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MEMORANDUM 

TO: Brian Shrager & Jim Eddinger, U.S. Environmental Protection Agency, OAQPS 

FROM: Eastern Research Group, Inc. 

DATE: November 2011 

SUBJECT: Revised November 2011 Development of Baseline Emission Factors for Boilers 

and Process Heaters at Commercial, Industrial, and Institutional Facilities 

1.0 INTRODUCTION

This memorandum discusses the processes used to develop baseline emission factors for 

boilers and process heaters based on data reported by industry in the 2008 Questionnaire for 

Boilers, Process Heaters, Incinerators and Other Combustion Units (ICR No. 2286.01, OMB 

Control No. 2060-0616, EPA Form No. 5900-122), the 2009 Test Plan for Boilers and Process 

Heaters (ICR No. 2286.03, OMB Control No. 2060-0616, EPA Form No. 5900-122), and 

subsequent data submittals. ERG developed two databases: 1) a comprehensive survey database 

containing all data reported by industry during the 2008 Combustion Survey (herein referred to 

as the Survey Database)1

 and 2) a comprehensive emission database containing all the stack test 

results, continuous emissions monitoring system (CEMS) data, and fuel analysis data reported in 

the 2008 Combustion Survey and the 2009 Phase II Test Plan (herein referred to as the Emission 

Database)2

. A data dictionary and description of all the fields contained in the Survey Database 

are summarized in another memorandum.3

 The standardization of reported emission data in both 

the Survey and Emission Databases is also described in another memorandum.4

The development of baseline emission factors followed a four-step process: First, a list 

of unique combustion units reported in the Survey Database was compiled. Next, the reported 

fuels combusted and control devices installed were categorized. Third, for all units reporting 

emission data, all available emission data for each particular combustion unit were averaged and 
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assigned a unit-specific baseline emission factor. Finally, to fill data gaps at units not reporting 

emission data, the emission data from other similar units at the same facility, or other units 

assigned to the same fuel, control device, and combustor design categories were averaged to 

develop an average baseline emission factor for similar types of units. 

Baseline emission factors were developed for 24 specific pollutants based on the fuel and 

control device combinations or fuel and combustor design combinations utilized by the 

combustion devices reported in the questionnaire. These emission factors will be used to 

determine the control devices necessary to meet emission limits and to estimate potential 

emission reductions for the National Emission Standards for Hazardous Air Pollutants 

(NESHAP) for boilers and process heaters at Industrial, Commercial, and Institutional facilities. 

This memorandum is organized as follows: 

1.0 Introduction 

2.0 Grouping Data According to Fuel Type, Control Device, and Combustor Design 

3.0 Development of Unit-Specific Emission Factors 

4.0 Development of Average Baseline Emission Factors 

5.0 Baseline Averages for Area Sources 

6.0 References 

Appendix A: Glossary 

Appendix B: Fuel and Control Device Groupings 

Appendix C: Estimated Percent Reductions from Control Device Groupings 

Appendix D: Baseline Emission Factors for Boilers and Process Heaters at Major Sources 

Appendix E: Baseline Emission Factors for Boilers at Area Sources

NOTE: Technical terms and acronyms used in the text, tables, and appendices of this 

memorandum are described in Appendix A. 
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2.0 GROUPING DATA ACCORDING TO FUEL TYPE, CONTROL DEVICE, AND 

COMBUSTOR DESIGN

The first step of the baseline emission factor process involved targeting select pollutants, 

developing a comprehensive list of all combustion units reported in the questionnaire, and 

categorizing combustion units according to standardized fuel groups, control devices, and 

combustor designs reported the questionnaire. The procedures used to characterize the 

qualitative data from the questionnaire into appropriate groups are discussed in this section. 

2.1 Pollutants 

Baseline emission factors are specific to a certain type of pollutant. This analysis 

targeted 24 different pollutants, all of which are listed in Table 1. Although data were reported 

for more than 24 pollutants, baseline emission factors were only developed for those listed in 

Table 1 because these pollutants represent pollutants regulated under Section 112 of the Clean 

Air Act, as amended in 1990 (CAA), they represent surrogates for pollutants regulated under the 

CAA, or they represent pollutants that EPA uses to quantify the human health benefits resulting 

from a rulemaking. 

Table 1: Pollutants Assigned Baseline Emission Factors 

Pollutant 

Antimony (Sb) Arsenic (As) 

Beryllium (Be) Cadmium (Cd) 

Chromium (Cr) Cobalt (Co) 

Lead (Pb) Manganese (Mn) 

Nickel (Ni) Selenium (Se) 

Sum of 8 Metallic HAP 

(TSM8)1

Sum of 10 Metallic HAP 

(TSM10)2

Mercury (Hg) Filterable Particulate 

Matter (PM) 
4

Pollutant 

Hydrogen Chloride (HCl) Hydrogen Fluoride (HF) 

Chlorine (Cl2) Sulfur Dioxide (SO2) 

Total Hydrocarbons (THC) Volatile Organic 

Compounds (VOC) 

Toxic-Equivalent 

Dioxins/Furans (TEQ D/F) Carbon Monoxide 

Formaldehyde Oxides of Nitrogen (NOx) 

1

 Comprises As, Be, Cd, Cr, Pb, Mn, Ni, and Se. 

2

 Comprises Sb, As, Be, Cd, Cr, Co, Pb, Mn, Ni, and Se. 

2.2 Developing a Comprehensive List of Combustion Units 

Each record in the Data: Unit Design/Operation table of the Survey Database correlates 

to a single combustion unit. The information for this table was derived from Section II.B of the 

Questionnaire.5

 In addition, small, gas-fired boilers or process heaters were reported under 

Section II.A of the Questionnaire. The definition of a small, gas-fired combustion unit is any 

unit firing natural gas, propane, liquefied petroleum gas (LPG), or refinery gas with a design 

capacity less than 10 million British thermal units per hour (MMBtu/hr). These groups of small 

combustion units, each treated as a single combustion unit for the purpose of developing baseline 

emission factors, are only present in the Data: GCP and Combustion Controls table of the 

Survey Database. 

An inventory was generated containing all the combustion units in the Data: Unit 

Design/Operation table as well as the small, gas-fired units in the Data: GCP and Combustion 

Controls table. This inventory was then filtered to include only combustion units classified as 

boilers or process heaters at major sources of hazardous air pollutant (HAP) emissions. This 

resulted in a total of 14,111 unique boilers and process heaters, with 7,117 of these being small, 

gas-fired units. 

2.3 Fuel Categories 

The Questionnaire provided a drop-down list containing 134 different fuels and materials, 

and it also allowed users to self-report additional types of fuels and materials not included in the 

list. These fuels were categorized into one of the 9 fuel categories listed in Table 2. A list 
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mapping each fuel category in Table 2 to specific fuel types reported in the survey can be found 

in Table B.1 of Appendix B. Because many boilers and process heaters fire multiple types of 

fuels, a fuel hierarchy was established to assign each multi-fuel boiler and process heater to a 

specific fuel category. 

For units firing multiple fuels, fuel categories were assigned based on the percentage of 

the total heat input contributed by each fuel. A threshold of 90 percent was used to assign a fuel 

category based on the hierarchy listed in Table 2. For example, if the total heat input at a unit 

consisted of 90 percent coal and 10 percent natural gas, it was placed in the Coal category 

because the unit was combusting at least 90 percent coal on a heat input basis. For a combustion 

unit to be classified as any fuel lower in the hierarchy, each of the fuels ranked higher must all 

contribute less than 90 percent to the unit’s total heat input. For example, if a combustion unit’s 

total heat input was composed of 10 percent coal and 90 percent wet biomass, it was placed in 

the wet biomass category. Only data where fuel percentages could be calculated were used in 

baseline analyses. If a unit was firing 50% biomass and 50% coal, its data were not used in the 

calculation of overall average baseline emission factors but were used to calculate unit-specific 

baseline emissions. 

Table 2: Categorical Fuel/Material Hierarchy 

Rank Fuel Category 

1 Coal/Fossil Solid 

2 Bagasse 

3 Wet Biomass 

4 Dry Biomass 

5 Heavy Liquids 

6 Light Liquids 

7 Process Gases 

8 

Natural Gas, Refinery Gas, 

& Other On-Spec Gaseous 

Fuels 
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Rank Fuel Category 

9 Waste 

For baseline purposes, petroleum coke and tire derived fuel were included in the 

Coal/Fossil Solid category. Any unspecified type of biomass was assumed to be dry biomass. 

The liquid fuel categories encompass both fossil- and non-fossil-derived fuels in liquid form, 

such as stripper condensate. Emission data from tests conducted while combusting wastes were 

not included in baseline calculations. Fuels considered as waste were defined based on the final 

definition of solid waste as per the Identification of Non-Hazardous Materials That Are Solid 

Waste rulemaking.6

2.4 Control Device Categories 

Control devices reported in the Questionnaire were categorized according to their ability 

to remove certain types of pollutants. Because certain control devices target different types of 

pollutants, the pollutants themselves were first categorized into groups. Table 3 shows the 

groupings created for these pollutants. 

Table 3: Pollutant Groupings 

Category Constituent Pollutants 

Inorganic HAP and SO2

HCl HF 

Cl2 SO2

Mercury (Hg) Hg 

Particulate Matter (PM) Filterable PM 

Non-Mercury Metallic HAP 

Sb As 

Be Cd 

Cr Co 
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Category Constituent Pollutants 

Pb Mn 

Ni Se 

TSM8 TSM10 

Organic HAP and CombustionBased Pollutants 

CO NOx

THC VOC 

Formaldehyde 

Dioxins/Furans TEQ D/F 

Control devices were reported in many separate sections in the Questionnaire. All 

control device data reported with the emission test and CEMS data, as well as in the Data: 

Control Device table in the Survey Database, were identified for each combustion unit. Each 

control configuration reported for a boiler or process heater was further categorized to reflect 

only the control device or devices that are effective at removing any of the pollutants in Table 3. 

Control devices that have little or no effect on any of the pollutants listed in Table 3 were 

classified as having no control equipment installed. For example, selective catalytic reduction 

(SCR) is not effective in reducing the concentration of any pollutants listed in Table 3. Thus, 

any combustion unit that employed SCR was classified as having no air pollution control device 

(APCD). Similarly, if a combustion unit reported a control configuration of an electrostatic 

precipitator coupled with SCR, the “total baseline control” was standardized to “Electrostatic 

Precipitator.” Further, if a unit reported more than one control device that was effective at 

removing a particular pollutant, the most efficient control device was included in the “total 

baseline control.” For example, if a unit reported a multiclone and electrostatic precipitator, the 

total baseline control was standardized to “Electrostatic Precipitator.” 

These standardized control configurations were classified into groups based on their 

effectiveness in the removal of the pollutants listed in Table 3. Control groups were created for 

Inorganic HAP and SO2, Metallic HAP, Mercury, and Particulate Matter. Because add-on 

control technologies reported in the Questionnaire do not achieve reductions in dioxin/furan, 
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organic HAP, CO, or THC, no control groups were assigned to the Organic HAP group. For 

each group of pollutants, control devices were ranked according to their effectiveness and 

assigned to a group. The lowest numbered groups represent the best-performing controls for a 

particular set of pollutants. For example, a wet scrubber is recognized to be the most effective 

control device at removing acid gases in the Inorganic HAP and SO2 group. Thus, a wet 

scrubber would be assigned to “Control Group 1” for those pollutants. A wet scrubber is also 

expected to remove modest amounts of particulate matter and metallic HAP, and it was assigned 

to “Control Group 3” for the Metallic HAP group, behind spray dryer/fabric filter and spray 

dryer/electrostatic precipitator control configurations. A list of the standardized “total baseline 

control” configurations and their groupings for Inorganic HAP and SO2, Mercury, Particulate 

Matter, and Metallic HAP can be found in Tables B.2.A through B.2.D, respectively, of 

Appendix B. 

The total baseline control for each unit’s test data was compared to the total level of 

control currently installed on the unit, as reported in the 2008 Questionnaire or subsequent data 

submittal. It was found that several facilities reported emissions testing data for control 

configurations that do not accurately depict the current level of control employed by the unit. 

The test data with outdated controls were disregarded from the baseline analysis. A summary of 

these control discrepancies can be found in another memorandum.7

2.5 Combustor Designs 

Because the formation of organic HAP is influenced by the design of a combustion 

chamber, boilers and process heaters firing solid fuels were classified according to combustor 

design. Combustor design categories depended on the fuel category to which the unit was 

assigned. Table 4 lists the combustor design subcategories within each fuel category. 

Table 4: Combustor Designs 

Fuel Category Combustor Designs 

Coal/Fossil Solid 

Fluidized Bed 

Pulverized Coal 

Stoker/Sloped Grate/Other 
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Fuel Category Combustor Designs 

Bagasse, Wet Biomass, and 

Dry Biomass 

Fluidized Bed 

Dutch Oven/Pile Burner 

Combination Suspension/Grate 

Suspension Burner 

Fuel Cell 

Stoker/Sloped Grate/Other 

Residual/Heavy Liquids N/A 

Distillate/Light Liquids N/A 

Process Gases N/A 

Natural Gas, Refinery Gas, 

& Other On-Spec Gaseous 

Fuels 

N/A 

Stoker boiler designs include spreader stokers, overfeed stokers, and mass feed stokers. 

These boilers feed fuel to a grate, and forced air and combustion controls coordinate the air and 

fuel supply to the boiler. Pulverized coal boilers pulverize the coal down to a powder and then 

inject the powdered fuel and air into the combustion chamber, where the fuel combusts in 

suspension. Both Dutch ovens and suspension burners are often designed to handle fuels with 

moderately higher moisture contents (e.g., logging and timber residue, bagasse). In Dutch ovens, 

the fuel is distributed onto grates, and air flows up through the grates to provide oxygen for 

combustion, cool the grates, and dry the fuel. Underfire air partially burns the fuel, and then 

combustion of the volatile gases is completed in a secondary chamber. West Virginia University 

conducted two surveys and found that pile burners most closely resemble dutch ovens, and thus 

those two combustor types have been included in the same design subcategory.8

 For suspension 

burners, fuel particles are combusted after being pneumatically suspended in an airstream. Fuel 

cells first inject biomass into a char furnace for gasification. The char furnace gas is then passed 
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through a catalytic oxidizer and fed to the cathode side of the fuel cell. The ionized gas reacts 

with oxygen fed to the anode side of the fuel cell to produce electricity, steam, or heat, while the 

effluent gas is combusted for thermal energy. 

Combination suspension/grate units contain both suspension and grate firing 

mechanisms. Biomass combusted in suspension/grate boilers, typically bagasse, has high 

moisture content and must be pre-dried before firing. Moisture content of the fuel affects the 

furnace heat release rate, volume of combustion zone, combustion efficiency, and excess air 

levels. The pre-dried biomass is first fired in suspension, and any remaining biomass that is not 

fully combusted falls to the grate where secondary combustion occurs. The first stage of 

combustion (suspension burning) dries out most of the remaining moisture so that what falls to 

the grate can be combusted efficiently. Biomass with a fuel content of 20 to 30 percent moisture 

typically does not need pre-drying.9

Combustion units were assigned to a combustor design based on the information reported 

in the Data: Unit Design/Operation table of the Survey Database as well as follow-up data 

corrections received from certain facilities, as described in another memorandum.10 If a unit did 

not enter combustor design information, or if the combustor design was reported as a type other 

than those listed above, it was placed in the Stoker/Sloped Grate/Other category, as stoker 

designs represent the majority of boilers and process heaters designed to burn biomass or coal. 

Some emission data represents more than one combustion unit. In these cases, the 

combustor design for each individual combustion unit was reviewed. If all of the units shared 

the same combustor design, that common combustor design was used to characterize the data. If 

the multiple combustion units represented multiple combustor designs, the data was not used for 

baseline calculations because it did not belong to any combustor design subcategory. Instead, its 

combustor design category was labeled as “Multiple Combustor Designs.” 

Sometimes a combustion unit reported more than one type of combustor design in the 

Survey Database, and a hierarchy was used to classify that unit in one of the combustor design 

categories. For solid fossil units, the hierarchy was pulverized coal units, followed by fluidized 

beds and then stokers. Other designs not classified as pulverized coal, stoker, or fluidized bed 

were included in the stoker design category. For biomass units, the hierarchy was fluidized bed, 

followed by dutch oven/pile burners, suspension/grate units, suspension burners, fuel cells, and 

then stokers (including sloped grate). Other designs not classified as one of the designs in the 
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hierarchy were included in the stoker category. 

3.0 DEVELOPMENT OF UNIT-SPECIFIC EMISSION FACTORS

Before an average baseline emission factor could be developed for a particular pollutant, 

each combustion unit was first assigned its own unit-specific emission factor, where data were 

available. The process of assigning unit-specific emission factors is discussed in this section. 

3.1 Selecting the Data Source for Unit-Specific Data Averages 

Emission data were reported in several sections of the 2008 Combustion Survey. Some 

sources reported additional emission data under the 2009 Phase II ICR Test Plan and/or 

supplemental data from public comments. Only emission data that could be standardized to 

common units of measured were used to determine unit-specific emission factors. The 

procedures used to standardize emission data are discussed in another memorandum.4

 

Standardized emission test data, CEMS monitoring data, and fuel analysis data were averaged 

for each boiler reporting these data. For units reporting multiple types of emission data, Table 5 

shows the hierarchy for determining which data source was used as the basis for the baseline 

emissions at the boiler or process heater. 

Table 5: Hierarchy for Determining Unit-Specific Baseline Emission Factors 

Rank Condition 

1 If a unit had emission test averages and CEMS data averages, and the values 

were within the same order of magnitude, CEMS and emission test averages 

were averaged together. 

2 If a unit had emission test and CEMS data averages, and the values were not 

within the same order of magnitude, only the emission test average was used. 

3 If a unit had only an emission test average, that value was used. 

4 If a unit had only CEMS data, the average of the reported CEMS data was used. 

5 

If an uncontrolled unit designed to burn liquid fuels had no emission test or 

emission monitoring data but reported fuel analysis data for metallic HAP, 

mercury, or chlorine (standardized to hydrogen chloride), the average of all the 

standardized fuel analysis data in the unit’s fuel category (light or heavy liquid) 

was assigned as the unit’s baseline emission factor. 
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Rank Condition 

6 

Facility-level averages were generated for each pollutant based on a common 

fuel category, control category, and combustor design. Boilers or process 

heaters without unit-specific emission test or CEMS data were assigned the 

facility-level average for the same fuel, control, and design. 

7 Boilers or process heaters with non-detect emission test data that could not be 

standardized received the average of all non-detect data for that pollutant. 

8 

The remaining boilers or process heaters with no emission test or CEMS data, as 

well as liquid-fired units with no fuel analysis data, were not assigned a unitspecific emission factor and were assigned to an average baseline emission 

factor, as discussed in Section 4. 

3.2 Assigning Appropriate Fuels and Control Devices 

Similar to how unit-specific emission factor values came from different data sections of 

the survey, fuel and control device data were often reported in multiple sections of the survey. 

Tables 6 and 7 show the hierarchies used to determine the fuel and control device, respectively, 

for each unit-specific emission factor. 

Table 6: Hierarchy for Determining Fuels for Unit-Specific Emission Factors 

Rank Source 

1 

If emission test or CEMS data were available, the fuels reported during these 

tests or monitoring periods were used. Tests on multiple fuels or control 

configurations were assigned separate record identifiers, as discussed in Section 

3.1.1. 

2 Small, gas-fired units (as defined in Section 2.2 above) located at refineries 

(NAICS code 324) were assumed to be combusting refinery gas. 

3 The remaining small, gas-fired units (as defined in Section 2.2 above) were 

assumed to be combusting natural gas. 

4 A combination of all fuels listed as being routinely combusted for that specific 

combustion unit, as listed in the Data: Materials Combusted table of the Survey 

Database. 

5 The fuel associated with the design capacity of the combustion unit, as listed in 

the Data: Unit Design/Operation table of the Survey Database. 

6 

A combination of all fuels listed as being combusted for that specific facility, as 

listed in the Data: Fuel Analysis Background Information table of the Survey 

Database. 
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Table 7: Hierarchy for Determining Control Devices for Unit-Specific Emission Factors 

Rank Source 

1 

If emission test or CEMS data were available, the control devices reported to be 

installed during these tests or monitoring periods were used. Tests on multiple 

fuels or control configurations were assigned separate record identifiers, as 

discussed in Section 3.1.1. 

2 

A combination of all current control devices reported to be installed on the 

combustion unit, as listed in the Data: Control Device table of the Survey 

Database. 

3 If no control device information was reported for a combustion unit, it was 

assumed to have no add-on control devices. 

4 

Because cyclones are often considered integral equipment to a boiler and not an 

add-on control device, units combusting coal and/or biomass that did not report 

having any controls installed were assumed to have a cyclone installed for 

metallic HAP and particulate matter control. The “total baseline control” 

category for these units remained classified as having no HAP control, but solid 

fuel boilers without reported controls and with cyclone/multiclone reported 

controls assigned to the same control group for metallic HAP and particulate 

matter. 

After the preferred data source for fuels combusted and control devices installed were 

determined, the reported fuels were assigned to fuel categories described in Section 2.3, and the 

reported control devices were assigned to control groups, as described in Section 2.4. These 

categories allowed baseline emission factors to be developed for each combination of fuel and 

control device. 

Several times, combustion units reported different fuel and control configurations 

associated with emission data than the controls and fuels reported with monitoring data. In these 

cases, the fuel and control device data from both sources were reviewed, and the data deemed 

most representative of current operations were assigned to the unit. Routinely combusted fuels 

were reported in the Data: Materials Combusted table of the Survey Database. Current control 

device data were reported in the Data: Control Device table of the Survey Database. The fuel 

and control information reported with the testing and monitoring data were compared to these 

tables to determine the most representative fuel and control configuration. Emission and 

monitoring data for alternate fuel or control configurations at the unit were not considered when 

calculating a unit-specific baseline emission factor, but they were included when calculating 

average baseline emission factors for units with similar fuel and control device configurations. 
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3.3 Emission Test and CEMS Data Averages 

Emission data averages were created using the standardized data in the Data: Emissions 

Test and Data: CEMS tables of the Emission Database. If a unit reported the results of a stack 

test to be non-detect, the detection limit was used as the basis for the average. Emission test data 

were available for all pollutants listed in Table 3 of this memorandum. Monitoring data was 

reported in the Survey Database on a daily average basis for CO, SO2, NOx, and Filterable PM. 

Hourly CEMS data was reported in the Survey Database for CO, NOx, and THC. Facilities were 

unable to report emission monitoring data as non-detect in the Survey Database because the 

template to enter CEMS data required a numerical value. 

Many combustion units reported emission test information for multiple fuel and control 

configurations. For example, some units reported control configurations that represent current 

control configurations presently installed on the unit, as well as control device configurations 

that were installed prior to complying with the 2004 vacated NESHAP for Industrial, 

Commercial, and Institutional Boilers and Process Heaters. Other units that tend to operate on 

multiple fuel types may have reported multiple stack tests; for example, one unit may have 

reported a test based on firing natural gas and another reported a test while firing fuel oil. To 

appropriately group emission test and monitoring data, a record identifier was created to 

distinguish between different combinations of fuel and control device configurations. 

Next, the average (mean) of all the emission test runs with the same record identifier was 

calculated. Default values that incorporate measurement error, based on the reported span values 

were used as the basis for baselines for CO and THC emission test data. The development of 

default values and calibration span values for those pollutants is described in another 

memorandum.11 For combustion units with only one fuel and control device combination, the 

record number was assigned as “1.” For combustion units with multiple combinations of fuel and 

control device configurations, additional record numbers were assigned. For example, if a 

combustion unit with a wet scrubber reported two emission tests, one burning coal and the other 

burning oil, two record identifiers were given. The coal/wet scrubber combination was assigned 

a record number of “1,” whereas the oil/wet scrubber combination was assigned a “2.” The 

maximum number of record identifiers assigned to a combustion unit was four, representing four 

unique combinations of fuel type and control device configurations. 

An average (mean) of all the monitoring data with the same record identifier was also 
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calculated. For most sources, this was a 30-day average, but some sources reported multiple 30-

day periods in the Survey Database. For combustion units that reported both emission test and 

monitoring data with similar fuel and control configurations, the same record identifier was used 

for both sets of data to allow the two datasets to be averaged, when deemed appropriate. The 

calculated means for the emission test and monitoring data were compared, and if the mean of 

each dataset was on the same order of magnitude, the emission test and emission monitoring data 

were averaged together and assigned to the unit-specific baseline emission factor. If the 

emission test and emission monitoring data were not of the same order of magnitude, only the 

average emission test data were used to establish baseline emissions for the unit. An order of 

magnitude was defined to be within a factor of 10. 

3.4 Fuel Analysis Data Averages 

The process of standardizing mercury and chlorine fuel analysis concentrations into 

standardized emission factors is discussed in another memorandum.4

 Fuel analysis data from 

uncontrolled liquid fuels were standardized for chlorine (converted to HCl), Hg, and other metals 

(Sb, As, Be, Cd, Cr, Co, Pb, Mn, Ni, Se). Because these HAP are fuel-based contaminants and 

not products of combustion, the constituents within the fuel are expected to be emitted in the 

exhaust gas. 

Because the liquid fuels are often delivered to a facility and used in multiple combustion 

units at the facility, fuel analysis data were reported in the Survey and Emission Databases at the 

facility level. As a result, unit-specific emission averages could not be generated. Instead, a list 

of uncontrolled combustion units designed to burn liquid fuels and that also reported combusting 

liquid fuels as per Section 2.3 above was developed from the Survey Database. Next, all of the 

fuel analysis data for liquid fuels at facilities with an uncontrolled liquid unit were identified and 

classified as either heavy or light liquids according to Table B.1 of Appendix B of this 

memorandum. Because purchased liquid fuels, such as fuel oils 1 through 6, are subject to 

ASTM specifications and are expected to be relatively homogenous from delivery to delivery, 

fuel analysis averages were not calculated for a specific facility or unit. Instead, each 

uncontrolled liquid unit was assigned to an average baseline emission factor that was calculated 

by taking the mean of all the standardized fuel analysis data for bio liquids, diesel fuel, jet fuel, 

kerosene, and #2 and #4 oil for units in the light liquid fuel category, and the mean of all 
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standardized fuel analysis data for black liquor, #5 and #6 oil, rectified methanol, red oil, and onspec used oil for units in the heavy liquid category. For example, facilities A and B each have an 

uncontrolled unit combusting distillate liquid fuel, and each facility also reported fuel analysis 

data for chlorine. Both combustion units would have each been assigned the same HCl fuel 

analysis average generated for light liquids. 

Some fuel analysis data were reported as a mixture of fuels. If a liquid fuel was reported 

as a mixture, the corresponding data were only used if each of the reported fuels was from the 

same liquid category. For example, fuel analysis data from a reported fuel combination of “No. 

2 Distillate/Diesel fuel” would have been used, whereas data from a combination of “No. 2 

Distillate/No. 6 Residual oil” would not have been used. Fuel analysis data for any type of 

sludge or other process-specific fuel was not used to calculate fuel analysis averages. 

3.5 Facility-Level Emission Averages

Only emission test data was considered for facility-level averages. Each of the emission 

test averages described in Section 3.3 of this memorandum were further averaged across each 

facility based on a common fuel category and either control category or combustor design, based 

on the pollutant. Organic HAP, CO, and TEQ dioxin/furan emissions were averaged based on 

fuel and combustor design; all other pollutants were averaged on fuel and control category. 

Boilers or process heaters with no emission test or CEMS data were assigned the facilitylevel average where the fuel category and either control or combustor design matched. If the 

unit without emission test or CEMS data was a unique unit and there were no other similar units 

at the facility, the unit did not receive the facility-level average. Facility-level emissions from 

similarly designed units provided a more accurate depiction of baseline emissions for similar 

boilers or process heaters without unit-specific data, because these units were expected to have a 

common fuel source. 

4.0 DEVELOPMENT OF AVERAGE BASELINE EMISSION FACTORS

For units that did not report emission test, CEMS, or fuel analysis data, and could not be 

assigned a facility-level average or a non-detect average for one of the pollutants in Table 1, 

average baseline emission factors were developed using data from other boilers and process 
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heaters with similar controls, fuels, and combustor designs. In several cases, it was possible for 

certain pollutants to be based on unit-specific data (where data was reported), and the data gaps 

not reported were filled with average baseline emission factors. The process of identifying data 

suitable for use in an average baseline emission factor and calculating the average baseline 

emission factors is discussed in this section. 

4.1 Baseline Criteria

Baseline averages were developed to represent emissions from units firing similar fuel 

types that have similar control devices. Any emission test or emission monitoring data reported 

in the Survey Database when combusting any amount of waste material were not included in 

baseline average calculations. Fuel analysis data for liquid wastes, or fuel analysis data that were 

reported for a combination of liquid fuels and waste, were not used in baseline average 

calculations. A list of reported fuels considered to be waste during the development of baseline 

emission factors can be found in Table B.1 of Appendix B. 

4.2 Development of Averages 

To calculate an average baseline emission factor for each pollutant, all unit-specific 

emission factors assigned in Section 3.0 were averaged for similar groups of controls, fuel types, 

and combustor designs. Because inorganic HAP and SO2, metallic HAP, Hg, and PM are fuelbased HAP that can be controlled with add-on pollution control devices, the unit-specific 

emission factors were averaged across all units with a common fuel category and control group. 

Formaldehyde, NOx, and CO are combustion-based pollutants, and their emissions are influenced 

by the design of the combustion chamber. Further, emissions of NOx and CO can be affected by 

NOx controls such as low-NOx burners, overfire-air, or flue gas recirculation. As a result, the 

unit-specific emission factors were averaged across all units with a common fuel category, 

combustor design, and NOx control configuration. Baseline averages for THC and TEQ D/F are 

also driven primarily by the design of the combustion chamber, and the unit-specific emission 

factors were averages across all units with a common fuel and combustor design category. 

Based on the data reported under Phase II, emissions of THC and TEQ D/F at units firing natural 

gas and refinery gas differed significantly depending on whether the unit was equipped with NOx

controls, so baseline emission factors for THC and TEQ D/F at these gas-fired units were 
18

established by averaging data from other gas-fired units with similar NOx control configurations. 

4.3 Filling Data Gaps 

After calculating average emission factors for each of the pollutants in Table 1 for the 

unique combinations of fuels, control devices, and combustor designs, there were some 

pollutants that did not have any emission data available to calculate an average baseline emission 

factor. For inorganic HAP and SO2, metallic HAP, Hg, and PM, control efficiencies were 

assigned to the control groups based on literature available on the pollutant removal efficiencies 

of various control devices. A list of the pollutant-specific percent reductions can be found in 

Appendix C. The percentages listed in Appendix C are the expected reductions a given control 

device could achieve compared with the level of emissions without control devices installed. 

There were no data gaps for the organic HAP pollutants for liquid fuels or units burning natural 

gas, refinery gas, or other on-spec gaseous fuels. The average baseline formaldehyde emissions 

for process gas units without NOx control were approximated to be equivalent to the average 

baseline formaldehyde emissions for process gas units with NOx control. The average baseline 

THC and TEQ D/F emissions from suspension burners combusting dry biomass were 

approximated using the average emissions from stokers combusting dry biomass. Data gaps for 

fluidized bed units and stokers with NOx control burning dry biomass were filled using the 

baseline emissions for stokers without NOx control burning dry biomass. Baseline 

formaldehyde emissions for suspension burners with NOx control burning dry biomass were 

approximated using the baseline formaldehyde emissions for suspension burners without NOx 

control burning dry biomass. Data gaps in the Bagasse fuel category were filled using the Wet 

Biomass averages from the same subcategory because Bagasse is considered to be a very wet 

type of biomass. Data gaps in the suspension/grate subcategory were filled using the Wet 

Biomass averages from the stoker category. The baseline values for CO, TEQ D/F, 

formaldehyde, and NOx, at fuel cell boilers firing bagasse fuels reflect an older version of the 

wet biomass fuel cell baseline emission factors before additional data updates were made. The 

CO baseline emission factor should have been 782 ppm @ 3% O2, but the older value used in all 

analyses was 801.2 ppm @ 3% O2. The difference in these two baseline values is minimal and 

both values are below the MACT floor emission limit for the subcategory so it does not affect 

the estimated impacts on emission reductions or costs. The TEQ D/F baseline emission factor 
19

should have been 0.008 ng/dscm @ 7% O2, but the older value used in all analyses 

was 0.007 ng/dscm @ 7% O2. The formaldehyde baseline emission factor should have 

been 1.656 ppm @ 3% O2, but the older value used in all analyses was 0.300 ppm @ 3% O2. 

The NOx baseline emission factor should have been 116.1 ppm @ 3% O2, but the older value 

used in all analyses was 107.6 ppm @ 3% O2. NOx, formaldehyde, and TEQ D/F were not 

included in the emission reduction impacts. 

Baseline formaldehyde emissions for units firing process gas without NOx control were 

approximated using the baseline formaldehyde emissions for process gas units with NOx control. 

4.4 Review of Outlier Data 

After baseline emission factors were developed for each possible subcategory, the 

average values were reviewed to look for uncharacteristically high or low values. Unexpectedly 

high or low values were flagged, and the individual data points that comprised the average were 

investigated. An example of a flagged value for a given pollutant would be if the uncontrolled 

baseline emission factor was lower than that of any other control group for that same pollutant 

and the same fuel category. 

The unit-specific averages were inspected for these flagged values to determine if a 

problem existed with any of the reported data used in the average. Data were disregarded from 

the analysis when errors were identified in units of measure, fuels burned, or control devices 

installed. In addition, if emission monitoring data was reported during periods of start-up, 

shutdown, or malfunction, these data were excluded from the analysis. When possible, changes 

were made to the reported data in the Emission Database, and the updated values were used to 

recalculate baseline emission factors. If reported data was identified as an outlier, it was not 

used in the average baseline emission calculations but was used for a unit’s site-specific baseline 

emission factor. 

In addition to reviewing the average baseline values for outliers, the full range of unitspecific emission data was also reviewed to identify any uncharacteristically high or low values 

that could over or underestimate the expected emission reduction estimates associated with this 

proposal. 

4.5 Establishing Baseline Emissions for PM2.5 and VOCs 
20

Baseline emission factors for particulate matter less than 2.5 microns (PM2.5) were 

estimated as a percentage of filterable PM baselines. PM2.5 is a select portion of total filterable 

PM based on particle size, so it is correct to assume that a portion of total filterable PM will 

always be PM2.5. The ratios of PM2.5 to total filterable PM were based on reported emission test 

data for both pollutants, and were specific to fuel types and control devices. The fractions of 

PM2.5 ranged from 0.07 to 1. Details on the fractions for each fuel and control device group are 

presented in Appendix D-3. Using the fuel category and control device configuration assigned to 

each unit, a baseline emission factor for PM2.5 was estimated by multiplying the appropriate 

PM2.5 fraction by the filterable PM baseline emission factor assigned to the unit. 

Similar to the method used to generate PM2.5 baseline emission factors, VOC emission 

factors were generated as a portion of THC baseline emissions. Monitoring data reported from 

Phase II Test Plan was used to calculate an average (mean) VOC-to-THC ratio that could be 

applied to all THC baseline emission factors. Only data from Phase II Test Plan was used 

because it was the only source of data that correlated THC and VOC data points over a multi-day 

period. VOC ratios were not calculated for each subcategory because there were only data 

available for six total boilers and process heaters. A VOC-to-THC ratio was generated for each 

monitoring data point that was not noted to be during a period of start-up, shutdown, or 

malfunction. A statistical quartile analysis was performed on the set of ratios to remove any 

outliers. The remaining ratios were then averaged to obtain a total VOC-to-THC ratio, which 

was applied to each THC baseline emission factor subcategory. It was assumed that this ratio 

would not fluctuate between different fuel categories or control devices. Based on monitoring 

data available from these six sources, THC emissions are composed of 57 percent VOCs. The 

data used to calculate this percentage is presented in Appendix D-4. 

4.6 Establishing Baseline Emissions for Toxic Equivalent Dioxins/Furans 

Baseline emission averages for TEQ D/F were calculated differently than the rest of the 

pollutants due to the way dioxin/furan data was reported in the Emission Database. Facilities 

were able to report a total mass emission value or total mass values for 17 individual 

dioxin/furan congeners and a group of “other congeners.” Each congener has a toxic 

equivalency factor (TEF), a unit-less weighting factor that equates the emissions of each 

congener to 2,3,7,8-TCDD based on relative toxicity. Table 8 lists the dioxin/furan congeners 
21

and their respective TEF used to calculate dioxin/furan emissions. 

Table 8: Dioxin/Furan Congeners and Toxic Equivalency FactorsA

Congener TEF Congener TEF 

1,2,3,4,6,7,8 HpCDD 0.01 1,2,3,7,8,9 HxCDD 0.1 

1,2,3,4,6,7,8 HpCDF 0.01 1,2,3,7,8,9 HxCDF 0.1 

1,2,3,4,7,8 HxCDD 0.1 2,3,4,6,7,8 HxCDF 0.1 

1,2,3,4,7,8 HxCDF 0.1 2,3,4,7,8 PeCDF 0.3 

1,2,3,4,7,8,9 HpCDF 0.01 2,3,7,8-TCDD 1 

1,2,3,6,7,8 HxCDD 0.1 2,3,7,8-TCDF 0.1 

1,2,3,6,7,8 HxCDF 0.1 Octa- CDD 0.0003 

1,2,3,7,8 PeCDD 1 Octa- CDF 0.0003 

1,2,3,7,8 PeCDF 0.03 Other Congeners 0 

AWorld Health Organization (WHO) toxic equivalency factors from 2005. 

Only Phase II Test Plan data was used to generate dioxin/furan averages because Phase I data 

was not received for individual congeners. The total mass emission values of each congener 

were multiplied by the appropriate TEF in order to get a TEQ mass emission. The TEQ values 

for each congener and each emission test run were summed in order to get a total TEQ 

dioxin/furan emission value. These sums were then averaged to generate average total TEQ 

dioxin/furan emissions per test. These TEQ averages were used as unit-specific emission factors 

for their respective combustion units. TEQ emission values could only be generated for boilers 

or process heaters that reported dioxin/furan data on the congener level; some facilities only 

reported an overall total mass dioxin/furan emission value, which could not be converted to a 

TEQ value. To calculate average baseline emission factors, these test averages were averaged 

across units in the same fuel and combustor design. Baseline emission factors for TEQ D/F for 

major and area sources are presented in Appendices D-1 and E, respectively. 
22

Although baseline emissions of TEQ D/F are shown in Appendix D, these estimated 

baselines are based on data that include a large number of detection limits. The resultant 

baselines are likely overestimating TEQ D/F emissions by an unknown amount since the 

majority of the data were reported to be measured below detection levels. 

5.0 BASELINE AVERAGES FOR AREA SOURCES 

Although a small number of area source facilities with boilers and process heaters 

reported emission data in the Survey Database, there were not sufficient data available to create a 

separate set of baseline emission averages for area source boilers. Instead, the average baseline 

emission factors calculated for major source boilers and process heaters were used to establish 

the baseline emissions from area source model units used to estimate the impacts of the 

promulgated rule. 

5.1 Controls for Area Sources

Data available in the Survey Database, Title V permits for area source boilers, and data 

from the National Forest Service Fuels for Schools program, indicates that most boilers at area 

sources are uncontrolled.1,12 Furthermore, the distribution of control devices on solid fuel area 

source boilers units in Pennsylvania and Wisconsin indicate that 8 percent of wood/biomass 

boilers greater than 10 MMBtu/hr in these two states do not have any listed control, and the other 

92 percent have an mechanical collector (e.g., multiclone, cyclone) control device installed. 

Moreover, 53 percent of coal boilers in Pennsylvania do not have any listed control. The 

remaining boilers firing solid fuels at area sources have a mechanical collector control device. 

Using this information on control devices, we assigned average baseline emission factors for the 

area source model units according to Table 9 below. 

Table 9: Baseline Emission Factor Assignments to Area Source Boilers 

Area 

Source 

Model 

Unit 

Pollutant Type Corresponding Major Source Baseline 

Emission Factor Category 

Biomass Fuel-based pollutantsA Average of wet and dry biomass for 

cyclone/multiclone controlled 
23

Area 

Source 

Model 

Unit 

Pollutant Type Corresponding Major Source Baseline 

Emission Factor Category 

Combustion-based pollutantsB Average of wet and dry biomass stokers with 

NOx control 

Coal 

Fuel-based pollutantsA Cyclone/multiclone controlled coal 

Combustion-based pollutantsB Coal stokers with NOx control 

Residual 

Liquid 

Fuel- and combustion-based 

pollutantsA.B Uncontrolled heavy liquid 

Distillate 

Liquid 

Fuel- and combustion-based 

pollutantsA,B Uncontrolled light liquid 

A Fuel-based pollutants include: PM, Hg, metallic HAP, inorganic HAP, and SO2. B

 Combustion-based pollutants include: THC, CO, PCDD/PCDF, and formaldehyde.
24

6.0 REFERENCES 

1. Survey Database containing Results of the 2008 Questionnaire for Boilers, Process 

Heaters, & Other Combustion Units (ICR No. 2286.01) (version 2). 

2. Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, & Fuel 

Analysis Data Reported under ICR No. 2286.01 & ICR No. 2286.03 (version 7). 

3. Eastern Research Group, Inc. Revised (November 2011) Data Dictionary for Boiler, 

Process Heater, and Other Combustion Unit Survey Databases. November 2011. 

4. Eastern Research Group, Inc. Revised (November 2011) Standardization of Reported 

Data from the Questionnaire for Boilers, Process Heaters, Incinerators and Other 

Combustion Units. November 2011. 

5. U.S. Environmental Protection Agency. 2008 Questionnaire for Boilers, Process 

Heaters, Incinerators and Other Combustion Units (ICR No. 2286.01, OMB Control No. 

2060-0616, EPA Form No. 5900-122). 

6. U.S. Environmental Protection Agency. Identification of Non-Hazardous Secondary 

Materials That Are Solid Waste; Final Rule. Federal Register vol. 76, No. 54. March 21, 

2011. 

7. Eastern Research Group, Inc. Revised MACT Floor Analysis (November 2011) for the 

Industrial, Commercial, Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source. November 2011. 

8. Hutchinson, V., et. al., Appalachian Hardwood Center. Overview of Wood-Fired Boiler 

Use in West Virginia. April, 1998. Available on-line at: 

<http://www.wvu.edu/~agexten/forestry/fact16.pdf> 

9. Public comment received from Golder Associates Inc. See document number EPA-HQOAR-2002-0058-2801.1 in the docket for National Emission Standards for Hazardous 

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

Process Heaters. 

10. Eastern Research Group, Inc. Handling and Processing of Corrections and New Data in 

the EPA ICR Databases – Revised November 2011. November 2011. 

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

Monoxide (CO) Data (Revised November 2011). November 2011. 

12. Hinckley, John, Q.E.P. 2008 Stack Test Review. July, 2008. 
25

APPENDIX A 

GLOSSARY 
26

Table A.1: Glossary

Term Description 

APCD Air pollution control device. An add-on exhaust stack technology 

that reduces the concentrations of HAP in exhaust gas. 

Btu British thermal unit. A unit of measurement for energy. 

CO Carbon monoxide. A common pollutant produced due to the 

incomplete combustion of carbonaceous fuel. 

HAP Hazardous air pollutant. See Table 1 for a list of all HAP associated 

with this rulemaking effort. 

Hg Mercury. This abbreviation is used to refer to both the mercury 

pollutant itself as well as the pollutant group created for it. 

Inorganic A pollutant category that is comprised of the pollutants hydrogen 

chloride (HCl), hydrogen fluoride (HF), and chlorine (Cl2). 

LPG Liquefied petroleum gas. A hydrocarbon fuel derived from 

petroleum, stored under pressure in the liquid phase. 

Metallic HAP A pollutant category that is comprised of the pollutants antimony 

(Sb), arsenic (As), beryllium (Be), cadmium (Cd), chromium (Cr), 

cobalt (Co), lead (Pb), manganese (Mn), nickel (Ni), and selenium 

(Se). 

MMBtu/hr One million British thermal units per hour. A unit of measurement 

for thermal energy. 

NOx Nitrogen oxides. A grouping of binary compounds composed of the 

elements nitrogen and oxygen, including nitric oxide (NO), nitrogen 

dioxide (NO2), nitrous oxide (N2O), dinitrogen trioxide (N2O3), 

dinitrogen tetroxide (N2O4), and dinitrogen pentoxide (N2O5). 

Organic An organic compound is characterized as any compound containing 

carbon, not including carbonates, carbon oxides, cyanides, and 

allotropes of carbon. For this analysis, organic refers to a pollutant 

category that is comprised of the pollutants formaldehyde, volatile 

organic compounds (VOC), and total hydrocarbons (THC). 

PCDD/PCDF Polychlorinated dibenzodioxins and polychlorinated dibenzofurans. 

A grouping of congener compounds produced from the combustion 

of chlorinated fuels. See Table 8 for a list of PCDD/PCDF congeners 

and their associated toxic equivalency factors (TEF). 

PM Filterable particulate matter (all sizes). 

PM2.5 A portion of total filterable particulate matter consisting of particles 

less than or equal to 2.5 μm in diameter. 

SO2 Sulfur dioxide. A common pollutant produced from the combustion 

of fuels with high sulfur content. 
27

Term Description 

TEF Toxic equivalency factor. A unit-less weighting factor specific to 

each PCDD/PCDF congener based on relative toxicity compared to a 

target congener. When the total mass emission value of a congener is 

multiplied by its TEF, the emission value is converted into an 

equivalent mass emission of the congener 2,3,7,8-TCDD. 

TEQ An alternative method for quantifying the toxicity of dioxin/furan 

congeners relative to the congener 2,3,7,8-TCDD. TEQ values used 

in this analysis are based on the 2005 World Health Organization 

toxic equivalency factors. 

THC Total hydrocarbons. Refers to the total sum of hydrocarbon 

compounds emitted during an emission test, standardized using 

propane as the reference compound. 

TSM8 Sum of eight selected metallic HAP, including arsenic (As), 

beryllium (Be), cadmium (Cd), chromium (Cr), lead (Pb), manganese 

(Mn), nickel (Ni), and selenium (Se). 

TSM10 Sum of ten selected metallic HAP, including antimony (Sb), arsenic 

(As), beryllium (Be), dadmium (Cd), chromium (Cr), cobalt (Co), 

lead (Pb), manganese (Mn), nickel (Ni), and selenium (Se). 

VOC Volatile organic compound. Any compound of carbon, excluding 

carbon monoxide, carbon dioxide, carbonic acid, metallic carbides or 

carbonates, and ammonium carbonate, which participates in 

atmospheric photochemical reactions. 
28

APPENDIX B 

Fuel and Control Device Groupings 
29

Table B.1: Fuel Category Constituents 

Rank Fuel Category Inclusive Fuels 

1 Coal/Fossil Solid 

Anthracite Coal 

Bituminous Coal 

Fly Ash 

Nitrile pitch residue 

Petroleum Coke 

Sub-bituminous Coal 

Tire Derived Fuel (TDF) with metals removed 

Wax 

2 Bagasse Bagasse 

3 Wet Biomass 

Black Liquor 

Dewatered Combustible Residues 

Hog Fuel 

Hydro pulper refuse 

Industrial Sludge 

Knots and Knotter Rejects 

Wood: Bark 

Wood: Unadulterated Lumber 

Wood: Unadulterated Timber 

Unspecified Biomass1

4 Dry Biomass 

Paper and Paper Residues 

Paper Pellets 

Plant-based Agricultural Residue 

Sanderdust 

Wood: Plywood, Particleboard (containing glues or resins)
30

Rank Fuel Category Inclusive Fuels 

5 Residual/Heavy 

Liquids 

Alcohol: Ethanol 

Alternative Liquid Fuel 

Cleaning Water 

Deinking Residuals 

Glycerol Distillation Byproduct 

Heavy Recycle 

Hexane 

Mixed liquid residues 

No. 5 Fuel oil 

No. 6 Residual oil 

Other Petroleum-based Oils 

Process coproduct liquid 

Rectified methanol 

Red oil (steam stripper steam condensate, incl terpenes, 

terpenoids, methanol, TRS) 

Stripper condensate 

Tall oil, tall oil derivatives 

Turpentine 

Used Petroleum-based Oils (unknown spec) 

Used Petroleum-based Oils (on-spec) 

6 Distillate/Light 

Liquids 

Animal Fat/Oils/Tallow 

Bio liquids 

Diesel fuel 

Jet Fuel 

JP-8 Aviation Fuel 

Kerosene 

No. 2 Distillate 

No. 4 Fuel oil 

Vegetable Oil 

yellow grease (used cooking oil) 

7 Process Gases2 Blast Furnace Gas 

Coke Oven Gas 
31

Rank Fuel Category Inclusive Fuels 

8 Natural Gas, Refinery 

Gas, & Other OnSpec Gaseous Fuels2,3

Acid Gas 

Biogas 

CO gas 

Ethane 

Hydrogen 

Isobutane 

Landfill Gas 

LPG 

Methane 

Natural Gas 

Noncondensable Gas (includes stripper offgas) 

Petrochemical process gas 

Pilot Gas 

Process coproduct gas 

Process Gas 

Propane 

Pulp mill gas 

Refinery gas 
32

Rank Fuel Category Inclusive Fuels 

9 Waste4

1,4-butanediol 

Boiler Cleaning agents 

Cardboard 

Cellulose fuel (balcones cubes) 

Coal Refuse 

Construction/Demolition Derived Material (unless it has 

been specified to be sufficiently processed) 

Contraband 

Envirofuel pellets/cubes 

Filters 

Fuel cubes (paper diaper clippings/refuse) 

Municipal Sludge 

Oily Paper Residues 

Oily Rags 

Paint Rags/Residues 

Plastics 

Refuse 

Refuse Derived Fuel (RDF) 

Resin Solid Residues 

Screen Rejects 

Spent Alcohol 

Tar 

Tires (whole) 

Toluene 

Used Petroleum-based Oils (off-spec) 

Used Solvents 

Waste Derived Liquid Fuel 

Wood: Treated 

1

 Unspecified biomass was reported in the questionnaire as “Biomass” and was assumed to be wet unless the 

reported nomenclature by the facility indicated the biomass had low moisture content. 

2

 The listing of these gaseous fuels does not suggest that they all will or will not meet specification. Gases must be 

tested to ensure they meet the specification for mercury as described in the proposal. 3

 Metals furnaces treat natural gas before combustion causing an increase in the amount of some pollutants in the 

fuel. While the fuel is still natural gas, the chemical makeup of varies between metal furnaces and other types of 

combustion units. Resulting emissions are not comparable between metal furnaces and other units combusting 

traditional natural gas. 

4 These reported fuels were classified as waste per the final definition of waste as per the Identification of NonHazardous Materials That Are Solid Waste rulemaking. 
33

Table B.2.A: Inorganic and SO2 Control Groupings 

Control Group Control Device 

1 

Spray Dryer 

Wet Scrubber 

Wet Scrubber 

2 

Dry Scrubber 

Dry Scrubber (Lime Injection) 

Scrubber (unknown) 

3 

Dry Sorbent Injection 

Duct Sorbent Injection 

Furnace Sorbent Injection 

Wet Lime Injection 

Wet Sorbent Injection 

4 Venturi Scrubber 

5 

Activated Carbon Adsorption or Injection 

Cyclone or Multiclone 

Dry Electrostatic Granular Filter 

Electrified Filter Bed (EFB) 

Electrostatic Precipitator 

Fabric Filter 

Mist Eliminator 

No HAP APCD Control 

Wet Electrostatic Precipitator 
34

Table B.2.B: Mercury (Hg) Control Groupings 

Control Group Control Device 

1 Fabric Filer/Activated Carbon Adsorption or Injection 

2 

Fabric Filter/Dry Scrubber (Lime Injection)/SNCR 

Fabric Filter/Wet Lime Injection 

Fabric Filter/Dry Scrubber 

Fabric Filter/Dry Sorbent Injection 

Fabric Filter/Duct Sorbent Injection 

Fabric Filter/Furnace Sorbent Injection 

Fabric Filter/Spray Dryer 

Fabric Filter/Wet Scrubber 

3 Fabric Filter 

4 Wet Scrubber 

5 Venturi Scrubber 

6 

Cyclone or Multiclone 

Dry Electrostatic Granular Filter 

Dry Scrubber 

Dry Sorbent Injection 

Duct Sorbent Injection 

Electrified Filter Bed (EFB) 

Electrostatic Precipitator 

Mist Eliminator 

No HAP APCD Control 

Scrubber (unknown) 

Spray Dryer 

Wet Electrostatic Precipitator 
35

Table B.2.C: Particulate Matter (PM) Control Groupings 

Control Group Control Device 

1 Fabric Filter 

2 

Electrified Filter Bed (EFB) 

Electrostatic Precipitator 

Wet Electrostatic Precipitator 

3 Venturi Scrubber 

4 Wet Scrubber 

5 Cyclone or Multiclone 

Dry Electrostatic Granular Filter 

6 

Activated Carbon Adsorption or Injection 

Dry Scrubber 

Dry Sorbent Injection 

Duct Sorbent Injection 

Mist Eliminator 

No HAP APCD Control 

Scrubber (unknown) 

Spray Dryer 
36

Table B.2.D: Metallic HAP Control Groupings 

Control Group Control Device 

1 Fabric Filter 

2 

Electrified Filter Bed (EFB) 

Electrostatic Precipitator 

Wet Electrostatic Precipitator 

3 Venturi Scrubber 

4 Wet Scrubber 

5 Cyclone or Multiclone 

Dry Electrostatic Granular Filter 

6 

Activated Carbon Adsorption or Injection 

Dry Scrubber 

Dry Sorbent Injection 

Duct Sorbent Injection 

Mist Eliminator 

No HAP APCD Control 

Scrubber (unknown) 

Spray Dryer 
37

APPENDICES C, D, E 

(See Excel spreadsheets)