1 MEMORANDUM
TO: Brian Shrager & Jim Eddinger, U.S. Environmental Protection Agency, OAQPS
FROM: Eastern Research Group, Inc.

DATE: November 2011
SUBJECT: Revised November 2011 Developmen t of Baseline Emission Factors for Boilers and Process Heaters at Commercial, I ndustrial, and Institutional Facilities

1.0 INTRODUCTION

This memorandum discusses the processes used to develop baseline emission factors for boilers and process heaters base d 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 N o. 2060-0616, EPA Form No. 5900-122), and subsequent data submittals. ER G developed two database s: 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 data base containing all the stack test results, continuous emissions monitoring system (C EMS) data, and fuel anal ysis 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 fo llowed a four-step process: First, a list of unique combustion units reported in the Surv ey Database was compiled. Next, the reported
fuels combusted and control devices installed we re categorized. Third, for all units reporting emission data, all available emission data for eac h particular combustion unit were averaged and2 assigned a unit-specific baseline emission factor. Finally, to fill data gaps at units not reporting emission data, the emission data from other simila r 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 co mbustor 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 Emi ssion Standards for Hazardous Air Pollutants (NESHAP) for boilers and process heaters at Indust rial, 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-Sp ecific 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 Reduc tions from Control Device Groupings Appendix D: Baseline Emission Factors for Bo ilers and Process Heat ers 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.3 2.0 GROUPING DATA ACCORDING TO FU EL TYPE, CONTROL DEVICE, AND
COMBUSTOR DESIGN

The first step of the baseline emission factor process involved targe ting select pollutants, developing a comprehensive list of all combus tion units reported in the questionnaire, and categorizing combustion units according to sta ndardized fuel groups, control devices, and combustor designs reported the questionnaire. The procedures used to characterize the qualitative data from the questionnaire into ap propriate groups are discus sed in this section.

2.1 Pollutants Baseline emission factors are specific to a ce rtain 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 f actors were only developed for those listed in Table 1 because these pollutant s represent pollutant s regulated under Section 112 of the Clean Air Act, as amended in 1990 (CAA), they repres ent surrogates for pollutants regulated under the CAA, or they represent pollutant s 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 (Cl 2 ) Sulfur Dioxide (SO 2 )
Total Hydrocarbons (THC) Volatile Organic Compounds (VOC) Toxic-Equivalent Dioxins/Furans (TEQ D/F) Carbon Monoxide
Formaldehyde Oxides of Nitrogen (NO x )

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 Com bustion 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-fire d combustion unit is any unit firing natural gas, propane, liquefied petrol eum 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 combus tion 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 containi ng 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 ma jor sources of hazardous air pollutant (HAP) emissions. This resulted in a total of 14,111 unique boilers and pro cess heaters, with 7,117 of these being small, gas-fired units.

2.3 Fuel Categories The Questionnaire provided a drop-down list co ntaining 134 different fu els and materials,
and it also allowed users to self-r eport additional types of fuels a nd materials not included in the list. These fuels were categori zed into one of the 9 fuel categ ories listed in Table 2. A list5 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 assi gn each multi-fuel boiler and process heater to a specific fuel category. For units firing multiple fuels, fuel categorie s were assigned based on the percentage of the total heat input contributed by each fuel. A threshold of 90 pe rcent 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 natu ral 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 h eat input. For example, if a combustion unit’s total heat input was composed of 10 percent co al 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% biom ass and 50% coal, its data were not used in the calculation of overall average baseline emission fact ors 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 Fuels6 Rank Fuel Category

9 Waste

For baseline purposes, petroleum coke and ti re 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 fr om 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 pe r the Identifica tion of Non-Hazardous Ma terials 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 polluta nts. Because certain control de vices target different types of pollutants, the pollutants themselves were firs t categorized into groups. Table 3 shows the groupings created for these pollutants.

Table 3: Pollutant Groupings Category Constituent Pollutants

Inorganic HAP and SO 2 HCl HF

Cl 2 SO 2 Mercury (Hg) Hg

Particulate Matter (PM) Filterable PM

Non-Mercury Metallic HAP Sb As

Be Cd

Cr Co7 Category Constituent Pollutants

Pb Mn

Ni Se

TSM8 TSM10

Organic HAP and CombustionBased Pollutants CO NO x

THC VOC
Formaldehyde

Dioxins/Furans TEQ D/F

Control devices were reported in many sepa rate 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 iden tified 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 effectiv e 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 exampl e, selective catalytic reduction (SCR) is not effective in reducing the concentra tion of any pollutants liste d in Table 3. Thus, any combustion unit that employed SCR was classi fied as having no air pollution control device (APCD). Similarly, if a combustion unit reported a control configuration of an electrostatic precipitator coupled with SCR, th e “total baseline control” was st andardized 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 devi ce 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 SO 2 , Metallic HAP, Mercury, and Partic ulate Matter. Because add-on control technologies reported in the Questionnaire do not achie ve reductions in dioxin/furan,8 organic HAP, CO, or THC, no control groups we re assigned to the Organic HAP group. For each group of pollutants, control devices were ranked according to th eir effectiveness and assigned to a group. The lowest numbered groups represent the best-performing controls for a particular set of pollutants. For example, a we t scrubber is recognized to be the most effective control device at removing acid ga ses in the Inorganic HAP and SO 2 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 particul ate matter and metallic HAP, and it was assigned to “Control Group 3” for the Me tallic HAP group, behind spray drye r/fabric filter and spray dryer/electrostatic precipitator control configurati ons. A list of the standa rdized “total baseline control” configurations and their groupings for Inorganic HAP and SO 2 , Mercury, Particulate Matter, and Metallic HAP can be found in Ta bles 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 contro ls were disregarded from the ba seline 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/Other9 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 boi lers pulverize the coal dow n to a powder and then inject the powdered fuel and air into the co mbustion chamber, where the fuel combusts in suspension. Both Dutch ovens and suspension bu rners are often designed to handle fuels with moderately higher moisture contents (e.g., loggin g and timber residue, bagasse). In Dutch ovens, the fuel is distributed onto grates, and air flows up through the grat es to provide oxygen for combustion, cool the grates, and dry the fuel. U nderfire 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 in cluded in the same design subcategory. 8 For suspension burners, fuel particles are combusted after being pn eumatically suspended in an airstream. Fuel cells first inject biomass into a char furnace for gasification. The char furnace gas is then passed10 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, st eam, or heat, while the effluent gas is combusted for thermal energy. Combination suspension/grate units cont ain both suspension and grate firing mechanisms. Biomass combusted in suspensi on/grate boilers, typi cally bagasse, has high moisture content and must be pre-dried before fi ring. Moisture content of the fuel affects the furnace heat release rate, volume of combusti on 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 sec ondary combustion occurs. The first stage of combustion (suspension burning) drie s out most of the remaining moisture so that what falls to the grate can be combusted efficiently. Biomass w ith a fuel content of 20 to 30 percent moisture typically does not need pre-drying. 9 Combustion units were assigned to a combus tor 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 faciliti es, as described in another memorandum. 10 If a unit did not enter combustor design information, or if th e combustor design was reported as a type other than those listed above, it wa s placed in the Stoker/Sloped Grate/Other category, as stoker designs represent the majority of boilers and pr ocess 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 un it was reviewed. If all of the units shared the same combustor design, that common combustor design was used to char acterize 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 labele d as “Multiple Combustor Designs.” Sometimes a combustion unit reported more th an one type of combustor design in the Survey Database, and a hierarchy was used to cl assify that unit in one of the combustor design categories. For solid fossil units, the hierarc hy was pulverized coal units, followed by fluidized
beds and then stokers. Other de signs not classified as pulverized coal, stok er, or fluidized bed
were included in the stoker de sign category. For biomass units, the hierarchy was fluidized bed, followed by dutch oven/pile burners, suspension/g rate units, suspension burners, fuel cells, and then stokers (including sloped grat e). Other designs not classified as one of the designs in the11 hierarchy were included in the stoker category.

3.0 DEVELOPMENT OF UNIT-SPECIFIC EMISSION FACTORS

Before an average baseline emission factor c ould 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 discu ssed 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 Phas e 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 dete rmine 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 Uni t-Specific Baseline Emission Factors Rank Condition

1 If a unit had emission test averages a nd CEMS data averages, and the values were within the same order of magnit ude, CEMS and emission test averages were averaged together. 2 If a unit had emission test and CEMS da ta averages, and the values were not within the same order of magnitude, only the emissi on 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 averag e 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 fu el analysis data for metallic HAP, mercury, or chlorine (standardized to hydr ogen chloride), the average of all the standardized fuel analysis data in the unit’s fuel cate gory (light or heavy liquid) was assigned as the unit’s baseline emission factor.12 Rank Condition

6 Facility-level averages were genera ted for each pollutant based on a common fuel category, control category, and co mbustor design. Boilers or process heaters without unit-specific emission test or CEMS data were assigned the facility-level averag e 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 assi gned 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 de termine the fuel and control device, respectively, for each unit-specific emission factor.

Table 6: Hierarchy for Determining Fuel s for Unit-Specific Emission Factors Rank Source

1 If emission test or CEMS data were av ailable, the fuels reported during these tests or monitoring periods were used. Tests on multiple fuels or control configurations were assigned separate reco rd 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 (a s 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 capaci ty 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 bei ng combusted for that specific facility, as listed in the Data: Fuel Analysis Background Information table of the Survey Database.13 Table 7: Hierarchy for Determining Control De vices for Unit-Specific Emission Factors

Rank Source

1 If emission test or CEMS data were avai lable, the control de vices reported to be installed during these tests or monitoring periods were used. Tests on multiple fuels or control configurations were a ssigned separate record identifiers, as discussed in Section 3.1.1.

2 A combination of all current control de vices 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 re ported 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 co al and/or biomass that did not report having any controls installed were assu med to have a cyclone installed for metallic HAP and particulate matter control. The “total baseline control” category for these units remained classifi ed 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 co mbusted 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 cont rol 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 diffe rent 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 bot h 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 Da tabase. Current control device data were reported in the Data: Control Device table of the Survey Database. The fuel and control information reported with the testi ng and monitoring data were compared to these tables to determine the most representative fuel and control confi guration. Emission and monitoring data for alternate fuel or control configurations at th e unit were not considered when calculating a unit-specific baseline emission fact or, but they were included when calculating average baseline emission factors for units with sim ilar fuel and control devi ce configurations.14 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 detec tion limit was used as the basis for the average. Emission test data were available for all pollutants listed in Ta ble 3 of this memorandum. Monitoring data was reported in the Survey Database on a daily average basis for CO, SO 2 , NOx, and Filterable PM. Hourly CEMS data was reported in the Survey Da tabase for CO, NOx, and THC. Facilities were unable to report emission monitoring data as no n-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, so me units reported cont rol configurations that represent current control configurations presently installed on the unit, as well as control device configurations that were installed prior to complying w ith 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 anot her reported a test while firing fuel oil. To appropriately group emission test and monitoring data, a reco rd identifier wa s 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 measur ement error, based on the reported span values
were used as the basis for baselines for CO a nd THC emission test data. The development of default values and calibration span values fo r those pollutants is described in another
memorandum. 11 For combustion units with only one fuel and control de vice combination, the record number was assigned as “1.” For combustion units with multiple combinations of fuel and control device configurations, ad ditional record numbers were assigned. For example, if a
combustion unit with a wet scrubbe r reported two emission tests, on e burning coal and the other burning oil, two record identifiers were given. The coal/wet scrubber co mbination 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 an d control device configurations. An average (mean) of all the monitoring data with the same record identifier was also15 calculated. For most sources, this was a 30-day average, but some sources reported multiple 30- day periods in the Survey Database. For combus tion 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 average d, when deemed appropriate. The
calculated means for the emission test and monito ring data were compare d, 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 a ssigned to the unit-specific base line 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 establis h 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 chlo rine fuel analysis concentrations into
standardized emission factors is discussed in another memorandum. 4 Fuel analysis data from uncontrolled liquid fuels were standa rdized 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 ofte n delivered to a facility a nd used in multiple combustion units at the facility, fuel analysis data were re ported in the Survey and Emission Databases at the facility level. As a result, unit-specific emission averages could not be ge nerated. 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 liqui d 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 fo r 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 anal ysis data for bio liquids, diesel fuel, jet fuel, kerosene, and #2 and #4 oil for uni ts in the light liquid fuel category, and the mean of all16 standardized fuel analysis data for black liquor, #5 and #6 oil, r ectified methanol, red oil, and onspec used oil for units in the h eavy liquid category. For example, facilities A and B each have an uncontrolled unit combusting distillate liquid fuel, a nd each facility also reported fuel analysis
data for chlorine. Both combustion units woul d have each been assigned the same HCl fuel analysis average genera ted for light liquids. Some fuel analysis data were reported as a mixt ure of fuels. If a liquid fuel was reported as a mixture, the corresponding data were only us ed 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 use d, whereas data from a combination of “No. 2
Distillate/No. 6 Residual oil” woul d 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 f acility-level averages. Each of the emission test averages described in Section 3.3 of th is memorandum were further averaged across each facility based on a common fuel category and eith er control category or combustor design, based on the pollutant. Organic HAP, CO, and TEQ di oxin/furan emissions we re 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 un ique unit and there were no other similar units at the facility, the unit did not re ceive 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 BA SELINE EMISSION FACTORS

For units that did not report em ission test, CEMS, or fuel an alysis data, and could not be assigned a facility-level averag e or a non-detect average for one of the pollutants in Table 1, average baseline emission factors were develope d using data from other boilers and process17 heaters with similar controls, fuels, and combus tor 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 emi ssion factors. The process of identifying data suitable for use in an average baseline emissi on factor and calculati ng the average baseline
emission factors is discu ssed in this section.

4.1 Baseline Criteria Baseline averages were developed to represen t 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 ma terial 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 f actor for each polluta nt, all unit-specific emission factors assigned in Secti on 3.0 were averaged for similar gr oups of controls, fuel types, and combustor designs. Because inorganic HAP and SO 2 , 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, NO x , and CO are combustion-based pollutants, and their emissions are influenced by the design of the combustion cham ber. Further, emissions of NO x and CO can be affected by
NO x controls such as low-NO x burners, overfire-air, or flue gas recircula tion. As a result, the unit-specific emission factors were averaged across all units with a common fuel category, combustor design, and NO x control configuration. Baseline averages for THC and TEQ D/F are also driven primarily by the design of the co mbustion 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 Ph ase II, emissions of THC and TEQ D/F at units firing natural gas and refinery gas differed significantly de pending on whether the unit was equipped with NO x controls, so baseline emission factors for THC and TEQ D/F at these gas-fired units were18 established by averaging da ta from other gas-fired units with similar NO x 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 device s, 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 SO 2 , 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 pollu tant-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 contro l devices installed. There were no data gaps for the organic HAP pollu tants for liquid fuels or units burning natural gas, refinery gas, or other on-spec gaseous fuel s. 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 un its with NOx control. The average baseline THC and TEQ D/F emissions from suspensi on burners combusting dry biomass were approximated using the average emissions from st okers combusting dry biomass. Data gaps for
fluidized bed units and stokers with NOx cont rol 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 befo re additional data updates were made. The
CO baseline emission factor shou ld have been 782 ppm @ 3% O 2 , but the older value used in all analyses was 801.2 ppm @ 3% O 2 . 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 factor19 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 us ed 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% O 2. NOx, formaldehyde, and TEQ D/F were not included in the emission reduction impacts. Baseline formaldehyde emissions for units fi ring process gas without NOx control were approximated using the baseline formaldehyde emi ssions for process gas un its 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 unchar acteristically 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 fo r 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 fo r these flagged values to determine if a problem existed with any of the re ported 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 Emissi on Database, and the updated values were used to
recalculate baseline emission fact ors. If reported data was iden tified 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 iden tify any uncharacteristica lly high or low values that could over or underestimate the expected em ission reduction estimates associated with this proposal.

4.5 Establishing Baseline Emissions for PM 2.5 and VOCs20 Baseline emission factors for particul ate matter less than 2.5 microns (PM 2.5 ) were estimated as a percentage of filterable PM baselines. PM 2.5 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 PM 2.5 . The ratios of PM 2.5 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
PM 2.5 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 de vice configuration assigned to each unit, a baseline emission factor for PM 2.5 was estimated by multiplying the appropriate
PM 2.5 fraction by the filterable PM baseline em ission factor assigned to the unit. Similar to the method used to generate PM 2.5 baseline emission factors, VOC emission factors were generated as a portion of THC baselin e 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 co rrelated 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 heater s. 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 quartil e analysis was performed on th e set of ratios to remove any outliers. The remaining ratios were then av eraged 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 categ ories or control devices. Based on monitoring data available from these six sources, THC em issions are composed of 57 percent VOCs. The data used to calculate this percen tage is presented in Appendix D-4.

4.6 Establishing Baseline Emissions for Toxic Equivalent Dioxins/Furans Baseline emission averages for TEQ D/F were cal culated 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 va lue 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 uni t-less weighting factor that equates the emissions of each congener to 2,3,7,8-TCDD based on re lative toxicity. Table 8 lists the dioxin/furan congeners21 and their respective TEF used to calculate dioxin/furan emissions.

Table 8: Dioxin/Furan Congeners and Toxic Equivalency Factors A 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

A World Health Organization (WHO) toxic equivalency factors from 2005.

Only Phase II Test Plan data was used to gene rate dioxin/furan averages because Phase I data was not received for individual congeners. Th e total mass emission values of each congener were multiplied by the appropriate TEF in orde r 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 un its. TEQ emission values coul d only be generated for boilers or process heaters that reported dioxin/furan data on the congener leve l; some facilities only reported an overall total mass di oxin/furan emission value, which could not be converted to a TEQ value. To calculate average baseline emissi on 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 numb er 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 facili ties with boilers and process heaters reported emission data in the Survey Database, ther e 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 ma jor 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 School s 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 Wiscons in indicate that 8 pe rcent of wood/biomass boilers greater than 10 MMBtu/hr in these two states do not have a ny 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 Penns ylvania do not have any listed control. The remaining boilers firing solid fuels at area source s have a mechanical collector control device. Using this information on control devices, we as signed average baseline emission factors for the area source model units according to Table 9 below.

T able 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 pollutants A Average of wet and dry biomass for cyclone/multiclone controlled23 Area Source Model

Unit Pollutant Type Corresponding Major Source Baseline Emission Factor Category

Combustion-based pollutants B Average of wet and dry biomass stokers with NO x control

Coal Fuel-based pollutants A Cyclone/multiclone controlled coal

Combustion-based pollutants B Coal stokers with NO x control

Residual

Liquid Fuel- and combustion-based pollutants A.B Uncontrolled heavy liquid

Distillate

Liquid Fuel- and combustion-based pollutants A,B Uncontrolled light liquid

A Fuel-based pollutants include: PM, Hg, metallic HAP, inorganic HAP, and SO 2 . 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 Un its (ICR No. 2286.01) (version 2).

2. Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, & Fuel Analysis Data Reported under ICR N o. 2286.01 & ICR No. 2286.03 (version 7).

3. Eastern Research Group, Inc. Revised (N ovember 2011) Data Dictionary for Boiler, Process Heater, and Other Combustion Un it Survey Databases. November 2011.

4. Eastern Research Group, Inc. Revised (N ovember 2011) Standardization of Reported Data from the Questionnaire for Boilers, Process Heaters, Incinerators and Other Combustion Units. November 2011.

5. U.S. Environmental Protection Agency. 2008 Questionnaire for Boilers, Process Heaters, Incinerators and Other Combus tion 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 Boile rs 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 Asso ciates Inc. See document number EPA-HQOAR-2002-0058-2801.1 in the docket for Nationa l Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Instit utional Boilers and Process Heaters.

10. Eastern Research Group, Inc. Handling and Processing of Corrections and New Data in the EPA ICR Databases – Revise d November 2011. November 2011.

11. Eastern Research Group, Inc. Incorporat ing 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

GLOSSARY26 Table A.1: Glossary
Term Description APCD Air pollution contro l device. An add-on exhaust stack technology that reduces the concentrati ons 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 (Cl 2 ). 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. NO x Nitrogen oxides. A grouping of binary compounds composed of the elements nitrogen and oxygen, includ ing nitric oxide (NO), nitrogen dioxide (NO 2 ), nitrous oxide (N 2 O), dinitrogen trioxide (N 2 O 3 ), dinitrogen tetroxide (N 2 O 4 ), and dinitrogen pentoxide (N 2 O 5 ). Organic An organic compound is char acterized as any compound containing carbon, not including carbonates, carbon oxides, cyanides, and allotropes of carbon. For this analys is, 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).

PM 2.5 A portion of total filterable particulate matter consisting of particles less than or equal to 2.5 μm in diameter. SO 2 Sulfur dioxide. A common polluta nt 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 quantif ying the toxicity of dioxin/furan congeners relative to the congene r 2,3,7,8-TCDD. TEQ values used in this analysis are based on th e 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 meta llic HAP, including arsenic (As), beryllium (Be), cadmium (Cd), chro mium (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 (C d), chromium (Cr), cobalt (Co), lead (Pb), manganese (Mn), nick el (Ni), and selenium (Se). VOC Volatile organic compound. Any compound of carbon, excluding carbon monoxide, carbon dioxide, car bonic acid, metallic carbides or carbonates, and ammonium carbonate, which participates in atmospheric photochemical reactions.28 APPENDIX B
Fuel and Control Device Groupings29 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 Biomass 1

4 Dry Biomass Paper and Paper Residues Paper Pellets Plant-based Agricultural Residue Sanderdust Wood: Plywood, Particleboard (c ontaining 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 Gases 2 Blast Furnace Gas Coke Oven Gas31 Rank Fuel Category Inclusive Fuels

8 Natural Gas, RefineryGas, & Other OnSpec Gaseous Fuels 2,3 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 gas32 Rank Fuel Category Inclusive Fuels

9 Waste 4 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 th ey all will or will not meet specification. Gases must be tested to ensure they meet the specificatio n 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 ma keup 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 fi nal definition of waste as per the Identification of NonHazardous Materials That Ar e Solid Waste rulemaking.33 Table B.2.A: Inorganic and SO 2 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 Precipitator34 Table B.2.B: Mercury (Hg) Control Groupings Control Group Control Device

1 Fabric Filer/Activated Car bon 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 Precipitator35 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 Dryer36 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 Dryer37 APPENDICES C, D, E
(See Excel spreadsheets)