MEMORANDUM 

TO: Brian Shrager, U.S. Environmental Protection Agency, OAQPS/SPPD 

FROM: Eastern Research Group, Inc. 

DATE: November 2011 

SUBJECT: Revised (November 2011) 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 both the regulatory option contained in the proposal and a more stringent 

regulatory option. 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 References 
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 reconsideration 

proposed 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 for units in the solid and gas 2 (other) 

subcategories), 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 the combustion-based pollutants PM (or TSM8) and CO, separate 

combustor design subcategories are considered for coal/fossil solids, and biomass. For 

units designed to burn liquid fuels separate combustor 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. 
 The alternative option is identical to the recommended option except that numeric 

emission limitations for PM remain as fuel-based, consistent with the March 2011 final 

rule, as opposed to combustor design. The TSM8 alternative standard is not included 

under this alternative. 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 Hg, HCl, and PM. Combustor-level 

subcategories for CO are identical to those developed under the recommended option. 

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. This is a change since the March 2011 final rule. The methods 

and assumptions used in projecting new units is detailed in another memorandum.3

3.0 ESTIMATING COST IMPACTS 

For each option, 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 recommended option are presented 

in Table 3-4. 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 emission data that affected the proposed MACT floors for 

existing solid fuel Hg and HCl, as well as existing CO limits at stoker/sloped grate/other units 

designed to burn wet biomass. Although the proposal reflects these revised MACT floor 

emission limits, the cost, emission, burden estimates, and secondary impacts analyses were not 

able to be updated to reflect these revised limits due to time constraints. These analyses will be 

revised for the final rule, but based on these new limits the overall cost of the rule is projected to 

increase by less than 2 percent. Table 3-1 contrasts the emission limits the baseline emissions 

were compared to for the impacts analyses with the proposed emission limits for Hg, HCl, and 

CO. 

Table 3-1. Comparison of Proposed Emission Limits with Limits Used in Impacts Analysis. 

Pollutant 

Subcategory Emission Limit Used 

for Cost and 

Emission Reductions 

Calculations 

Proposed Emission 

Limit 

Hg (lb/MMBtu) Existing- Solid 5.2E-06 3.1E-06 

HCl (lb/MMBtu) Existing- Solid 2.6E-02 2.2E-02 

CO (ppm @ 3% O2) 

Existing – 

Stoker/Sloped 

Grate/Other Wet 

Biomass 

730 790 

 

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 60 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 35 existing boilers and process heaters. 

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

of hydrogen chloride (HCl)—is 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. 

 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 478 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 

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 910 existing boilers and process heaters. DIFF was identified to be 

necessary to control HCl emissions at 129 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 

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 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 tuneup 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 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.4

 For the cost impacts analysis, 1,704 facilities are expected to 

conduct an audit, 204 facilities are commercial or institutional and 1,500 facilities are 

industrial. 
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 testing costs have been 

adjusted since the March 2011 final rule to remove the costs associated with dioxin/furan testing. 

The cost to conduct stack tests for 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 

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 a average heat input rate of 250 mmBtu/hr or more from coal, fossil solid or heavy liquid, as 

well as units designed to burn biomass units that reported co-firing biomass with other fuels. 

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 is 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% 

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 the EIA.5

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

feet for natural gas, and cents per gallon for fuel oil. 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 

3-2 below shows the distribution of reported NAICS codes considered as industrial versus 

commercial in terms of fuel pricing. 

Table 3-2: 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 

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

gas fuel categories. A fuel savings 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 on-site industrial 

byproduct instead of a purchased fuel. 
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 numeric emission 

limitations for PM are on a fuel basis, and the alternative TSM8 emission limit option is removed 

from consideration. 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 60 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 

the same number of boilers and process heaters under this option when compared to the 

recommended option. 

 ACI equipment was estimated to be installed at 35 existing boilers and process heaters for 

controlling Hg. ACI equipment is required to be installed on the same number of boilers 

and process heaters compared to the recommended option. 

 ESP technology was estimated to be installed at 629 existing boilers and process heaters 

to control PM. ESP technology is required to be installed on an additional 211 boilers and 

process heaters under this option when compared to the recommended option. 

 Wet scrubbers were estimated to be necessary to control HCl emissions at 910 existing 

boilers and process heaters. This is identical to the number of sources estimated to install 

a scrubber for HCl control under 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 the same number of 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 8 

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 3-4 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 under both the 

recommended and alternative options the 78 new large biomass boilers are projected to install 

fabric filters for mercury control, no ESP installations are estimated and the alternative option 

shows the same number of control devices as the recommended new unit option. 

Similar to the discussion in Section 3.1 above, there were late changes to the emission 

data that affected the proposed MACT floors for new solid fuel HCl and new CO limits at 

stoker/sloped grate/other units designed to burn wet biomass. Although the proposal reflects 

these revised MACT floor emission limits, the cost, emission, burden estimates, and secondary 

impacts analyses were not able to be updated to reflect these revised limits due to time 

constraints. These analyses will be revised for the final rule. The estimated costs for new sources 

did not change as a result of these edits. Table 3-3 contrasts the emission limits the baseline 

emissions were compared to for the impacts analyses with the proposed emission limits for HCl, 

CO, and PM. 

Table 3-3. Comparison of New Source Proposed Emission Limits with Limits Used in Impacts 

Analysis. 
Pollutant 

Subcategory Emission Limit Used 

for Cost and 

Emission Reduction 

Calculations 

Proposed Emission 

Limit 

HCl (lb/MMBtu) New-Solid 2.6E-02 2.2E-02 

CO (ppm @ 3% O2) 

New – Stoker/Sloped 

Grate/Other Wet 

Biomass 

430 590 

PM (lb/MMBtu) 

New – Stoker/Sloped 

Grate/Other Wet 

Biomass 

0.0048 0.029 

3.4 Summary of Cost Impacts 

 The recommended option is the proposed option for existing and new boilers and process 

heaters. Tables 3-4 and 3-5 summarize the costs of the recommended for new and existing units. 

Appendix A of this memorandum provides a detailed summary of the recommended and 

alternative options for existing and new sources costs according to unit size, subcategory, and 

individual control device costs. 

Table 3-4: Summary of Costs of Proposed Recommended Options 

Costs shown in $106

 (2008) with capital recovery estimated at 7% 

Type of 

Unit Option 

Number 

of Units TAC 

TAC 

considering 

fuel savings 

Testing & 

Monitoring 

TAC 

Control 

TAC 

Control 

TCI 

New Recommended 1,844 $104 $104 $5.6 $98.5 $393 

Existing Recommended 14,111 $1,874 $1,493 $97.6 $1,748 $5,440 

Table 3-5: Summary of Total Annual Costs by Control Type for Existing Units under Recommended Option 

Costs shown in $106

 (2008) with capital recovery estimated at 7% 

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 

14,111 $125 $166 $735 $414 $1.8 $249 $16.7 $40.6 $27.6 

 
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 14,111 boilers and process 

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

subsequent requests for or submissions of data. Each combustion unit was assigned a unitspecific 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. This is a change since the March 2011 final rule to accommodate the 

alternative TSM8 standard for certain subcategories. Previously emissions of non-Hg metallic 

HAP were assumed to achieve an identical percent reduction as achieved for PM. The minimum 

percent reduction required for PM or TSM8 was chosen, and baselines for both PM and TSM8 

were reduced by that same percentage. Since there is no TSM8 alternative for units designed to 

combust liquid fuels, TSM8 reductions for these units were estimated by applying the control 

efficiency needed to meet the PM emission limit. 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 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. Numeric emission limitations for dioxins/furans have been removed because the EPA 

has determined that the application of measurement technology to these sources is not 

practicable due to technical and economic limitations. Assuming zero reductions in dioxin/furan 

emissions is a change from the March 2011 final rule. 

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. 

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. This is a change since the March 2011 final rule, as previously 

only units not subject to numeric emission limitations were required to perform an initial boiler 

tune-up. Now, all units, regardless of size or fuel, must conduct an initial tune-up. 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 

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

emissions. 

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 4-1 shows the computed emission limits, mean of the top performers, 

and the 3x RDL value for each subcategory. In all cases, the average emissions or 3x RDL value 

was lower than the actual numeric emission limit. 
Table 4-1: 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 5.2E-06 3.8E-07 8.6E-07 

Liquid 2.6E-05 2.4E-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 

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 numeric emission limits for PM were based on a fuelbasis (solid, liquid, gas) instead of a combustor basis, and the alternative numeric emission limits 

for TSM8 were removed. It was assumed that each combustion unit would achieve an identical 

percent reduction in TSM emissions as was achieved for compliance with the alternative numeric 

PM emission limits. The remainder of the above methodology and calculations for the 

recommended option were performed for all other pollutants. The actual MACT floor emission 

limits used in the alternative options are discussed in another memorandum.1 

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 

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 

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-1. 

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 

proposed 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 new and existing boilers 

and process heaters, respectively. 

Table 5-1: Summary of Secondary Impacts 

Impact New Units 

(recommended option) 

Existing Units 

(recommended option)

Water (gal/yr) 0 1.2 billion

Wastewater (gal/yr) 0 416 million

Solid Waste (tons/yr) 1,700 285,500

Purchased Electricity (kW-hr/yr) 120 million 1.4 billion

CO2 Emissions from Purchased 

Electricity (tons/yr) 79,700 931,000

Energy Savings* (trillion Btu/yr) 0 47.3

* 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, 

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 

(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 

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. 

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 new and existing 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. 

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