1

MEMORANDUM

TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS (C439-01)

FROM: Graham Gibson, Susan McClutchey, and Amanda Singleton, ERG

DATE: 24 March 2010

SUBJECT: DRAFT Methodology for Estimating Impacts from Industrial, Commercial, 

Institutional Boilers Area Sources of Hazardous Air Pollutant Emissions

1.0 INTRODUCTION

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

emission reductions, and secondary impacts from industrial, commercial, and institutional boilers 

at area sources of hazardous air pollutant (HAP) emissions. These impacts were calculated for 

existing units and projected new boilers expected to be operational by the year 2013, three years 

after the rule is expected to be promulgated. 

The cost, emission reductions, and secondary impacts analyses for existing and new area 

source boilers were conducted on model boilers. Twenty-seven general model boilers were 

developed based on the sized of the combustion unit and fuel combusted. There are a total of 

182,671 existing boilers nationwide, according to the extrapolated boiler inspector inventory. 

These boilers were divided into the 27 model units in order to assess the impacts of the proposed 

regulatory options. An estimated 6,779 new boilers at area sources are expected to be installed 

by 2013, and most of these units are expected to fire fuel oil. Given the current fuel oil prices, 

and the fact that gas-fired boilers are not part of the area source industrial, commercial and 

institutional boiler source category, these projections may overestimate the number of new 

sources expected to come on-line by 2013. Instead, these new boilers projected to fire fuel oil 

may be configured to fire natural gas in order to avoid the compliance costs associated with the 

area source rulemaking. The project new units were distributed among 12 model boilers, five 

models representing units at industrial facilities and the remaining 77 model boilers representing 
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boilers at commercial and institutional facilities. The methodology used to develop model units 

and estimate the number of affected units are presented in other memoranda.

(Projecting new area source 

boilers, developing model units)

The results of the impacts analysis are presented for the most stringent regulatory option 

evaluated and the regulatory option contained in the proposed rule. The development of the 

MACT floor level of control 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 

separated into the following sections:

1.0 Introduction

2.0 Regulatory Options and Estimating Cost Impacts

3.0 Methodology for Estimating Emission Reductions

4.0 Methodology for Estimating Secondary Impacts [under development]

5.0 References [under development]

2.0 REGULATORY OPTIONS AND ESTIMATING COST 

IMPACTS

Three control options were considered for boilers at area sources of HAP. For each 

option, a percentage of units in each model unit were assumed to require control devices in order 

to meet the limit when the baseline emissions for the model unit exceeded the MACT floor 

emission limit applicable to each model. A detailed description of the four options is described 

below. A summary table comparing the overall capital and annualized costs of option 1 and 

option 2a is presented in Table 1. The equations used to estimate the control, testing, 

monitoring, and work practice costs are discussed in another memorandum.2,3

2.1 Existing Units

Option 1

Option 1 requires boilers of all sizes to meet numerical emission limits for CO, PM, and 

Hg. To estimate the number of units required to install controls to meet the emission limits, the 

baseline emissions for each model unit is compared to the corresponding MACT floor for CO 

and Hg, and generally achievable control technology (GACT) limit for PM. The following logic 
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is used to select which control devices are included in the cost analysis for each existing boiler:

Mercury Control

A new fabric filter installation was expected to achieve the mercury emission limits in the 

proposed rule. Where baseline mercury emissions were found to be greater than the MACT floor, 

the cost of a fabric filter was estimated for a portion of the boilers represented by the model unit. 

Based on the data used in the MACT floor analysis, a fraction of units in each subcategory 

meeting the MACT floor for Hg was estimated. For boilers designed to burn biomass one of the 

boilers was meeting the floor and the other unit was not meeting the floor. In the cost impacts 

analysis, 50 percent of the biomass units were estimated to install a fabric filter to meet the floor. 

For boilers designed to burn coal, 44 percent of units were achieving the proposed MACT floor 

emission limit for coal, so a new fabric filter was estimated to be installed at 56 percent of the 

existing coal-fired boilers. For liquid fuel units, there were no area source boilers with emission 

test data available for mercury. In the absence of other information about the distribution of units 

that would require a fabric filter to be installed, this cost impacts analysis assumes that 50 

percent of the liquid fuel units would install a fabric filter to meet the mercury limit. 

CO/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. 

Most boilers (other than Dutch ovens and PC-coal boilers) are designed to operate with 

CO emissions at or near 400 parts per million (ppm). A boiler tune-up, was estimated in the cost 

impacts analysis if the unit’s baseline emissions exceeded the floor for carbon monoxide (CO), 

but were less than or equal to 400 ppm @ 3% O2. The combustor design of the boilers in the area 

source inventory is not known and this impacts analysis assumes that all areas source boilers 

firing solid fuels have a stoker combustor design since this is the predominant combustor design 

in the major source boiler inventory. The baseline emissions for area source boilers in all fuel 

categories are less than 400 ppm, and so it is assumed that combustion controls, either a basic 

tune-up or a more advanced burner replacement or installation of a linkageless boiler 
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management system, can achieve the proposed MACT floor emission limits. No oxidation 

catalysts are estimated to be required to meet the MACT floor emission limits.

Based on the emission test data used to calculate the MACT floor for CO, 29 percent of 

units burning coal are meeting the MACT floor and these units would be expected to install a 

linkageless boiler management system to comply with the CO limits. For units burning biomass, 

72 percent of the units are exceeding the MACT floor emission limits, and so 72 percent of the 

units are estimated to install a linkageless boiler management system. For units burning liquids, 

86 percent of the units are exceeding the floor and this cost impacts analysis assumes these units 

will install a new low NOx replacement burner in order to meet the CO limits. The units not 

expected to install these advanced controls are expected to conduct an annual tune-up to maintain 

in compliance with the proposed CO limit overtime.

Particulate Matter Control

For all units that were not expected to install a fabric filter for mercury control, this cost 

impacts analysis assumes that the unit would install a multiclone to achieve the GACT emission 

limits for PM. Based on the current MACT floor analysis, 44 percent of coal units and 50 percent 

of biomass and liquid units would install a multiclone.

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 model unit, and the fuel category of the 

model unit. 

All boilers designed to burn solid fuels were expected to conduct an annual compliance 

test for PM, Hg, and CO. The cost to conduct stack tests for these three pollutants was estimated 

to be $15,000 per year. Combustion units greater than 100 mmBtu/hr were expected to install 

CO CEMS in lieu of conducting a CO stack test and the cost to conduct tests on PM and Hg was 

estimated to be $12,000 per year. 

Boilers 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.
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Conducting stack tests for PM and CO was estimated to be $13,000 per year and the cost to 

conduct fuel analysis for Hg was estimated to be $600 per year. Combustion units greater than 

100 mmBtu/hr were expected to install CO CEMS in lieu of conducting a CO stack test and the 

cost to conduct tests on PM and fuel analysis for Hg was estimated to be $8,600 per year. 

Although solid fuels are eligible to comply with the proposed rule through fuel analysis in lieu of 

stack testing, when the mercury content of the fuel is below the MACT floor emission limit, 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.2,3

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 a fabric filter, an annualized cost of $9,700 for a bag leak detection 

monitor was included in the cost analysis. For units greater than 100 mmBtu/hr, an annualized 

cost of $53,300 for a CO CEMS was included in the cost analysis. For units that did not install a

bag leak detector, an annualized cost of $14,660 for an opacity monitor was included in the cost 

analysis. 

Fuel Savings Impacts

This cost analysis includes an estimate of energy savings for every unit that is expected to 

install controls to improve combustion, or conduct an annual tune-up or energy audit. The 

Department of Energy has conducted energy assessments at selected manufacturing facilities and 

reports that facilities can reduce fuel/energy use by 10 to 15 percent by using best practices to 

increase their energy efficiency. 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-up. 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 the Equation 1:

Annual Fuel Savings (mmBtu/yr) = DC * CF * Ophours (Equation 1)

Where:
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DC = unit design capacity (mmBtu/hr)

CF = capacity factor, 90% of design capacity

Ophours = annual operating hours, assumed 8400 (hours/year)

After the fuel savings for each boiler was calculated, the both industrial and commercial 

prices for coal, #2 distillate fuel oil, #6 residual fuel oil, and natural gas were obtain from the 

EIA.3 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 distribution 

of SIC codes reported in the 13-state boiler inspector inventory, the model units were distributed 

to an industrial or commercial sector, and then the appropriate fuel price was multiplied by the 

calculated fuel savings. This cost analysis only estimates the fuel savings from units in the coal 

and liquid fuel categories. A fuel savings was not estimated for units in the biomass fuel category 

since the price of biomass fuels is variable, and often biomass is an on-site industrial byproduct 

instead of a purchased fuel.

Option 2

Option 2 follows the same logic for estimating control costs as option 1 outlined above, 

with the exception of small units (less than 10 mmBtu/hr). In option 2, the only cost estimated 

for small units is the cost of an annual tune-up for each boiler. No testing and monitoring costs 

were included in option 2 for small units 

Option 2a

Option 2a includes control device and testing/monitoring cost estimation logic identical 

to Option 2 outlined above, except for the addition of the estimated cost of one facility-wide 

energy audit for each facility, annualized over 5 years, as discussed in option 2. As discussed in 

the memorandum for Estimating Control Costs from Major Source Boilers and Process heaters, 

the cost of an energy audit ranges from $75,000 for industrial-scale energy audits to between 

$2,000 and $5,000 per energy audit for institutional and commercial-scale audits.2 The facility’s 

classification of either an industrial or commercial facility was assigned using the distribution of 

SIC codes in the 13-state boiler inspector inventory. The cost of each type of audit was 

annualized over 5 years at 7 percent to obtain an annualized cost estimate. For the cost impacts 
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analysis, 91,339 facilities are expected to conduct an audit, 87,507 facilities are commercial or 

institutional and 3,832 facilities are industrial.

2.2 Regulatory Options for New Units

The same three regulatory options 1, 2, and 2a were evaluated for the 6,779 new boilers 

expected to come online through 2013. However, the distribution of new units expected to install 

fabric filters for mercury control or advanced combustion controls for CO control were adjusted 

to account for other regulatory requirements including New Source Performance Standards and 

local air quality standards that may require new boilers to install low NOx burners. 

Option 1

Mercury and PM Control

To meet the PM GACT floor limit of 0.03 lb/mmBtu, and the proposed mercury limits 

for coal, biomass, and liquid units, the cost to install a fabric filter was applied to all new boilers, 

regardless of size.

CO Control

Since new boilers are estimated to install new low NOx burners as part of their 

installation, the work practice estimated to achieve the proposed CO limits is a tune-up. The 

costs for a tune-up were applied to all new boilers expected to come online through 2013.

Testing and Monitoring

The same testing and monitoring costs described for option 1 for existing units in section 

2.1 was applied to all new units.

Fuel Savings

Since all new boilers are expected to conduct a tune-up to meet the CO limit, an estimate 

of fuel savings was calculated for all new boilers firing coal and liquid fuels. The calculations 

used to estimate fuel savings are described in Section 2.1.

Option 2

Similar to option 2 discussed in Section 2.1, under this option new units less than 10 

mmBtu/hr will demonstrate compliance with the rule using a tune-up and the cost of an annual 
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tune-up was applied to every new boiler with a design capacity of less than 10 mmBtu/hr. For 

larger units, the regulatory option is the same as Option 1, that is all units >10 will install a fabric 

filter and conduct a tune-up in order to achieve the proposed MACT floor emission limits for 

mercury and CO and the GACT emission limit for PM.

Option 2a

Option 2a is the same as option 2 above, except for the addition of a facility-wide energy 

audit. As discussed for option 2a for existing boilers under Section 2.1, the cost of an audit 

depends on whether the facility is an industrial or commercial facility. The cost of each type of 

audit was annualized over 5 years at 7 percent to obtain an annualized cost estimate. The 

facility’s classification of either an industrial or commercial facility was assigned using EIA fuel 

projection estimates for 2013 in the industrial and commercial sectors. Based on these 

projections, and an average of 2 boilers per facility, this cost impacts analysis estimates that 

3,035 facilities with new boilers are at commercial or institutional facilities and the remaining 

354 facilities with new boilers are at industrial facilities. 

2.5 Summary of Cost Impacts

Option 2a is the proposed option for existing boilers and option 1 is the proposed option 

for new boilers. Since new boilers and their exhaust stacks can be designed to allow for stack 

testing, the tune-up work practice standard does not apply to new small units. Table 1

summarizes the costs of the proposed option for new and existing boilers at area sources of HAP. 

Appendix A of this memorandum provides a detailed summary of the costs for each model unit. 

Table 1: Summary of Costs of Proposed Options

Costs shown in $106 (2008) with capital recovery estimated at 7%

Type of 

Unit Option

Number 

of Boilers TAC

TAC 

considering 

fuel savings

Testing & 

Monitoring 

TAC Control TAC

Control 

TCI

New

1 6,779 $2,233 $2,145 $177 $2,056 $5,952

Existing

2a 182,677 $5,324 $4,751 $357 $4,967 $15,596
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3.0 METHODOLOGY FOR ESTIMATING EMISSION 

REDUCTIONS

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

at both existing and new facilities and it presents a summary of the results for the regulatory 

options 1 and 2a.

3.1 Emission Reductions from Existing Boilers

Each model area source boiler was assigned baseline emissions based on the calculated 

baseline averages for existing major source combustion units in the same size and fuel 

subcategory. The development of area source model units and the procedures and results of the 

baseline emissions analysis is presented in other memoranda.

1-2

Emission Reductions for Option 1

Emission reductions for all pollutants were calculated on a ton per year basis. Emission 

reductions of Hg and CO were calculated by subtracting the baseline emissions assigned to each 

model unit from the MACT floor emission limits corresponding to the subcategory for each 

model boiler. A detailed discussion of the procedures and results of the MACT floor analysis is 

presented in another memorandum.

(cite MACT floor analysis)

 

For all units expected to install a fabric filter to meet the mercury MACT floor emission 

limits, this fabric filter achieves a co-benefit of reducing emissions of PM and non-mercury 

metallic HAP. To calculate the PM emission reductions from units expected to install a fabric 

filter, the baseline emissions assigned to each model boiler were subtracted from the calculated 

average baseline emission factor corresponding to a fabric filter level of control in the same fuel 

category. For example, the PM baseline emission factor for uncontrolled or multiclone-equipped 

biomass boilers is 0.26 lb/mmBtu, and the calculated baseline emission factors for biomass 

boilers equipped with a fabric filter is 0.01 lb/mmBtu. The emission reductions were estimated 

using the difference of these two factors, or 0.25 lb/mmBtu. The methodology used to calculate 

average baseline emission factors for different fuel and control configurations is discussed in 

another memorandum.(Baseline) It was assumed that the remaining boilers that did not install a 

fabric filter will install a cyclone or multiclone to reduce PM emissions. Multiclones were 
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identified as a GACT level of control for solid fuel units. Emission reductions for units expected 

to install a multiclone were estimated by multiplying the baseline emissions of each model unit 

by the expected PM control efficiency of a multiclone, a 75 percent reduction. These control 

efficiencies for various control devices are detailed in another memorandum. (cite baseline memo) 

Model units with a design capacity greater than 10 mmBtu/hr were expected to already have a 

multiclone installed as a baseline level of control, so no additional PM emission reductions were 

estimated from these units, unless the unit installed a fabric filter for mercury control. 

To estimate the reductions in other non-mercury metallic HAP, the percent reduction in 

filterable PM was calculated for each model unit, depending whether a multiclone of fabric filter 

was projected to be installed on the boiler. This percent reduction was multiplied by the baseline 

emissions for each of the non-mercury metallic HAP. This analysis assumes that each model 

boiler would achieve an identical percent reduction from baseline emissions for each nonmercury metallic HAP as was achieved for PM. 

PM2.5 emissions comprise a fraction of total filterable PM emissions depending on the 

fuel combusted 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.(cite 

baseline memo) To calculate emission reductions for PM2.5 for each model boiler, the emission 

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

For any boiler conducting a tune-up, a one percent gain in combustion efficiency was 

estimated, resulting in an estimated one percent emissions reduction of HCl, HF, SO2, THC, 

VOC, and dioxins/furans. Efficiency gains reduce fuel use, and in turn, emissions of hazardous 

air pollutants. A one percent reduction in emissions for these pollutants was estimated by 

multiplying the baseline emissions for each unit by a factor of 0.01.

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

emission rate, Equation 2 was used:

Annual Emission Rate (tpy) = ERHI * 0.0005 * Ophours (Equation 2)

Where:

ERHI = emission rate (lb/mmBtu)

0.0005 = conversion factor, lbs per ton

Ophours = annual operating hours reported in 2008 survey (hours/year)
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To convert emission reductions from a concentration basis to an annual emission rate, 

Equations 3 and 4 were used:

Annual Emission Rate (tpy) = ERC * 0.000001 * ρair * QS * 60 * Ophours * 0.0005 * 

(20.946 – O2) / (20.946 – Std O2) (Equation 3)

Where:

ERC = emission concentration (ppm @ 3% O2)

0.000001 = conversion factor, ppm to parts

ρair = density of air, 0.0749 lb/dscf

QS = exhaust flowrate (dscfm)

60 = conversion factor, minutes to hours

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

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 for proposed rule. 

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

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

Where:

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

0.0283 = conversion factor, dscm to dscf

QS = exhaust flowrate (dscfm)

60 = conversion factor, minutes to hours

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 proposed 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 memorandaSEE Control Cost Memo. All conversions 

required the annual operating hours for each model unit, which were assumed to be 8,400 hours 

per year for all model units (two weeks of downtime).

Emission Reductions for Option 2a
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The same calculations discussed for estimating emission reductions for option 1 were 

applied to all boilers except small model boilers (less than 10 mmBtu/hr). For small model 

boilers, the emission reductions were based on a one percent gain in efficiency expected from the 

annual tune-up work practice standard. 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. A summary of the estimated 

emission reductions at existing units for both option 1 and option 2a are located in Appendix B1.

3.2 Emission Reductions from New Boilers 

Based on industrial and commercial fuel consumption projections from the EIA and a 

history of boiler installation dates in the boiler inspector inventory, there are 6,779 new area 

source boilers expected to come on-line by 2013.(cite EIA source) These new projected boilers are 

expected to fire biomass, coal, and liquid fuels. An average (mean) design capacity of area 

source boilers firing similar fuel type, in the same size category, and in the same sector 

(industrial or commercial) was estimated to develop new model units representative of the 

existing boiler inventory. New model units were assigned baseline emissions in the same 

manner as existing area source model units. The development of area source model units and the 

procedures and results of the baseline emissions analysis is presented in other memoranda.

1-2

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 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 boilers larger 

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

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 a low sulfur content. New boilers larger than 30 

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

than 30 mmBtu/hr would have no add-on controls and liquid fuels were expected to meet the 
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NSPS SO2 limits using low sulfur fuel oils. 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. Based on the EIA fuel projections, all new coal boilers are projected to be less than 10 

mmBtu/hr and the only 49 model boilers firing biomass are expected to exceed 30 mmBtu/hr. 

Emission Reductions for Option 1

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. The 

same calculations discussed in Section 3.1 of this memo were used to estimate the reductions for 

new units.

Emission Reductions for Option 2a

The emission reductions for new units under regulatory option 2a were calculated using 

the same methods discussed in Section 3.1 of this memo to compare with the reductions achieved 

under regulatory option 1. Under the proposed rule, new small units do not qualify for the same 

tune-up work practice standards that apply to existing units since it is expected that new units can 

be designed to allow for stack test diameters that would be compatible with EPA test methods. 

A summary of the estimated emission reductions at existing units for both option 1 and option 2a

are located in Appendix B-2.

4.0 METHODOLOGY FOR ESTIMATING SECONDARY 

IMPACTS

[under development]

5.0 REFERENCES [under development]
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1. Area source model units memo

2. Baseline emission factor memo

3. Eddinger, J. April 2009. Technical Memorandum: “MACT Floor Analysis for the 

Industrial, Commercial, and Institutional Area Source Boilers”.

4. MACT floor memo

5. Roy Oommen, Eastern Research Group (ERG). Memorandum to Jim Eddinger, U.S. 

Environmental Protection Agency, OAQPS. Methodology for Estimating Cost and 

Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters 

National Emission Standards for Hazardous Air Pollutants. October, 2002.
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Appendix A – Emission Reductions Spreadsheet