing methods. 

The methods and procedures used to develop baseline emission factors are provided in another 

memorandum.6

 The methods and procedures used to account for instrumental measurement 

detection limitations for instrumental emission testing methods are also presented in another 

memorandum.23 The “Revised Recommended Option” appendices reflect the changes in the 

THC baseline emissions (which also had an impact on the estimated reductions), whereas the 

“Old Recommended Option” appendices do not. 

Control Cost Impacts 

Mercury Control 

 Fabric filters — a new fabric filter installation was expected to achieve most of the Hg 

emission limits in the proposal. Where baseline Hg emissions were found to be greater 

than the MACT floor, the cost of a fabric filter was estimated for an individual boiler or 

process heater, unless the unit already had a fabric filter installed. A new fabric filter was 

projected to be installed at 325 existing boilers and process heaters. This does not include 

the fabric filters installed in combination with dry injection to achieve HCl controls that 

are discussed below. 

 Activated carbon injection (ACI) — in the case of a unit with a fabric filter emitting Hg 

above the MACT floor emission limit, the costs to install activated carbon injection 

(ACI) technology on the boiler were estimated. ACI equipment was projected to be 

installed for 38 existing boilers and process heaters. 

 Wet scrubbers—one of the technologies selected for the cost analysis to reduce emissions 

of hydrogen chloride (HCl)—are also capable of achieving modest reductions in Hg. 

Literature suggests that these scrubbers can achieve a 10 percent reduction in Hg 

emissions. If a scrubber was being installed for HCl, and baseline Hg emissions were 

within 10 percent of the MACT floor, the wet scrubber was expected to achieve this level 

of emission reduction without installing a fabric filter. 
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 Slurry additive and halogen addition systems – if a boiler already has a selective catalytic 

reduction (SCR) and scrubber installed, additional Hg removal is possible. Hg reductions 

of 80% are achieved due to the co-benefit of the SCR and scrubber if these additive 

systems are installed in certain situations. If baseline Hg emissions were between 10 and 

80 percent of the MACT floor and a SCR and scrubber were both installed on the boiler, 

the cost for additive systems was estimated. No boilers met these criteria. 

Particulate Matter and Metallic HAP Control 

 When baseline particulate (PM) and TSM8 emissions both exceeded the respective 

emission limits for those pollutants, the cost of an ESP was estimated, unless a fabric 

filter had already been included in the cost analysis for Hg reduction. ESP technology 

was projected to be installed at 155 existing boilers and process heaters. 

 Wet scrubbers are also capable of achieving a modest reduction in PM and TSM. 

Literature suggests that these scrubbers can achieve an 85-percent reduction in PM 

emissions. If a scrubber was being installed for HCl, and baseline PM emissions were 

within 85 percent of the MACT floor for PM, the wet scrubber was expected to achieve 

this level of emission reduction without installing an ESP. 

Hydrogen Chloride Control 

 When HCl baseline emissions were greater than the MACT floor, the cost of adding a 

packed bed scrubber, increasing the sorbent rate on an existing scrubber, or installing a 

combination fabric filter and dry injection (DIFF) system was estimated. Scrubbers and 

DIFF were estimated to be able to attain similar levels of hydrogen chloride control. 

Based on input received during the public comment period, many wood product facilities 

are not permitted to discharge wastewater, thereby restricting the type of controls needed 

to reduce emissions of HCl and other acid gases. For this analysis, facilities in NAICS 

codes 321 (wood products manufacturing) and 322 (paper manufacturing) were assumed 

to not be able to install a packed scrubber due to the regulation of wastewater discharge 

from those industries. For the remaining units requiring control device installation for 

hydrogen chloride reduction, the less expensive control option between a packed scrubber 

and DIFF was assumed to be the control installed. If the boiler already reported having a 
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scrubber installed, a DIFF was not the selected control technology, and the baseline 

emissions still exceeded the floor, the incremental required HCl removal efficiency was 

calculated and the then the cost to increase the sorbent injection rate in the scrubber was 

estimated in the cost analysis. Wet scrubbers were estimated to be necessary to control 

HCl emissions at 678 existing boilers and process heaters. DIFF was identified to be 

necessary to control HCl emissions at 104 existing boilers and process heaters. 

Incremental sorbent injection was identified to be necessary to control HCl emissions at 8 

existing boilers and process heaters. 

 Since the fabric filter portion of a DIFF will achieve reductions in both HCl and Hg, the 

analysis first checked for whether a DIFF was necessary to achieve HCl reductions, and 

if so, this DIFF was assumed to achieve the MACT floor limits for both HCl and Hg. If a 

DIFF was not needed for HCl control, but a fabric filter was needed for mercury control, 

the costs of a fabric filter were estimated. 

Carbon Monoxide and Organic HAP Control 

 Organic HAP and carbon monoxide can be controlled by either improving the 

combustion efficiency of the unit, or installing an oxidation catalyst on the exhaust of a 

combustion unit. The control strategy necessary to meet the MACT floor emission limit 

will vary depending on the magnitude between the baseline emissions and the CO MACT 

floor. A step function was used to delineate what type of control strategy should be 

analyzed in the cost impacts analysis: 

o A boiler tune-up was estimated in the cost impacts analysis if the unit’s CO 

baseline emissions were less than or equal to 1.5 times the applicable numeric CO 

emission limit. We estimated that tune-ups could achieve a percent reduction from 

the unit’s baseline emissions. To determine an appropriate threshold level that 

tune-ups could achieve the limits to demonstrate annual compliance with the CO 

stack test in this proposal, we looked at best performing units for CO that reported 

paired CO CEMS emissions and boiler load data. Details of this analysis are 

discussed in a previous version of this memorandum.21 We settled on a modest 

threshold condition of assuming that a tune-up would meet the limit if the floor 

value was within 150% of the baseline emissions. Based on data provided by best 
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performing units, it is reasonable and a conservative estimate that this level of 

control can be achieved without capital installations. 

o If the unit’s baseline CO emissions were greater than 1.5 times but less than or 

equal to 2.5 times the applicable numeric CO emission limit, the cost of a 

replacement low-NOx burner was estimated to achieve the MACT floor emission 

limits. Since stokers, fuel cells, or fluidized bed units do not have replaceable 

burners, a linkageless boiler management system (LBMS) was the technology 

estimated to achieve the MACT floor when baseline CO emissions exceeded the 

floor in lieu of replacement low-NOx burners. A threshold of 2.5 is still less than 

the reported findings from best performing boilers in the coal and biomass 

subcategories that demonstrate wide fluctuations in CO emissions without any 

added CO controls, as discussed above. However, since we do not have similar 

data available for the liquid and process gas subcategories, we opted to select a 

conservatively low threshold to address some concerns received from public 

comments about underestimating the costs of CO control. 

o Finally, if the baseline CO emissions were greater than 2.5 times the applicable 

CO emission limit, the cost impacts analysis estimated that a CO oxidation 

catalyst would be required to meet MACT floor limits. 

Work Practice Costs 

 All boilers and process heaters are subject to a work practice standard. Large units 

(greater than or equal to 10 mmBtu per hour) are required to conduct an annual tune-up. 

All liquid-fired units that were identified as capable to switching to natural gas 

consumption are large units, and are thus subject to an annual tune-up. All small boilers 

(less than 10 mmBtu per hour) combusting any fuel, and limited use boilers (less than 

876 hours of operation per year) are required to conduct a biennial boiler tune-up. Very 

small units designed to burn gaseous fuels or light liquid fuels (less than 5 mmBtu per 

hour) are required to conduct a tune-up every 5 years. The cost to conduct an annual 

tune-up is based on the cost estimate provided in a report by the Industrial Extension 

Service16. This report indicated that the initial set-up for boiler tune-up was $3,000 to 

$7,000 per boiler; thereafter, annual tuning costs $1,000 per boiler. An average of $5,000 

per boiler in initial set-up costs was annualized over 5 years at a 7 percent rate and added 
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to the subsequent year tune-up costs. Although the proposal allows a biennial or every 5-

year tune-up in some circumstances the cost impacts analysis show the tune-up costs on 

an annual basis since these represent the first year costs when the rule is implemented. 

The resultant annualized cost for an annual tune-up is $2,875 per boiler, as shown in 

Equation 1. 

Annual Tune-up Cost ($2008) = {[C$2004 * (X2008 / X2004) * i * (1+i)

y

] / [(1+i)

y

 – 1)]} + 

[Z$2004 * (X2008 / X2004)] = $2,875 (Equation 1)

Where: 

C$2004 = Average set-up cost, $5,000 (from 2004) 

X2008 = 2008 cost index, 575.4 

X2004 = 2004 cost index, 442.2 

i = interest rate, 7% 

y = length of annuity, 5 years 

Z$2004 = annual tuning cost, $1,000 (from 2004) 

 All existing facilities are expected to conduct a one-time energy audit. An annual cost of 

$854 per audit was used for commercial or institutional facilities and $18,292 per audit 

was used for industrial facilities, and these costs are the same as the estimates included in 

the March 2011 final rule and the December 2011 proposed reconsideration of the rule.2

For the cost impacts analysis, 1,702 facilities are expected to conduct an audit under the 

“Old Recommended Option” discussed in Section 3.1, 204 facilities are commercial or 

institutional and 1,498 facilities are industrial. There are 1,700 facilities expected to 

conduct an audit under the “Revised Recommended Option” discussed in Section 3.1. 

Testing and Monitoring Cost Impacts

Testing and monitoring requirements varied depending on the equipment installed on the 

unit to control emissions, the design capacity of the unit, and the fuel category the unit was 

assigned to. 

Testing Costs 

 All boilers and process heaters designed to burn solid and gaseous fuels were expected to 

conduct an annual compliance test for PM, HCl, Hg, and CO. The cost to conduct stack tests for 
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these four pollutants was estimated to be $28,000 per year for boilers combusting solid or other 

gaseous fuels. Based on comments received about testing under worst-case conditions, many 

solid fuel boilers which fire multiple fuel streams or types of fuel are expected to conduct 

repeated testing for mercury and HCl at a cost of $18,000 per year. 

 Boilers and process heaters designed to burn liquid fuels were expected to conduct an 

annual compliance test for PM and CO. In lieu of a stack test boilers designed to burn liquid 

fuels were expected to conduct fuel analysis, or report fuel analyses received from a fuel 

supplier, for chlorine and Hg. Conducting stack tests for PM and CO was estimated to be 

$11,000 per year, and fuel analysis for chlorine and Hg was estimated at $400 per month. 

Although other fuels are eligible to comply with the proposal through fuel analysis in lieu of 

stack testing, this cost estimate conservatively assumed that only units designed to fire liquid 

fuels would use this compliance alternative. The methods and data sources used to estimate 

testing and monitoring costs are discussed in other memoranda.2 

 The proposal includes a provision for gaseous fuels other than natural gas and refinery 

gas to demonstrate that they meet the specifications outlined in the rule for mercury. We 

reviewed the database for facilities that had boilers with heat input capacities of at least 10 

mmBtu/hr that are firing gaseous fuels other than natural gas or refinery gas, and we estimated 

that these 385 combustion units would need to conduct monthly fuel analysis, at a cost of $200 

per month, or $2,400 per year. The methods and costs associated with demonstrating that the gas 

meets the specifications for mercury are discussed in another memorandum.2 In the March 2011 

final rule cost estimates, we had estimated gas specification costs at one per month, per facility. 

However, because certain gas streams are not used in all combustion units, and different units 

may combust different blends of gases, we increased the cost to one specification per month, per 

unit in order to be conservative. 

Monitoring Costs 

Various monitor configurations were installed based on the size of the unit and the 

pollution control devices expected to be installed to achieve the MACT floor emission limits. For 

units expected to install packed bed wet scrubbers, an annualized cost of $5,600 for a scrubber 

parametric monitor was included in the cost analysis. If a unit was expected to install DIFF, the 

cost to monitor sorbent injection rate and add a bag leak detection monitor was included in the 

analysis, based on the unit’s hours of operation. For units expected to install a fabric filter, an 
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annualized cost of $9,700 for a bag leak detection monitor was included in the cost analysis. If a 

unit was expected to install ACI, the cost to monitor the carbon injection rate was included in the 

analysis, based on the unit’s hours of operation. For units that did not install a PM CPMS and did 

not install a scrubber to meet HCl limits, an annualized cost of $14,660 for an opacity monitor 

was included in the cost analysis. The cost analysis includes the cost of a PM CPMS for units 

with an average heat input rate of 250 mmBtu/hr or more from coal, fossil solid or liquid fuel. 

Oxygen monitors were required for all boilers and process heaters subject to CO emission limits; 

these monitors were assumed to be extractive type monitors with an annualized cost of $1,436. 

Although several units are expected to have O2 monitors installed on the units for other reasons, 

such as to monitor combustion efficiency, since the number of units with monitors installed and 

calibrated is unknown, this analysis applies the cost of an O2 monitor to all units subject to a CO 

emission limit. No PM CPMS or opacity monitors were assumed for boilers and process heaters 

designed to burn gaseous fuels. 

Fuel Savings Impacts 

 This cost analysis includes an estimated energy savings of one percent for every existing 

unit that is expected to install controls to improve combustion, or conduct an annual tune-up or 

energy audit. Further, documents from the Sustainable Energy Authority of Ireland have charted 

efficiency gains as a function of boiler fuel type and time elapsed since the previous tune-up.8

Many best practices are considered pollution prevention because they reduce the amount of fuel 

combusted which results in a corresponding reduction in emissions from the fuel combustion. 

Further boiler tune-ups have been shown to improve the efficiency of a boiler between 1 and 5 

percent, depending on the age of the unit and the time lapse since the previous tune-up10-15, 17-19. 

Other combustion controls such as upgrading burners and installation of an LBMS are also 

expected to improve the efficiency of the unit, thus reducing fuel consumption. This cost analysis 

assumes an annual fuel savings of 1 percent. The energy savings are estimated using Equation 2: 

Annual Fuel Savings (mmBtu/yr) = DC * CF * Ophours* EG (Equation 2)

Where: 

DC = unit design capacity (mmBtu/hr) 

CF = capacity factor, 90% of design capacity 

Ophours = annual operating hours reported in 2008 survey (hours/year) 

EG = Efficiency gain, estimated to be 1% 
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After the fuel savings for each boiler and process heater was calculated, the industrial and 

commercial prices for coal, #2 distillate fuel oil, #6 residual fuel oil, and natural gas were 

obtained from both the 2008 and 2012 EIA in order to get a potential range of fuel savings.5, 22

This is a change since the proposed reconsideration of the rule, for which the cost analysis 

utilized fuel prices from the 2008 EIA only.5

 The EIA data reported fuel prices as $/ton for coal, 

$/thousand cubic feet for natural gas, and cents per gallon for fuel oil. A comparison of the 2008 

and 2012 EIA fuel prices is provided in Table 3-3 below. The 2008 EIA data are presented in 

year 2008$ while the data for the 2012 EIA are presented in 2012$. 

Table 3-3: Comparison of Fuel Prices from 2008 and 2012 EIA 

Fuel Type 

Industrial Costs ($/MMBtu) Commercial/Institutional Costs 

($/MMBtu) 

2008 EIA 2012 EIA 2008 EIA 2012 EIA 

Coal 2.43 3.06 2.43 3.06 

Natural Gas 9.32 3.06 11.66 9.09 

Distillate Oil 23.23 18.7 22.66 18.69 

Residual Oil 12.96 14.06 12.96 12.03 

The revised EIA 2012 data highlight the trends towards substantially lower natural gas 

fuel prices since previous iterations of this impacts analysis. This new data results in lower fuel 

savings estimates. The higher heating values were obtained from Table C-1 of the EPA 

Mandatory Reporting Rule (40 CFR part 98 subpart C) and the higher heating values were used 

to convert the fuel prices to a standard unit of measure, $ per mmBtu. Using the NAICS code 

reported by each facility and the fuel category assigned to each combustion unit, the appropriate 

fuel price was multiplied by the calculated fuel savings. Table 3-4 below shows the distribution 

of reported NAICS codes considered as industrial versus commercial in terms of fuel pricing. 

Table 3-4: Summary of NAICS Code Distribution by Sector 

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, 813, 921, & 928 
15 

This cost analysis only estimates the fuel savings from units in the coal, liquid and natural 

gas fuel categories. A fuel savings range was not estimated for units in the biomass or other 

process gas fuel categories since the price of these fuels is variable, and often biomass is an onsite industrial byproduct instead of a purchased fuel. 

Fuel Switching Impacts 

No costs were estimated for liquid units assumed to switch to natural gas combustion. 

The units identified as candidates for fuel switching reported the ability to combust both liquid 

fuels and natural gas, and thus unit’s fuel handling and firing equipment were not assumed to 

need modification. The only changes required to these units would be to cease the purchase of 

liquid fuels and replace it with the purchase of natural gas. Additionally, as shown in the 2008 

and 2012 EIA, natural gas prices are historically lower than both distillate and residual oil prices 

on a dollar per unit of heat input basis.5, 22

3.2 Alternative Option 

The alternative option includes control device and testing/monitoring cost estimation 

logic identical to the Recommended Option outlined above, except that the alternative TSM8 

emission limit option is removed from consideration for liquid units, and no liquid units are 

assumed to switch to natural gas combustion in lieu of demonstrating compliance with emission 

limits. All other aspects of the options are identical. As a result of this modified option and its 

computed MACT floors, the number of units estimated to install controls to meet the limits were 

adjusted as follows: 

 A new fabric filter was estimated to be installed at 555 existing boilers and process 

heaters to control Hg emissions. This does not include the fabric filters installed in 

combination with dry injection to achieve HCl control. A new fabric filter is required to 

be installed on an additional 230 boilers and process heaters under this option when 

compared to the recommended option. 

 ACI equipment was estimated to be installed at 40 existing boilers and process heaters for 

controlling Hg. ACI equipment is required to be installed on an additional two boilers 

and process heaters compared to the recommended option. 

 ESP technology was estimated to be installed at 155 existing boilers and process heaters 

to control PM. ESP technology is required to be installed on the same number of boilers 
16 

and process heaters compared to the recommended option. 

 Wet scrubbers were estimated to be necessary to control HCl emissions at 902 existing 

boilers and process heaters. A new wet scrubber is required to be installed on an 

additional 224 boilers and process heaters under this option when compared to the 

recommended option. 

 DIFF was identified to be necessary to control HCl emissions at 129 existing boilers and 

process heaters. DIFF is estimated to be installed on an additional 25 boilers and process 

heaters under this option when compared to the recommended option. 

 Incremental sorbent injection was identified to be necessary to control HCl emissions at 

12 existing boilers and process heaters. Incremental sorbent injection is estimated to be 

installed on the same number of boilers and process heaters under this option compared 

to the recommended option. 

3.3 New Unit Options 

The recommended option for new units follows similar logic for estimating control costs 

as the recommended option for existing units outlined above with two exceptions: (1) Since new 

boilers are not subject to energy assessment requirements under the proposed rule, no costs for 

these audits have been included; and (2) since these boilers are new, fuel savings from these 

boilers was not estimated since the savings are expected to be minimal given that a new boiler 

will operating optimally in the first year they are installed regardless of any of the requirements 

of this rule. The new unit analysis also projects new gaseous fuels, but based on the EIA data 

used for the new unit projections all of these new boilers are estimated to be natural gas so no 

cost for a gas specification is included in the new unit analysis. Table 3-5 summarizes the costs 

for the recommended option for new sources. 

The alternative option for new units follows similar logic as the alternative option for 

existing units. Similar to the assumptions noted earlier in Section 3.3, estimated fuel savings and 

costs for energy audits were not applied to new units. However, since no new liquid units are 

projected, the results of both the promulgated and alternative options are the same for both 

options. 
17 

3.4 Summary of Cost Impacts 

 The recommended option is the promulgated option for existing and new boilers and 

process heaters. Tables 3-5 and 3-6 summarize the costs of the promulgated for new and existing 

units. Appendix A of this memorandum provides a detailed summary of the promulgated option 

for existing and new sources costs according to unit size, subcategory, and individual control 

device costs. Note that Appendix A-1a represents the “Old Recommended Option” that was used 

in the RIA, while Appendix A-1b represents the “Revised Recommended Option” after 

accounting for later data submittals and edits to the analysis. 

Table 3-5: Summary of Costs of Proposed Promulgated Options 

Costs shown in $106

 (2008) with capital recovery estimated at 7% 

Type of 

Unit Option 

Number 

of Units TAC 

Minimum 

TAC 

considering 

fuel 

savings 

Maximum 

TAC 

considering 

fuel 

savings 

Testing & 

Monitoring 

TAC 

Control 

TAC 

Control 

TCI 

New Recommended 1,844 $104 N/A $104 $5.6 $98.5 $393 

Existing Recommended 

(Old) 

14,142 $1,702 $1,355 $1,558 $89.4 $1,612 $5,028 

Existing Recommended 

(Revised) 

14,136 $1,661 $1,247 $1,489 $88.9 $1,544 $4,877 

Table 3-6: Summary of Total Annual Costs by Control Type for Existing Units under Promulgated Option 

Costs shown in $106

 (2008) with capital recovery estimated at 7% 

Option 

Number 

of 

Boilers 

Fabric 

Filter ESP 

Wet 

Scrubber DIFF 

Increased 

Caustic 

Rate 

Combustion 

Controls 

and 

Oxidation 

Catalysts 

Activated 

Carbon 

Injection 

Work 

Practices 

(Tuneup) Energy 

Audit 

Recommended 

(Old) 14,142 $327 $54.6 $667 $337 $2 $168 $15.8 $40.7 $27.6 

Recommended 

(Revised) 14,136 $355 $54.6 $643 $337 $2 $98.9 $13.5 $40.6 $27.5 

4.0 METHODOLOGY FOR ESTIMATING EMISSION 

REDUCTIONS 

 

This section discusses the methodology used to estimate emission reductions from boilers 

and process heaters at both existing and new facilities and it presents a summary of the results 

for the recommended regulatory options. 

The emission reductions analysis for existing combustion units was done for each boiler 

and process heater in the major source inventory. There are a total of 14,142 boilers and process 
18 

heaters at major sources that reported data in the 2008 questionnaire (ICR No. 2286.01) or 

subsequent requests for or submissions of data (or 14,136 units in the revised inventory 

discussed in Section 3.1 of this memoranda). Each combustion unit was assigned a unit-specific 

or average baseline emission factor, depending on the availability of emission data reported for 

the unit. A detailed discussion of the procedures and results of the baseline emissions analysis is 

presented in another memorandum.6

4.1 Emission Reductions for Recommended Option 

Emission reductions followed three steps: First, emission reductions were estimated for 

units subject to emission limits for PM (or TSM8), HCl, Hg, and CO. These emission reductions 

were calculated on a ton per year basis by subtracting the baseline emissions assigned to each 

unit from the emission limits corresponding to each unit’s subcategory. A detailed discussion of 

the procedures and results of the MACT floor analysis is presented in another memorandum.1

 A 

percent reduction was calculated for CO. It was assumed that each combustion unit would 

achieve an identical percent reduction from baseline emissions for THC and VOC as was 

achieved for CO. A percent reduction was also calculated for HCl. It was assumed that each 

combustion unit would achieve an identical percent reduction from baseline emissions for HF as 

was achieved for HCl. A combustion unit is assumed to install a scrubber or DIFF for HCl 

control if it is not currently meeting the HCl floor limit, and if it doesn’t already have a scrubber 

installed. For units required to install a scrubber or DIFF, it was assumed that the control will 

achieve a reduction from baseline for SO2 equivalent to the reduction in HCl. 

This analysis assumed that each combustion unit would comply with either the PM or 

TSM8 numeric emission limit that required the lowest percent reduction from the respective 

baseline emissions. The minimum percent reduction required for PM or TSM8 was chosen, and 

baselines for both PM and TSM8 were reduced by that same percentage. The reductions in 

individual non-Hg metallic HAP (antimony, arsenic, beryllium, cadmium, chromium, cobalt, 

lead, manganese, nickel, and selenium) were based on the same pollutant removal efficiencies 

estimated for PM or TSM8 above. The reductions for each of the individual 10 metallic HAP 

were summed in order to get reductions for TSM10. PM2.5 emissions were assumed to be a 

fraction of total filterable PM emissions based on fuel and control device configuration installed 
19 

on the unit. The methods used to derive the contribution of PM2.5 to overall filterable PM are 

presented in other memoranda.6

 To calculate emission reductions for PM2.5, the emission 

reductions for PM were multiplied by the applicable PM2.5 fraction. 

Although baseline emissions of dioxin/furans are shown in Appendix B, this estimated 

baseline is based on data that include detection limit-based values, which overestimates the 

amount of dioxin/furans by an unknown amount since most of the data were reported to be 

measured below detection levels and the vast majority of the data that were above the detection 

limit were still lower than the amount that the EPA has determined can be accurately measured. 

No reductions were estimated for dioxins/furans because any estimates would be highly 

uncertain. 

To convert emission reductions from an emission rate on a heat input basis to an annual 

emission rate, Equation 3 was used: 

Annual Emission Rate (tpy) = ERHI * 0.0005 * Ophours (Equation 3)

Where:

ERHI = emission rate (lb/mmBtu) 

0.0005 = conversion factor, lbs per ton 

Ophours = annual operating hours reported in 2008 survey (hours/year) 

To convert emission reductions from a concentration basis to an annual emission rate, 

Equations 4 and 5 were used: 

Annual Emission Rate (tpy) = ERC * 0.000001 * QS * 60 * Ophours * MW * 0.0026 * 

0.0005 * (20.946 – O2) / (20.946 – Std O2) (Equation 4)

Where:

ERC = emission concentration (ppm @ 3% O2) 

0.000001 = conversion factor, ppm to parts 

QS = exhaust flowrate (dscfm) 

60 = conversion factor, minutes to hours 

Ophours = annual operating hours reported in 2008 survey (hours/year) 

MW = molecular weight of pollutant, in lb per lb-mole 

0.0026 = conversion factor, lb-mole per dry standard cubic foot of gas 

0.0005 = conversion factor, lb per ton 

20.946 = percentage of oxygen in ambient air 

O2 = percentage of oxygen assumed in exhaust gas 

Std. O2 = 3 percent oxygen in standardized emission concentration. 
20 

Annual Emission Rate (tpy) = ERC * 0.0283 * QS * 60 * Ophours * 0.000000001 * 0.0022 

* 0.0005 * (20.946 – O2) / (20.946 – Std O2) (Equation 5) 

Where:

ERC = emission concentration (ng/dscm @ 7% O2) 

0.0283 = conversion factor, dry standard cubic meter per dry std. cubic foot 

QS = exhaust flowrate (dscfm) 

60 = conversion factor, minutes per hour 

Ophours = annual operating hours reported in 2008 survey (hours/year) 

0.000000001 = conversion factor, ng to g 

0.0022 = conversion factor, g per lb 

0.0005 = conversion factor, lb per ton 

20.946 = percentage of oxygen in ambient air 

O2 = percentage of oxygen assumed in exhaust gas 

Std O2 = 7 percent oxygen in standardized emission concentration for promulgated rule. 

Converting concentrations to an annual emission rate required an oxygen concentration 

and exhaust flowrate estimated for each specific fuel type. The development of these 

assumptions and estimates is presented in other memoranda.2 All conversions required the 

annual operating hours for each combustion unit reported in the 2008 survey or in subsequent 

data submittals. If no operating hours were reported, the unit was assumed to operate for 8,400 

hours per year (two weeks of downtime). 

The second step was to estimate emission reductions based on a one percent gain in 

efficiency expected from the initial tune-up work practice standard required for all units. 

Efficiency gains reduce fuel use, and in turn, emissions of hazardous air pollutants. A one 

percent reduction in all types of emissions was estimated by multiplying the baseline emissions 

for each unit by a factor of 0.01. All units, regardless of size or fuel, must conduct an initial tuneup. A one percent gain in efficiency is thus expected for all types of units based on this tune-up 

requirement. 

The third and final step consisted of taking the maximum emission reduction value from 

the two steps outlined above. Even if a unit’s reported baseline emissions were below its 

respective emission limits, the unit was still expected to achieve nominal emission reductions of 

one percent through combustion efficiency and fuel savings resulting from the tune-up work 

practice. However, if additional emission reductions were needed in order to meet the emission 

limits the reductions resulting from improved efficiency were expected to be factored into the 

overall engineering strategy and control device design to achieve each emission limit. This 
21 

approach ensures that every unit in the inventory achieves at least a 1 percent reduction in 

emissions. 

Reductions for Liquid Units Switching to Natural Gas Combustion 

For the continental liquid units identified to have the capability to switch to natural gas 

combustion, emission reductions were calculated by subtracting the current liquid baseline 

emissions from the expected emissions when firing natural gas. For the fuel-based pollutants 

(i.e., Hg, PM, HCl, HF, SO2, PM2.5, and metallic HAP) it was assumed that the same level of 

control currently in use for the liquid unit would be retained for the natural gas combustion. As 

an example, if a liquid unit with a fabric filter was expected to convert to natural gas combustion, 

emission reductions were calculated by subtracting the liquid baseline emissions from the 

expected natural gas emissions for a fabric filter level of control for the respective pollutant. For 

the organic combustor-based pollutants (i.e., CO, THC, and VOC) a similar comparison was 

done, except using the reported baseline presence or absence of low NOx burners in lieu of the 

level of control. As an example, if a liquid unit with low NOx burners was expected to convert to 

natural gas combustion, emission reductions were calculated by subtracting the liquid baseline 

emissions from the expected natural gas emissions for units with low NOx burners for the 

respective pollutant. 

Based on the available data, emission factors for CO, THC, VOC, and HF from natural 

gas combustion were higher than the corresponding liquid baseline emissions, and emissions for 

these pollutants increased after assuming that the 258 large, routine-use liquid units would switch 

to natural gas combustion. Natural gas emissions for the remaining pollutants were lower than 

the corresponding liquid baseline emissions, and the natural gas switch provided additional 

emissions reductions. Table 4-1 compares the emission reductions expected from liquid units 

both with and without the assumption that the 258 units would switch to natural gas combustion. 

Table 4-1: Comparison of Emission Reductions (tons per year) from Liquid Units With and Without Units 

Switching to Natural Gas Combustion 

Subcategory Hg PM HCl CO THC VOC HF SO2 PM2.5 Metals 

No Liquid 

Units 

Switching to 

Natural Gas 

1.13 5,562 2,155 12,448 3,404 1,954 71 89,152 2,346 1,633 
22 

258 Liquid 

Units 

Switching to 

Natural Gas 

1.14 9,522 2,160 8,632 2,940 1,688 (538) 97,520 4,800 2,325 

Incremental 

Emissions 

Reductions 

0.01 3,960 5 (3,816) (464) (266) (609) 8,368 2,454 692 

Emission Reduction Range for Mercury

Given that some survey respondents reported non-detect fractions of mercury differently 

than others, a second method of estimating emission reductions for mercury was used in order to 

establish a range of possible reductions for mercury. For each subcategory, the average (mean) 

emissions of the top performing units were calculated and compared to three times the 

representative detection level (3x RDL) for the same subcategory; the higher value of the two 

was determined to be the lower bound of emissions for each subcategory. Details and methods 

used to compute the mean of the top performing units and each 3x RDL value can be found in 

other memoranda.4,20 Table 4-2 shows the computed emission limits, mean of the top performers, 

and the 3x RDL value for each subcategory. For the solid and process gas subcategories, the 

average emissions or 3x RDL value was lower than the actual numeric emission limit. For 

liquids, the 3x RDL was the basis of the emission limit, and thus the values are equal. 

Table 4-2: Comparison of Hg Emission Limits, Top Performer Averages (Mean), and 3x RDL by 

Subcategory 

Fuel Subcategory Emission Limit 

(lb/MMBtu) 

Mean Emissions of 

Top Performers 

(lb/MMBtu) 

3x RDL (lb/MMBtu) 

Solid 5.7E-06 4.1E-07 7.2E-07 

Liquid 4.7E-07 3.7E-07 4.7E-07 

Process Gas 7.9E-06 6.2E-06 4.4E-07 

As an added constraint to the lower bound on estimated emission levels that could 

reasonably be achieved, it was assumed that units expected to install air pollution control devices 

for compliance with a numeric emission limit for Hg, or units expected to install control devices 

to meet PM (or TSM), or HCl limits that have a co-benefit of reducing mercury, would achieve a 

minimum amount of reductions based on the type of control installed. For units installing a fabric 
23 

filter, ACI, or DIFF for Hg or HCl control, the representative control efficiency was assumed to 

be 70 percent. For units installing an ESP for PM, it was assumed that the maximum control 

efficiency for Hg removal would be 25 percent. For units installing a wet scrubber, or units with 

a pre-existing scrubber that are required to incrementally increase the sorbent injection rate, it 

was assumed that the maximum control efficiency for Hg removal would be 10 percent. These 

selected percentages are within the ranges of pollutant removal efficiencies discussed in another 

memorandum.6

Emission reductions were then calculated by determining the percent reduction needed to 

reduce baseline emissions to the level of the average emissions of the top performers (or 3x 

RDL, whichever was higher). This value was compared with the estimated removal efficiency of 

the control device expected to be installed on the unit. The baseline emissions were then 

multiplied by the minimum of these two percentages. However, if the percent reduction required 

to comply with the actual numeric emission limit was higher than this minimum value, then the 

percent reduction needed was defaulted to the percentage needed to meet the floor since all units 

will be required to meet their respective numeric emission limit. This alternative method for 

estimating mercury emission reductions was used to estimate the upper end of the range for 

mercury reductions.

4.2 Emission Reductions for Alternative Option 

The same calculations discussed for estimating emission reductions for the recommended 

option were applied to all units except that the alternative numeric TSM8 emission limits for 

liquid units were removed, and that no liquid units were assumed to switch to natural gas 

combustion. It was assumed that each combustion unit would achieve an identical percent 

reduction in TSM emissions as was achieved for compliance with the numeric PM emission 

limits. The remainder of the above methodology and calculations for the recommended option 

were performed for all other pollutants.

4.3 Emission Reductions from New Boilers and Process Heaters 

Based on industrial and commercial fuel consumption projections from the Department 

of Energy’s 2011 Annual Energy Outlook, there are 1,844 new boilers and process heaters 
24 

expected to come on-line by 2015.7

 A discussion of the methodology used to project new boilers 

and process heaters is discussed in another memorandum.3 

The New Source Performance Standards for Industrial, Commercial and Institutional 

Boilers (40 CFR part 60, subparts Db, Dc) (NSPS), was reviewed to identify the expected 

baseline level of control for projected new units. It was determined that new boilers and process 

heaters larger than 30 mmBtu/hr and combusting biomass would install an ESP. This technology 

selection is based on the analysis used to establish the PM NSPS limit for biomass boilers. New 

coal units larger than 75 mmBtu/hr would have a fabric filter and wet scrubber installed, while 

new coal units between 30 and 75 mmBtu/hr would only have a fabric filter installed and would 

meet the SO2 limits in the NSPS by using coals with low sulfur content. New units larger than 30 

mmBtu/hr and combusting liquid fuel would have a fabric filter installed. All new units less than 

30 mmBtu/hr would have no add-on controls and liquid fuels were expected to meet the NSPS 

SO2 limits using low sulfur fuel oils. Gas-fired units of all sizes were not expected to install 

controls to meet any of the NSPS limits. For this impacts analysis, it was assumed that all new 

solid fuel units would be stokers, since stoker boilers are the most common type of solid fuel 

boilers and all new units would have NOx control installed as a baseline control, regardless of 

fuel. 

After an appropriate baseline level of control was determined for each model unit, an 

average baseline emission factor calculated for existing units within the same fuel category and 

having the same level of control was assigned to each model boiler. The NSPS specifies PM and 

SO2 limits for new solid- and liquid-fired combustion units based on heat input. It was assumed 

that all new solid and liquid units would be constructed to meet these limits, so they were used as 

baseline emission values where applicable. The baseline emissions for each unit were subtracted 

from the new source MACT floor emission limit corresponding to each unit’s subcategory. 

Similar to the methods discussed in Section 4.1 of this memorandum, the emission 

reductions for new units were calculated by subtracting the baseline emissions assigned to each 

unit from the MACT floor emission limits corresponding to each unit’s subcategory, except for 

units not subject to numeric emission limits. Pollutants which received reductions in emissions 

based on the percent reduction in a regulated pollutant for existing sources were calculated 

identically for reductions from new sources. However, new sources are not expected to achieve 

substantial fuel savings as a result of a tune-up, since the unit is expected to be installed tuned 

and ready to operate efficiently, the one percent reduction in emissions for all pollutants 
25 

expected from the efficiency gain of the boiler tune-up was not estimated. The method for 

estimating an upper range of Hg reductions used for existing sources, which involved comparing 

baseline emissions to the average emissions of the top performers, was also calculated for new 

sources. However, this did not result in a range of Hg emission reductions for new sources. New 

source baseline emissions of Hg at each of the model units were below the mean of the top 

performing unit in each subcategory except for the industrial biomass units. However, for this 

subcategory, since the MACT floor was based on the 3x RDL, no further reductions could be 

estimated. Summaries of the estimated emission reductions from existing and new units for both 

the recommended and alternative options are located in Appendix B. Note that Appendix B-1a 

represents the “Old Recommended Option” that was used in the RIA, while Appendix B-1b 

represents the “Revised Recommended Option” after accounting for later data submittals and 

edits to the analysis. 

5.0 METHODOLOGY FOR ESTIMATING SECONDARY 

IMPACTS 

Secondary impacts include the solid waste, water, wastewater, electricity required to 

operate air pollution control devices and the resultant greenhouse gas emissions, as well as the 

additional energy savings resulting from improved combustion controls or work practices 

required by the NESHAP. This section documents the inputs and equations used to estimate 

these secondary impacts, and it summarizes the impacts at new and existing units under the 

recommended option. Table 5-1 summarizes the cost, emission, and secondary impacts of this 

promulgated NESHAP. Appendices C-1 and C-2 present a detailed breakdown of the secondary 

waste, water, and energy impacts from each subcategory of existing and new boilers and process 

heaters, respectively. 

Table 5-1: Summary of Secondary Impacts 

Impact New Units 

(recommended 

option) 

Existing Units 

(Old Recommended 

option)

Existing Units 

(Revised 

Recommended 

option)

Water (gal/yr) 0 1.2 billion 1.2 billion 

Wastewater (gal/yr) 0 432 million 426 million 
26 

Solid Waste (tons/yr) 1,700 238,600 238,000 

Purchased Electricity (kWhr/yr) 120 million 1.3 billion 1.3 billion 

CO2 Emissions from 

Purchased Electricity 79,700 896,800 859,200 

Energy Savings* (trillion 

Btu/yr) 0 46.8 48.5 

* Energy savings is calculated for units in the coal, liquid and gas (1) subcategories. 

The secondary impacts were calculated using algorithms and assumptions described in 

another memorandum.2

 These algorithms and assumptions were applied to the existing boiler 

and process heaters, where the baseline emissions for each unit exceeded the promulgated 

MACT floor emission limit except for small units (less than 10 mmBtu/hr), limited use units, and 

units firing natural gas, refinery gas, or other on-spec gaseous fuels. A one percent energy 

savings was calculated for all existing units except those firing biomass or process gas, those that 

are otherwise already meeting the appropriate numeric emission limitation for CO, or those that 

require the installation of an oxidation catalyst for CO control. For new units, the algorithms and 

assumptions were applied to model units representing units expected to come online between 

2012 and 2015, when the baseline emissions for each model exceeded the promulgated MACT 

floor emission limit for new units except for small units and units firing natural gas, refinery gas, 

or other on-spec gaseous fuels. Similar to existing units these small and gas-fired units are not 

required to meet a numerical emission limit, and therefore not expected to incur any secondary 

waste, water, or electricity impacts from these controls. A one percent energy savings from small 

units and units burning natural gas, refinery gas, or other on-spec gaseous fuels are included in 

the energy savings estimate in Table 5-1 since these units are expected to conduct a tune-up. The 

methodology used to assign baseline emission factors to new and existing units are discussed in 

another memorandum.6 

5.1 Wastewater and Water Impacts 

The water required to create a slurry in the packed scrubber and the wastewater generated 

by the effluent of a packed bed scrubber were calculated for every unit expected to install a 

scrubber to meet the HCl limits in the proposal. Both the water and wastewater calculations 

required the use of several constants and variables. The constants including the density of gas, 
27 

moles of salt needed per mole of hydrogen chloride in the exhaust gas, the molecular weight of 

the salt used, the fraction of the waste stream treated, operating hours per year and the molecular 

weight of the gas. The data sources for these constants are provided in another memorandum.2

The variables used to estimate the quantity of water required and wastewater generated were 

calculated based on characteristics reported for each existing unit in the 2008 survey and 

subsequent data gathering activities and for the characteristics assigned to each new model unit. 

The variables included: exhaust flow rate from the combustion unit to the control device in 

actual cubic feet per minute, the inlet loading of hydrogen chloride to the control device (mole 

fraction), and the efficiency of the control device in removing hydrogen chloride from the 

exhaust gas (percent reduction). The calculations used to estimate each variable are provided in 

another memorandum.2

 The total national water and wastewater amounts in Table 5-1 were 

determined by adding the per unit water and wastewater estimates for all new and existing units, 

respectively. 

5.2 Solid Waste Impacts 

Solid waste is generated from collecting dust and fly ash in fabric filters or ESP control 

devices, spent carbon associated with ACI, or spent caustic from increasing the caustic injection 

rate. Solid waste impacts were estimated for every unit expected to install a fabric filter for 

mercury control or a DIFF for HCl control, ACI for mercury emission limits, or install an ESP to 

meet PM emission limits. The total national solid waste amounts in Table 5-1 were determined 

by adding the per unit solid waste estimates for all new and existing units, respectively. To 

estimate the solid waste contribution from each of these control devices, the variables were 

calculated based on characteristics reported for each existing unit in the 2008 survey and 

subsequent data gathering activities and for the characteristics assigned to each new model unit. 

The calculations used to estimate each variable and the quantity of solid waste generated are 

provided in another memorandum.2

 

The solid waste (dust, fly ash) generated by the use of an electrostatic precipitator was 

calculated when an electrostatic precipitator was determined to be necessary to meet the 

NESHAP emission limits for PM. Estimates of the solid waste collected in an ESP were based 

on several variables, including: Exhaust flow rate from the combustion unit to the control device 

(acfm); the inlet loading of particulate matter to the control device (gr/acfm); operating hours 
28 

(hr/year) and the efficiency of the control device required to meet the PM emission limits in the 

promulgated NESHAP. 

The solid waste generated from the collection of dust and fly ash in a fabric filter was 

calculated when a fabric filter was determined to be necessary to meet the promulgated NESHAP 

emission limits for particulate matter and/or mercury. The calculation required the use of three 

variables, including: exhaust flow rate from the combustion unit to the control device (dscfm); 

operating hours (hr/year) and the inlet loading of particulate matter to the control device 

(gr/acfm). 

For this analysis, the spent carbon collected from units with ACI is assumed to be 

disposed of instead of being re-generated. The amount of spent carbon created from ACI was 

calculated when ACI was expected to be necessary to meet the promulgated NESHAP emission 

limits for mercury. The calculation required the use of six variables, including: Exhaust flow 

rate from the combustion unit to the control device (dscfm); operating hours (hr/year), required 

removal efficiency for mercury, and an adjustment factor based required removal efficiency of 

mercury. 

 The solid waste generated by the use of increased caustic was calculated for those units 

where additional caustic was expected to achieve the promulgated NESHAP emission limits for 

HCl. The calculation required the use of three variables, including: exhaust flow rate from the 

combustion unit to the control device (dscfm); operating hours (hr/year), and the required 

removal efficiency for HCl. 

5.3 Electricity Impacts 

The amount of electricity required to operate a control device was calculated for a packed 

scrubber, electrostatic precipitator, fabric filter, DIFF, CO oxidation catalyst and the fans for the 

ductwork associated with this equipment. These impacts were assessed for every unit that was 

estimated to require hydrogen chloride and/or particulate matter control. Electricity requirements 

are one output of the cost algorithms used in the analyses, so no additional calculations were 

necessary. For some units, an electrical demand from multiple control devices was estimated. 

The total national electricity demand in Table 5-1 was determined by adding the per unit solid 

waste estimates for all new and existing units, respectively. To estimate the electricity demand 

from each of these control devices, a set of variables were calculated based on characteristics 
29 

reported for each existing unit in the 2008 survey and subsequent data gathering activities and 

for the characteristics assigned to each new model unit. The constants, variables, and calculations 

used to estimate each variable and the electricity demand to operate the control devices are 

provided in another memorandum.2

 

5.4 Greenhouse Gas Emissions from Electricity Usage 

Since greenhouse gases are generated from electricity production, an estimate of carbon 

dioxide emissions was generated for the electricity impacts of the add-on air pollution control 

devices. The total electricity usage from all control devices was multiplied by the national 

average carbon dioxide emission factor for carbon dioxide emissions from EPA’s 2005 e-GRID 

to obtain the expected annual carbon dioxide emissions.9 Carbon dioxide emissions were only 

estimated for boilers required to install a fabric filter, electrostatic precipitator, wet scrubber, 

oxidation catalyst, or DIFF system, since those controls generate an increased electricity 

demand. 

5.5 Energy Savings Impacts 

The energy savings from combustion controls such as low NOx burners or linkageless 

boiler management systems, and work practice standards, including a tune-up, and implementing 

the energy audit findings with a short-term payback can improvements in efficiency, thereby 

reducing fuel consumption. This secondary impacts analysis only estimates a one percent 

efficiency gain from tune-up work practices and installation of combustion controls to be 

conservative and consistent with the assumptions made in Section 3.1 of this memorandum. No 

energy savings are attributed to the energy assessment in this analysis. Quantifying the exact 

gains in efficiency from each of these work practice standards is difficult, and may depend on the 

baseline operating efficiency of each unit. 

Section 3.1 discusses the fuel savings impacts in terms of annualized cost savings to each 

boiler or process heater, and the national energy savings presented in Table 5.1 of this section 

follows the same methodology as was discussed in Section 3.1 and reflect the savings from 

boilers in the coal, gas, and liquid fuel categories only. 
30 

5.6 Estimating Secondary Impacts for Existing and New Units 

 Appendices C-1 and C-2 present a detailed breakdown of the secondary waste, water, and 

energy impacts from each subcategory of existing and new boilers and process heaters, 

respectively. The differences presented between the recommended and alternative regulatory 

options are based on the number of controls estimated to be installed to meet the floor limits 

associated with each option, which in turn affects the amount of waste, wastewater, water, and 

energy consumed by the control devices installed for PM, HCl, and Hg. 

6.0 INCREMENTAL IMPACTS SINCE MARCH, 2011 RULE 

NOTICE 

 Appendix D presents the incremental costs, emission reductions, and secondary impacts 

of the amended final rule when compared to the March, 2011 final rule notice (76 FR 15608). 

This appendix shows the incremental impacts due to changes in the major source inventory of 

boilers and process heaters. The amended final rule contains an additional 336 boilers and 

process heaters compared to the inventory used to estimate impacts for the March, 2011 final 

rule. Appendix D also shows the incremental impacts due to changes in regulatory provisions 

(e.g., changes in emission limits, subcategories, or revised emission data submittals).
31 

7.0 REFERENCES 

1. Eastern Research Group, Inc. Revised MACT Floor Analysis (August 2012) for the 

Industrial, Commercial Institutional Boilers and Process Heaters national Emission 

Standards for Hazardous Air Pollutants – Major Source. August 2012. 

2. Eastern Research Group, Inc. Revised (November 2011) Methodology for 

Estimating Control Costs for Industrial, Commercial, Institutional Boilers and 

Process Heaters National Emission Standards for Hazardous Air Pollutants – Major 

Source. November 2011. 

3. Eastern Research Group, Inc. Revised (November 2011) New Unit Analysis for 

Industrial, Commercial, and Institutional Boilers and Process Heaters at Major 

Sources. November 2011. 

4. Singleton, A. and B. Lange, ERG. Gas Specification for Industrial, Commercial, 

Institutional Boilers and Process Heaters National Emission Standards for Hazardous 

Air Pollutants – Major Source. January 2011. 

5. U.S. Department of Energy, EIA. 2008 Delivered Fuel Prices to Industrial and 

Commercial Clients. http://www.eia.doe.gov/

6. Eastern Research Group, Inc. Revised August 2012 Development of Baseline 

Emission Factors for Boilers and Process Heaters at Commercial, Industrial, and 

Institutional Facilities. August 2012. 

7. U.S. Department of Energy. Energy Information Administration. Annual Energy 

Outlook 2011. Table A2. Energy Consumption by Sector and Source. 

http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf

8. “Servicing Your Boiler by Sustainable Energy Authority of Ireland.” Previously 

available on-line at http://www.seai.ie/. Docketed in National Emission Standards 

for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters. 

9. Environmental Protection Agency. eGRID. “eGRID Year 2005 Summary Tables” 

December 2008. 

http://www.epa.gov/cleanenergy/documents/egridzips/eGRID2007V1_1_year05_Su

mmaryTables.pdf

10. Milmore, P. and S. Winkleman. Climate Wise Boiler and Steam Efficiency Wise 

Rules: Proceedings from the Twentieth National Industry Energy Technology 

Conference. April 1998. Docketed in National Emission Standards for Hazardous 

Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers 

and Process Heaters. 
32 

11. DTE Energy. “Your Energy Savings Business Program: Boiler Tune-ups.” 

Previously available on-line at http://YourEnergySavings.com/. Docketed in 

National Emission Standards for Hazardous Air Pollutants for Major Sources: 

Industrial, Commercial, and Institutional Boilers and Process Heaters. 

12. U.S. Department of Energy. Energy Assessment Helps Kaiser Aluminum Save 

Energy and Improve Productivity. DOE/GO-102008-2561. July 2008. Docketed in 

National Emission Standards for Hazardous Air Pollutants for Major Sources: 

Industrial, Commercial, and Institutional Boilers and Process Heaters. 

13. Sathyanathan, V. T., Ph.D. Running a Coal Fired Boiler at the Best Efficiency. April 

2010. Docketed in National Emission Standards for Hazardous Air Pollutants for 

Major Sources: Industrial, Commercial, and Institutional Boilers and Process 

Heaters. 

14. CenterPoint Energy. Energy Efficiency Checklist (Minnesota). Previously available 

on-line at http://centerpointenergy.com/. Docketed in National Emission Standards 

for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters. 

15. Environmental Protection Agency. Wise Rules for Industrial Efficiency: A Tool Kit 

for Estimating Energy Savings and Greenhouse Gas Emissions Reductions. EPA 

231-R-98-014. July 1998. Docketed in National Emission Standards for Hazardous 

Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers 

and Process Heaters. 

16. Eckerlin, H.M., Ph.D., and E.W. Soderberg, Industrial Extension Service. USI Boiler 

Efficiency Program. A Report Summarizing the Findings and Recommendations of 

an Evaluation of Boilers in State-Owned Facilities. February 2004. 

http://www.energync.net/programs/docs/usi/om/boilers/ssr.pdf

17. Wright, A. and M. Martin, Oak Ridge National Laboratory, and B. Gemmer, P. 

Scheihing, and J. Quinn, DOE Industrial Technologies Program. Results from the 

U.S. DOE 2006 Save Energy Now Assessment Initiative: DOE’s Partnership with 

U.S. Industry to Reduce Energy Consumption, Energy Costs, and Carbon Dioxide 

Emissions, Detailed Assessment Opportunity Data Report. ORNL/TM-2007/138. 

September, 2007. 

18. Wright, A., M. Martin, and S. Nimbalkar, Oak Ridge National Laboratory, and J. 

Quinn, S. Glatt, and B. Orthwein, DOE Industrial Technologies Program. Results 

from the U.S. DOE 2007 Save Energy Now Assessment Initiative: DOE’s 

Partnership with U.S. Industry to Reduce Energy Consumption, Energy Costs, and 

Carbon Dioxide Emissions, Detailed Assessment Opportunity Data Report. 

ORNL/TM-2009/074. April 2009. 

19. Five State Heating and Cooling, Charlotte, NC. 

http://www.fivestarheatingandcooling.com/
33 

20. Eastern Research Group, Inc. Analysis of Dioxin/Furan Data and Minimum 

Detection Levels from Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air Pollutants – Major Sources. 

November 2011. 

21. Singleton, A., and Gibson, G., ERG. Revised Methodology for Estimating Cost and 

Emissions Impacts for industrial, Commercial, Institutional Boilers and Process 

heaters National Emission Standards for Hazardous Air Pollutants – Major Source. 

February 2011. 

22. U.S. Department of Energy, EIA. 2012 Delivered Fuel Prices to Industrial and 

Commercial Clients. http://www.eia.doe.gov/

23. Eastern Research Group, Inc. Incorporating Measurement Error in Reported Carbon 

Monoxide (CO) and Total Hydrocarbon (THC) Data (Revised August 2012). 

August 2012.