Prevention of Significant Deterioration 

Air Pollution Control 

Construction Permit Application 

We Energies’ 50 MW Biomass-Fired 

Cogeneration Facility to be Located at the 

Domtar - Rothschild Mill. 

 

March, 2010 

Prepared for: 

We Energies 

231 W. Michigan St. 

Milwaukee, WI 53203 

Prepared By: 

 

RTP ENVIRONMENTAL ASSOCIATES INC.® 

903 Superior Avenue, Suite 6 

Tomah, WI 54660 

Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc.

We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010 

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Executive Summary 

We Energies is proposing to construct a 50 megawatt (MW), biomass-fired cogeneration facility (the 

“Project”) at the Domtar - Mill in Rothschild, Marathon County. The facility will produce 

approximately 50 MW of biomass fueled electric power, and will also provide process steam for the 

Domtar Mill. The Project will include an advanced circulating fluidized bed (CFB) boiler which will be 

fueled by wood, bark, wood waste, forest residues, and wastewater treatment plant residue from the 

Domtar Paper Mill. This boiler will also utilize natural gas for startup and combustion stabilization. 

The facility will also include two natural gas-fired package boilers which will provide steam for the Mill 

when the CFB boiler is unavailable. The Project will also include fuel receiving, unloading, storage, 

and conveying processes, boiler bed material and ash handling processes, cooling towers, and an 

emergency diesel feedwater pump. Finally, the Project will also involve the retirement of the four 

existing mill boilers after the new facility becomes operational. 

Under the Prevention of Significant Deterioration (PSD) program in NR 405.02(22)(a), Wis. Adm. 

Code, the major stationary source threshold for this facility is 100 tons per year. Based on the total 

potential emissions in Table ES-1, the Project will be subject to the PSD program for carbon monoxide 

(CO), nitrogen oxides (NOx), particulate matter (PM/PM10), fine particulate matter (PM2.5), sulfur 

dioxide (SO2), organic compounds (VOC), and fluorides (as HF). This PSD applicability is based only 

on the new emission units. Although emissions from the existing mill boilers will be reduced, because 

the new boiler is a separate project with a separate owner and responsible official, no netting or project 

emissions accounting has been used to offset the potential emissions for the new units. 

TABLE ES-1. PSD applicability for the biomass-fired cogeneration Project. 

 POLLUTANT 

Potential to 

Emit 

ton/year 

PSD Significant 

Threshold 

ton/year 

OVER? 

Carbon Monoxide CO 766 100 YES 

Nitrogen Oxides NOx 372 40 YES 

Particulate Matter PM/PM10 131 15 YES 

Particulate Matter PM2.5 97 10 YES 

Sulfur Dioxide SO2 316 40 YES 

Organic Compounds VOC 66 40 YES 

Lead Pb 0.11 1 NO 

Mercury Hg 0.01 N/A 

Fluorides (as HF) HF 4.2 3 YES 

Sulfuric Acid Mist H2SO4 6.3 7 NO 
Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc.

We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010 

- iii - 

Control Technology Review. 

A control technology review or Best Available Control Technology (BACT) analysis was conducted for 

each proposed new emissions unit. For the biomass-fired Boiler B01, We Energies is proposing an 

advanced circulating fluidized bed boiler designed to fire natural gas and biomass fuels. We Energies is 

proposing to equip this boiler with state-of-the-art air quality control systems including selective noncatalytic reduction (SNCR) for the control of NOx emissions, and a fabric filter baghouse for the control 

of PM, PM10, and PM2.5 emissions. 

For the natural gas-fired Boilers B02 and B03, We Energies proposes to install package boilers 

equipped with ultra low NOx burners for the control of NOx, CO, and VOC emissions. We Energies 

also proposes to limit the fuels fired in these boilers to only natural gas. 

TABLE ES-2. Proposed control technologies and emission limits representing BACT for the 

biomass-fired boiler B01. 

POLLUTANT PROPOSED CONTROL TECHNOLOGY 

PROPOSED 

LIMIT, 

lb/mmBtu 

POTENTIAL 

TO EMIT, 

ton/year 

Carbon Monoxide 

(CO) 

Advanced Circulating Fluidized Bed Boiler and 

Good Combustion Practices 0.20 701 

Nitrogen Oxides 

(NOx) 

Circulating Fluidized Bed Boiler and 

Selective Non-Catalytic Reduction 0.10 350 

PM < 10 microns 

(PM10) Fabric Filter Baghouse 0.03 105 

PM < 2.5 microns 

(PM2.5) 

Fabric Filter Baghouse with 

Felted Filter Media Bags 0.023 81 

Sulfur Dioxide 

(SO2) 

Circulating Fluidized Bed Boiler and Low Sulfur 

Fuels including Biomass Fuels and Natural Gas 0.09 315 

Organic 

Compounds (VOC) 

Circulating Fluidized Bed Boiler and 

Good Combustion Practices 0.017 60 

Fluorides 

(as HF) 

Circulating Fluidized Bed Boiler and Low Fluoride 

Fuels including Biomass Fuels and Natural Gas n/a 3.5 
Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc.

We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010 

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Dispersion Modeling Analysis 

The air quality in Marathon County is generally very good, and Marathon County is considered 

attainment for all criteria air pollutants, including CO, NO2, PM, PM10, PM2.5, and SO2. Dispersion 

modeling impact analysis was completed and illustrates that allowable emissions from the proposed 

sources will not cause or contribute to violations of any National Ambient Air Quality Standard 

(“NAAQS”), or of any applicable Prevention of Significant Deterioration (“PSD”) increment. The 

results of the cumulative NAAQS analysis demonstrate that the Project will not cause or contribute to 

air quality impacts that exceed the NAAQS. The PSD increment results demonstrate that the Project will 

not cause or contribute to air quality impacts that exceed the PSD increments. 

In the dispersion modeling analysis, a significant impact analysis was performed to determine the 

increases in ambient air concentrations due only to the proposed Project. When the maximum ambient 

concentrations of a pollutant are below the significant impact level (“SIL”) for all averaging periods, the 

emissions from the source are not expected to have a significant impact on ambient air, and further air 

quality analysis is not required. The results of the significant impact analysis in Table ES-2 show that 

the maximum impacts from the Project are below the SILs for CO, NO2 and the annual SO2 standard. 

This means that the Project will have an insignificant impact on air quality for these pollutants and 

averaging intervals. 

TABLE ES-2. Results of the dispersion modeling significant impact analysis. 

Pollutant Averaging Period Significant Impact Level, 

μg/m3

Highest Modeled 

Concentration, μg/m3

8-hour 500 99 

CO 

1-hour 2,000 209 

NO2 Annual 1 0.92 

Annual 1 0.98 

SO2 24-hour 5 12.6 

3-hour 25 55.6 

Annual 1 5.6 

PM10

24-hour 5 20.4 

Annual 0.3 1.2 

PM2.5

24-hour 1.2 6.4 

A cumulative National Ambient Air Quality Standard (NAAQS) modeling analysis was also performed 

that considered emissions from the Project, other nearby sources, and the background concentrations of 

these air pollutants. The results of the cumulative NAAQS analysis in Table ES-3 show that the Project 

will not cause or contribute to air quality impacts that exceed the NAAQS. 
Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc.

We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010 

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If the proposed source's maximum modeled air pollutant concentrations exceed the SIL for any pollutant 

and averaging interval, a cumulative PSD increment impact analysis is also performed for that pollutant 

and averaging interval. The results of the cumulative Class II PSD increment analysis are summarized 

in Table ES-4. The SO2 3-hr and 24-hr and the PM10 24-hr concentrations are the highest second-high 

concentrations. The PSD increment results demonstrate that the Project will not cause or contribute to 

air quality impacts that exceed the PSD increments. 

TABLE ES-3. Results of the dispersion modeling cumulative NAAQS analysis. 

Pollutant Averaging 

Interval 

Cumulative 

Impact, 

μg/m3

Background, 

μg/m3

Total, 

μg/m3

NAAQS 

μg/m3 % of NAAQS

NO2 1-hour 61 11.9 73.2 188 39% 

24-hour 249 11.2 260.2 365 71% 

SO2

3-hour 951 11.8 962.8 1300 74% 

PM10 24-hour 41.8 29.4 71.2 150 47% 

Annual 2.3 8.7 11.0 15 73% 

PM2.5

24-hour 9.0 25.6 34.6 35 99% 

TSP 24-hour 103.6 39.7 143.3 150 96% 

Lead 3 month 0.00066 0.01 0.01066 0.15 7% 

TABLE ES-4. Results of the dispersion modeling cumulative PSD analysis. 

Pollutant Averaging 

Interval 

Maximum 

Impact, ug/m3

PSD Increment 

ug/m3

% of PSD 

Increment 

Annual 5.7 17 34% 

PM10

24-hour 21.0 30 70% 

24-hour 86.1 91 95% 

SO2

3-hour 300 512 58% 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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Table of Contents 

Chapter 1. Contents of this Application. ..................................................... 10

Chapter 2. Project Description..................................................................... 11

2.1 Air Emission Units. .........................................................................................................................11

2.2 Biomass-fired Circulating Fluidized Bed Boiler B01. ....................................................................15

2.2.1 Fluidized Bed Boiler Technology. ....................................................................................15

2.2.2 CFB Boiler Fuels. .............................................................................................................16

2.2.3 Definition of Biomass. ......................................................................................................16

2.2.4 CFB Boiler Design............................................................................................................17

2.2.5 Expected Boiler Operating Characteristics. ......................................................................17

2.2.6 Aqueous Ammonia. ..........................................................................................................17

2.3 Natural Gas-Fired Package Boilers B02 and B03. ..........................................................................17

2.4 Biomass Fuels Material Handling Processes...................................................................................19

2.4.1 Process P121: Biomass Fuels Unloading, Screening, Hogging, and Conveying.............19

2.4.2 Process F122: Self Unloading Truck Biomass Fuels Unloading. ....................................21

2.4.3 Process F123: Biomass Fuels Storage and Reclaim.........................................................21

2.4.4 Process P124: Boilerhouse Fuel Storage Silos.................................................................21

2.4.5 Process F125: Biomass Fuels Delivery Truck Haul Roads..............................................22

2.5 Process P131: CFB Boiler Bed Material Silo and Process P132: CFB Boiler Ash Silo...............22

2.6 Process F133: Boiler Ash Haul Roads. ..........................................................................................22

2.7 Process P141: Cooling Tower. .......................................................................................................22

2.8 Process P151: Emergency Diesel Feed Water Pump. ....................................................................22

2.9 Project Schedule..............................................................................................................................23

Chapter 3. Project Emissions........................................................................ 24

3.1 Biomass-fired Circulating Fluidized Bed Boiler B01. ....................................................................24

3.2 Natural Gas-Fired Package Boilers B02 and B03. ..........................................................................25

3.3 Biomass Fuels Material Handling Processes...................................................................................26

3.3.1 Process P121: Biomass Fuels Unloading, Screening, Hogging, and Conveying.............26

3.3.2 Process F122: Self Unloading Truck Biomass Fuels Unloading .....................................26

3.3.3 Process F123: Renewable Fuels Storage and Reclaim.....................................................27

3.3.4 Process P124: Boilerhouse Fuel Storage Silos.................................................................27

3.3.5 Process F125: Renewable Fuels Delivery Truck Haul Roads..........................................27

3.4 Process P131: CFB Boiler Bed Material Silo and Process P132: CFB Boiler Ash Silo...............28

3.5 Process F133: Boiler Ash Haul Roads. ..........................................................................................28

3.6 Process P141: Cooling Tower. .......................................................................................................29
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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3.7 Process P151: Emergency Diesel Engine Feed Water Pump.........................................................31

Chapter 4. Applicable Air Pollution Control Regulations. ....................... 32

4.1 Total Project Emissions and the Prevention of Significant Deterioration (PSD) Program. ............32

4.2 Biomass-Fuel Fired Boiler B01.......................................................................................................33

4.2.1 New Source Performance Standards (NSPS), NR 440, Wis. Adm. Code. .......................33

4.2.2 National Emission Standards for Hazardous Air Pollutants, NR 460, Wis. Adm. Code. .34

4.2.3 Federal Acid Rain Program, NR 409 Wis. Adm. Code. ...................................................35

4.2.4 Clean Air Interstate Rule, NR 432, Wis. Adm. Code. ......................................................35

4.2.5 Section 112(r) Prevention of Accidental Releases (40 CFR Part 68). ..............................36

4.2.6 State of Wisconsin Requirements. ....................................................................................36

4.3 Natural Gas-Fired Boilers B02 and B03. ........................................................................................40

4.3.1 New Source Performance Standards (NSPS)....................................................................40

4.3.2 National Emission Standards for Hazardous Air Pollutants (NESHAP). .........................40

4.3.3 Federal Acid Rain Program...............................................................................................41

4.3.4 Control of Hazardous Pollutants under NR 445, Wis. Adm. Code...................................41

4.4 Diesel Engine Driven Feedwater Pump, Process P151. ..................................................................41

Chapter 5. Proposed BACT Limits.............................................................. 43

5.1 CFB Boiler B01...............................................................................................................................43

5.2 Natural Gas-Fired Boilers B02 and B03. ........................................................................................44

5.3 Balance of Plant Equipment............................................................................................................45

Chapter 6. Hazardous Air Pollutants and Case-by-Case MACT Analysis.46

6.1 Biomass-Fuel Fired Boiler B01.......................................................................................................46

6.2 Natural Gas-Fired Boilers B02 and B03. ........................................................................................49

Chapter 7. Dispersion Modeling Analysis. .................................................. 51

7.1 Dispersion Model ............................................................................................................................52

7.2 Modeling Analysis Overview..........................................................................................................52

7.3 Dispersion Modeling Results. .........................................................................................................52

7.3.1 Significant Impact Assessment. ........................................................................................52

7.3.2 Cumulative NAAQS Assessment. ....................................................................................53

7.3.3 Cumulative PSD Increment Analysis................................................................................54

Chapter 8. Additional Impacts Analysis...................................................... 55

8.1 Analysis on Soils, Vegetation, and Visibility..................................................................................55

8.2 Associated Growth and Secondary Emissions. ...............................................................................56

8.3 Class I Air Quality Analysis Requirements.....................................................................................56
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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Tables 

TABLE 2-1. Proposed new emission units at We Energies’ Biomass-Fired Cogeneration Facility. ........11

TABLE 2-2. Domtar Biomass Cogeneration Facility thermal performance. ...........................................18

TABLE 2-3. Overall project schedule. ......................................................................................................23

TABLE 3-1. Potential air pollutant emissions for the proposed biomass-fired boiler B01. ......................24

TABLE 3-2. Potential air emissions for each package Boiler B02 and B03. ..........................................25

TABLE 3-3. Potential emissions for the new mechanical draft cooling tower, Process P141. .................30

TABLE 3-4. Potential emissions for the diesel engine driven fire pump based on limiting operation to 

100 hours per year................................................................................................................31

TABLE 4-1. Total facility emissions and the PSD applicability for the We Energies' - Domtar Rothschild 

Mill 50 MW biomass fuels-fired cogeneration facility........................................................32

TABLE 4-2. Hazardous air emissions for the biomass-fired boiler B01..................................................39

TABLE 5-1. Proposed control technologies and emission limits representing BACT for the biomass-fired 

boiler B01.............................................................................................................................43

TABLE 5-2. Proposed control technologies and emission limits representing BACT for the natural gasfired Boilers B02 and B03....................................................................................................44

TABLE 5-3. Proposed control technologies and emission limits representing BACT for We Energies’ 50 

MW Biomass Fuels Cogeneration Facility balance of plant equipment. .............................45

TABLE 6-1. Proposed emission standards representing MACT for Boiler B01.......................................46

TABLE 6-2. Potential hazardous air pollutant emissions for the biomass-fired boiler B01 (2 pages)......47

TABLE 6-3. Proposed emission limits representing MACT for each natural gas-fueled boiler. ..............49

TABLE 6-4. Potential hazardous air pollutant (HAP) emissions for each natural gas-fired boiler...........50

TABLE 7-1. National ambient air quality standard (NAAQS), modeling Significance Levels, and PSD 

Class II Increment, ug/m3

....................................................................................................51

TABLE 7-2. Results of the significant impact analysis.............................................................................53

TABLE 7-3. Cumulative NAAQS modeling results...................................................................................54

TABLE 7-4. Cumulative PSD Increment Modeling Results. .....................................................................54
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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Figures

FIGURE 2-1. Locus map for We Energies’ proposed 50 MW biomass-fired cogeneration facility. 

FIGURE 2-2. USGS location map for We Energies’ 50 MW biomass-fired cogeneration facility. 

FIGURE 2-3. Proposed site layout for We Energies’ 50 MW biomass-fired cogeneration facility. 

FIGURE 2-4. Typical CFB boiler power block showing the furnace, cyclone, baghouse, and stack. 

FIGURE 2-5. Diagram of the biomass fuels receiving, conveying, and storage processes. 

FIGURE 2-6. Photo of a truck dumper and A-frame fuel storage building. 

Attachments 

APPENDIX A. Control Technology Review - Best Available Control Technology (BACT) Analysis for 

the 50 MW Biomass-Fired Electric Generating Unit. 

APPENDIX B. Control Technology Review - Best Available Control Technology (BACT) Analysis for 

the Natural Gas-Fired Boilers. 

APPENDIX C. Control Technology Review - Best Available Control Technology (BACT) Analysis for 

the Balance of Plant Equipment. 

APPENDIX D. Case-by-Case Maximum Achievable Control Technology (MACT) Analysis for the 

Biomass-Fueled Boiler, and Natural Gas-Fueled Boiler under Section 112(g) of the Clean 

Air Act. 

APPENDIX E. Dispersion modeling analysis. 

APPENDIX F. Wisconsin Department of Natural Resources - Bureau of Air Management air pollution 

control construction permit application forms. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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Chapter 1. Contents of this Application. 

Chapter 2. Project description including emission units and project schedule. 

Chapter 3. Potential air emissions. 

Chapter 4. Applicable air pollution control regulations. 

Chapter 5. Summary of the proposed emission limits representing the best available control technology 

(BACT) for each emissions unit. 

Appendix A is the Control Technology Review for the 50 MW Biomass Fuel-Fired Electric 

Generating Unit Boiler B01. 

Appendix B is the Control Technology Review for the Natural Gas-Fired Boilers B02 & B03. 

Appendix C is the Control Technology Review for the Balance of Plant Equipment. 

Chapter 6. Analysis of potential hazardous air pollutant air emissions and a summary of the proposed 

emission limits representing the Case-by-Case Maximum Achievable Control Technology 

(MACT) for the Biomass-Fueled Boiler B01, and Natural Gas-Fueled Boilers B02 and B03 

under Section 112(g) of the Clean Air Act. 

Appendix D is the Case-by-Case MACT Analysis for the Biomass-Fueled Boiler B01, and 

Natural Gas-Fueled Boilers B02 & B03 under Section 112(g) of the Clean Air Act. 

Chapter 7. Summary of the dispersion modeling analysis. 

Appendix E is the detailed dispersion modeling analysis. 

Chapter 8. Additional impacts analysis as required under the Prevention of Significant Deterioration (PSD) 

program in NR 405, Wis. Adm. Code. 

We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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Chapter 2. Project Description. 

We Energies is proposing to construct a 50 megawatt, biomass-fired cogeneration facility at the Domtar – 

Rothschild Mill (“Mill”) in Rothschild, Marathon County, Wisconsin. Figure 2-1 is a locus map for the 

proposed facility. Figure 2-2 shows the location of the facility on the USGS 6.5 minute map which in 

Rothschild. Figure 2-3 is the proposed layout of the facility at the Mill showing the existing mill 

buildings, the new boilerhouse, fuel storage building, conveyors, and cooling tower. 

The Project location is on the Domtar Mill property that is adjacent to the east bank of the Wisconsin 

River. South Line Road and North Grand Avenue (Business U.S. Highway 51) form the eastern edge 

of the Domtar property. Residential and commercial areas are to the south, east and north of the 

project site. State Highway 29 is an east-west thoroughfare and is located about 0.5 miles north of the 

project site. Interstate 39 and U.S Highway 51 are located about 0.5 miles west of the project site.

2.1 Air Emission Units. 

The facility will produce approximately 50 MW of electric power, and will also provide process steam for 

the Domtar Mill. The facility will include a new circulating fluidized bed (CFB) boiler which will be 

fueled by biomass fuels including wood, bark, papermill sludge, and other clean biomass fuels. The 

facility will also include two natural gas-fired package boilers which will provide steam for the Mill when 

the CFB boiler is unavailable. The facility will include biomass fuel receiving, unloading, storage, and 

conveying processes, boiler bed material and ash handling and storage processes, cooling tower, and an 

emergency diesel feed water pump. The proposed new emission units are summarized in Table 2-1. 

TABLE 2-1. Proposed new emission units at We Energies’ Biomass-Fired Cogeneration Facility. 

Process ID Description 

B01 Biomass-fired Circulating Fluidized Bed Boiler 

B02 Natural Gas-Fired Package Boiler 

B03 Natural Gas-Fired Package Boiler 

P121 Biomass Fuels Unloading, Screening, Hogging, and Conveying Dust Collector 

F122 Self Unloading Truck Biomass Fuels Unloading 

F123 Biomass Fuels Storage and Reclaim 

P124 Boilerhouse Fuel Storage Silos 

F125 Biomass Fuels Delivery Truck Haul Roads 

P131 CFB Boiler Bed Material Silo 

P132 CFB Boiler Ash Silo 

F133 Boiler Ash Haul Roads 

P141 Cooling Tower 

P151 Emergency Diesel Engine Feed Water Pump 

We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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FIGURE 2-1. Locus map for We Energies’ proposed 50 MW biomass-fired cogeneration facility. 

We Energies Biomass 

Cogeneration Facility 

NORTH

Scale, miles

5 0 5 10

We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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FIGURE 2-2. USGS location map for We Energies’ 50 MW biomass-fired cogeneration facility. 

We Energies Biomass 

Cogeneration Facility 

We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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FIGURE 2-3. Proposed site layout for We Energies’ 50 MW biomass-fired cogeneration facility. 

Biomass Fuels 

Storage Building 

New Boilerhouse 

and Stack S01 

New Cooling 

Tower 

Existing Mill 

Existing Mill 

We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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2.2 Biomass-fired Circulating Fluidized Bed Boiler B01. 

The proposed boiler will be a circulating fluidized bed (CFB) boiler designed to provide up to 550,000 

pounds per hour of steam at 1,550 psig and 950 o

F. The boiler will have a maximum design heat input 

capacity of 800 million Btu per hour. The primary boiler fuels will be logging residue, wood, bark, wood 

waste, forest residues, and wastewater treatment plant sludge from the Domtar Paper Mill. The boiler 

will also be designed to fire natural gas for a startup fuel and for combustion stabilization, with a 

maximum natural gas firing rate of less than 250 mmBtu per hour. A typical CFB boiler power block 

showing the boiler, the CFB cyclone, the fabric filter baghouse, and the stack is shown in Figure 2-4. 

Note that there is additional boiler information in Appendix A to this permit application. 

FIGURE 2-4. Typical CFB boiler power block showing the furnace, cyclone, baghouse, and stack. 

2.2.1 Fluidized Bed Boiler Technology. 

The atmospheric pressure, fluidized bed boiler technology was developed to minimize SO2 and NOx

emissions from the combustion of high sulfur fuels such as coal and petroleum coke. The fluidized bed 

boiler combustion process minimizes NOx formation and removes SO2 in the boiler before post 

combustion air pollution control systems. Fluidized bed boilers are also excellent boilers for firing highly 

variable and low heat value fuels such as biomass fuels. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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The boiler proposed for this Project is a CFB boiler. The CFB boiler is a more advanced fluidized bed 

boiler technology. CFB boilers have higher fluidizing air velocities ranging from 10 to 20 ft/sec, lack a 

distinct transition from the dense bed at the bottom of the furnace to the dilute zone above, and have a 

very high flow rate of re-circulated solids. The high fluidizing air velocity results in a turbulent fluidized 

bed and a high rate of entrained solids carried out of the boiler. These solids are separated from the 

combustion gases by cyclones located at the outlet of the boiler furnace and are returned to the furnace to 

improve combustion efficiency. 

2.2.2 CFB Boiler Fuels. 

The primary fuel for the CFB boiler will be biomass fuels, including logging residues, wood, bark, wood 

waste, forest residues, and wastewater treatment plant sludge from the Domtar Mill. The design fuel – 

forest residues - will have a heat value of 8,430 Btu per pound on a bone-dry basis, or approximately 

4,530 Btu per pound on an as-received basis. The biomass fuels consumption rate will be 45 tons per 

hour on a dry basis, or approximately 84 tons per hour on an as-received basis. The boiler will also be 

equipped with natural gas start-up burners. Natural gas may also be co-fired as a support fuel using 

secondary lance type burners during upset conditions for combustion stabilization, or for short periods 

when the biomass moisture is higher than normal. 

2.2.3 Definition of Biomass. 

The primary target source and anchor fuel for this project will be woody biomass. For purposes of this 

application, “biomass” means a resource that derives energy from wood or plant material or residue, clean 

solid wood waste and crops grown for use as a resource. 

Fuel sources may include the following and other qualifying clean biomass sources: 

• logging residue 

• discarded woody material from primary manufacturing facilities such as 

paper mills, sawmills, or chip mills 

• on-site pulp & paper wastewater treatment plant residue 

• leftover woody material from secondary manufacturers such as door, 

window, cabinet manufacturers 

• woody biomass from municipality wood waste, tree services, and 

construction companies 

• clean solid wood waste from discarded wood packaging such as 

pallets/crating and from construction and demolition activities 

• woody biomass plantations, energy crops and agricultural residues. 

For purposes of this application, “biomass” excludes edible portions of food crops, refuse derived fuel, 

treated wood, municipal solid waste, sewerage sludge, and animal waste. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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2.2.4 CFB Boiler Design. 

The CFB boiler will be equipped with a single steam drum and multiple economizer, generating bank, 

superheater and steam attemperator systems. High pressure, high temperature steam will be fed to a new 

50 MW (electric) steam turbine electric generator set. The boiler will be equipped with air heaters to 

preheat the combustion air using hot flue gases and/or steam to improve thermal efficiency and to 

compensate for high moisture biomass. Steam soot blowers will be located at strategic positions to 

maintain heating surfaces clean. There will be a single electrically driven induced draft fan positioned 

downstream of the baghouse. 

The CFB boiler will have a recirculating sand system to replace the sand purged from the fluidized bed 

with the ash. The sand system will consist of a sand silo which will feed sand by gravity to the sand chute 

that ends in the furnace. The ash will bind itself to the sand in the bed. As a result, the mixture will be 

collected in a cyclone for the sand to be screened and recirculated back to the boiler combustion zone. 

The heavier particles will be discharged onto a conveyor system which will transfer the ash to the ash 

silo. The sand consumption will be dependent on the fuel and sand quality. 

2.2.5 Expected Boiler Operating Characteristics. 

The heat rate of the Project is a function of the process load. Table 2-2 is a summary of the heat rate and 

overall plant efficiency as a function of process steam demand. The Project will be designed for a high 

level of reliability, to insure reliable steam supply to the Domtar mill. The expected annual 

equivalent availability of the biomass boiler is 94%, and the Project includes natural gas fueled 

auxiliary boilers to provide process steam when the biomass boiler is out of service.

2.2.6 Aqueous Ammonia. 

Aqueous ammonia (19% concentration) will be utilized for the proposed Selective Non-Catalytic 

reduction (SNCR) flue gas NOx control system. The aqueous ammonia will be stored outside in a 

10,000 gallon bulk tank, located next to the boiler building, inside appropriate spill containment. 

Deliveries will be by self unloading tanker truck, with vapor recovery, at a diked area sized to 

contain the full volume of the truck.

2.3 Natural Gas-Fired Package Boilers B02 and B03. 

The proposed boilers B02 and B03 will be package boilers designed to provide up to 125,000 pounds per 

hour of steam. To deliver this steaming capacity, each boiler will have a maximum design heat input 

capacity of 175 million Btu per hour. The only boiler fuel will be natural gas. Each boiler will be 

equipped with ultra-low NOx burners and flue gas recirculation to control emissions of CO, NOx, PM, 

PM10, PM2.5, and VOCs. 

 

We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Renewable Fuels-Fired Cogeneration Facility RTP E

Appendix A: Control Technology Review for the Biomass-Fired Boiler. 

- 18 -

TABLE 2-2. We Energies’ Biomass Cogeneration Facility thermal performance. 

Boiler Output * 100% MCR 100% MCR 100% MCR 80% MCR 80% MCR 80% MCR **** 60Outlet steam flow to Domtar lb/hr * 0 200,000 300,000 0 200,000 280,000 Fuel Demand, mmBtu/hr ** 682 781 785 549 630 634 Fuel Demand, tons/hr ** 75 86 87 61 70 70 Boiler Efficiency 78.2% 78.2% 78.2% 77.6% 77.6% 77.6% 7Steam flow to turbine, lb/hr 483,000 550,000 550,000 385,000 440,000 440,000 2Turbine output, Gross MW 57 51 43 45 36 28 Unit output, Net MW 50 44 37 38 30 21 Turbine Heat Rate, Btu/kWh 9,321 11,855 14,118 9,497 13,489 17,716 Net Electric Heat Rate, Btu/kWh *** 13,361 10,944 9,343 14,314 11,191 8,778 1Overall Plant Cogeneration Efficiency *** 25.0% 48.9% 60.0% 23.8% 52.7% 66.1% 2

Footnotes 

* % of Maximum Continuous Rating (MCR) -- Boiler output in lb/hr is based on steam delivered at 1550 psi and 950 oF. 

* Outlet steam flow to Domtar-Rothschild Mill in lb/hr is based on 180 psi and 450 oF temperature steam extraction from 

** Fuel demand based on the estimated fuel moisture content of 39% *** Efficiency based on steam utilization by Domtar-Rothschild Mill. **** Minimum condenser flow cases. 
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2.4 Biomass Fuels Material Handling Processes. 

This Project will involve the installation of one new biomass fuel-fired, circulating fluidized bed (CFB) 

boiler. To support this new boiler, the Plant will require new biomass fuel handling equipment. The 

individual fuel material handling processes or operations will include delivery, unloading, conveying, 

hogging (shredding), storage, and reclaim. The biomass fuels will be received in a shredded form which 

will require final shredding to prepare the fuel for combustion. These fuels may be received either by 

self unloading trucks, or by fixed bed trucks which will be unloaded using a truck dumper. Under 

normal operation, the majority of biomass fuels will be received by the fixed bed trucks using the truck 

dumper. To control fugitive dust emissions to the highest degree possible, the truck dumper will unload 

the trucks into an enclosure. After unloading, the fuels will be conveyed via completely enclosed 

conveyors to Transfer Tower 1, and then to the Hog Building. In the Hog Building, the fuels will be 

shredded in a hog to the final size required to fire the fuels in the CFB boiler. After the Hog Building, 

the fuels will be conveyed to Transfer Tower 2, and then to the Biomass Fuels Storage Building. This 

building will have a belt tripper to load the fuels into the building, and a reclaim system to reclaim the 

fuels for delivery to the boiler. After the fuel is reclaimed, the fuel will be conveyed to Transfer Tower 

No. 1, and then to the CFB Boiler fuel silos for combustion. 

To control fugitive dust emissions from these operations, the unloading enclosure, conveyor transfer 

points, and transfer towers will be equipped with dust collection hoods. These hoods will be connected 

to an induced draft fan to collect dust generated at these points. The dust laden air will be directed to a 

fabric filter baghouse to remove PM prior to venting the air. Figure 2-5 is a diagram of the biomass 

fuels receiving, conveying, and storage processes. 

2.4.1 Process P121: Biomass Fuels Unloading, Screening, Hogging, and 

Conveying. 

Process P121 will include a dust collection system that will control dust from the unloading, conveying, 

hogging, and conveying operations. This process will include a pneumatic or mechanical fuel 

conveying system that will convey bark and wood waste from the Domtar Mill’s wood room to the Hog 

Building. The conveying air (if pneumatic) and dust collection pickup air will be exhausted to a fabric 

filter baghouse prior to discharge to the atmosphere. Figure 2-6 is a photo of a similar truck dumper and 

fuel storage building. 
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We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010  - 20 -FIGURE 2-5. Diagram of the biomass fuels receiving, conveying, and storage processes. 

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We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010 

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FIGURE 2-6. Photo of a truck dumper and A-frame fuel storage building at a biomass facility. 

2.4.2 Process F122: Self Unloading Truck Biomass Fuels Unloading. 

Biomass fuels may be delivered by self unloading semi trailer trucks and unloaded to a hopper feeding the 

same conveyor as the truck dumper hoppers.. As noted previously, the majority of the biomass fuels 

received will normally be delivered by fixed bed trucks which will be unloaded using the truck dumper 

which is included as part of Process P121. For the self unloading trucks, the maximum theoretical truck 

unloading rate is 25 tons per truck, and 5 trucks per hour, or a total of 125 tons per hour. The maximum 

theoretical annual use would be 778,700 tons per year. 

2.4.3 Process F123: Biomass Fuels Storage and Reclaim. 

After the biomass fuels are unloaded, they will be conveyed to the Hog Building to screen and shred the 

fuel. From the Hog Building the fuel will be conveyed in fully enclosed conveyors to the Biomass 

Fuels Storage building. Inside the storage building, the biomass fuels will drop from the conveyor onto 

a pile. The fuels will then be reclaimed from the storage building in a “first in, first out” material 

management system. The maximum storage building load-in rate is expected to be 250 tons per hour and 

778,700 tons per year. The maximum load-out rate is also expected to be 250 tons per hour. 

2.4.4 Process P124: Boilerhouse Fuel Storage Silos. 

Biomass fuels will be reclaimed from the storage building and conveyed via totally enclosed conveyors 

to the boiler fuel silos located inside the boilerhouse. The fuel silos will include bin vents to vent the 

silos when filling and emptying. 
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2.4.5 Process F125: Biomass Fuels Delivery Truck Haul Roads. 

Biomass fuels will be delivered to the Plant by semi-trailer trucks. The biomass fuel haul trucks are 

expected to deliver up to 10 loads per hour, and up to 778,700 tons per year, equal to 3,115 hours of 

operation and up to 31,150 deliveries. The total paved road round trip travel for each delivery is 

expected to be 3,000 feet, or 0.57 mile. Therefore, the total theoretical maximum annual paved road 

vehicle miles traveled will be 17,754 miles per year. Note that the actual travel is expected to be much 

less, since the plant will normally consume much less than the maximum theoretical fuel rate of 778,700 

tons per year. 

2.5 Process P131: CFB Boiler Bed Material Silo and Process P132: 

CFB Boiler Ash Silo. 

The CFB boiler will require an inert bed material to operate. For this biomass-fired boiler, the bed 

material will be sand. This CFB boiler bed material silo bin vent is designated as Stack S131, Process 

P131. Fly ash from the CFB boiler will be conveyed by a vacuum ash handling system to an ash storage 

silo equipped with a vent filter. The silo bin vent will allow the silo to vent when filling or emptying. 

This ash silo bin vent is designated as Stack S132, Process P132. 

2.6 Process F133: Boiler Ash Haul Roads. 

The ash from the combustion of the biomass fuels will be hauled from the site by totally enclosed 

pneumatic semi-trailer trucks. The maximum ash generation rate would be 29,200 tons per year. Based 

on a vehicle capacity of 25 tons, this annual ash generation rate would require 1,168 shipments. In 

addition, the maximum daily haul rate would be 8 shipments per day. The total paved road round trip 

travel for each delivery is expected to be 3,000 feet, or 0.57 mile. Therefore, the total annual vehicle 

miles traveled will be 1,168 vehicles and 0.57 miles per vehicle, or 666 miles per year. 

2.7 Process P141: Cooling Tower. 

We Energies’ 50 MW Biomass Fuels Cogeneration Facility will require a new mechanical draft cooling 

tower which will be designated as Process P141. This cooling tower will be a plume abated tower 

which will use additional air to desaturate the plume leaving the cooling tower to reduce visible plume 

issues and the potential for icing and fogging. 

2.8 Process P151: Emergency Diesel Feed Water Pump. 

As part of this Project, We Energies is proposing to install a new diesel (compression ignition) engine 

driven feed water pump. This emergency diesel engine will have 6 cylinders and a total displacement of 

8.1 liters, or 1.35 liters per cylinder. This diesel fire water pump will be fired by ultra low sulfur 

distillate fuel oil, and will be subject to the Standards of Performance for Stationary Compression 

Ignition Internal Combustion Engines, 40 CFR Part 60, Subpart IIII, promulgated July, 2006. Because 

this engine will be an emergency engine, We Energies is proposing operational limits of no more than 

100 hours in any 12 consecutive month period. 
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2.9 Project Schedule. 

The overall project schedule is summarized in Table 2-3. Construction activities would start in 

February, 2011 with commencement of the support facilities, and continue until the completion of the 

unit in September 2013. Commercial operation is planned for September 2013. 

TABLE 2-3. Overall project schedule. 

TASK START DATE 

Air Pollution Control Permit Application Submittal ................................................3/2010 

Select Boiler Supplier...............................................................................................2/2010 

Final PSD Air Pollution Control Permit Issued......................................................12/2010 

Certificate of Authority Issued ...............................................................................12/2010 

Finalize Boiler Contract and Release Boiler Vendor for Construction ....................2/2011 

Construction Mobilization to Site.............................................................................4/2011 

Boiler Commissioning..............................................................................................2/2013 

Project Commercial Operation .................................................................................9/2013 

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Chapter 3. Project Emissions.

3.1 Biomass-fired Circulating Fluidized Bed Boiler B01. 

The potential emissions for the biomass fuels-fired, circulating fluidized bed (CFB) boiler for the worsecase of natural gas or biomass fuels combustion are summarized in Table 3-1. 

TABLE 3-1. Potential air pollutant emissions for the proposed biomass-fired boiler B01. 

Uncontrolled 

Emission 

Factor 

Heat Input 

Capacity 

Maximum 

Theoretical 

Emissions 

Control 

Efficiency 

Controlled 

Emission 

Factor 

Potential to Emit 

Pollutant 

lb/mmBtu mmBtu/hr lb/hr tons/yr % lb/mmBtu lb/hr tons/yr

Carbon 

Monoxide CO 0.20 800 160 701 0.20 160.0 700.8

Nitrogen 

Oxides NOx 0.15 800 120 526 33% 0.10 80.0 350.4

Particulate 

Matter 

PM / 

PM10

12.0 800 9,600 42,048 99.75% 0.030 24.0 105.1

Particulate 

Matter PM2.5 9.0 800 7,200 31,536 99.74% 0.023 18.4 80.6

Sulfur 

Dioxide SO2 0.09 800 72 315 0.09 72.0 315.4

Organic 

Compounds OC 0.017 800 13.6 60 0.017 13.6 59.6

Lead Pb 0.00003 800 0.02 0.11 0.00003 0.024 0.11

Mercury Hg 0.0000029 800 0.0023 0.01 0.0000029 0.0023 0.01

Fluorides 

(as HF) HF 0.001 800 0.8 3.5 0.001 0.80 3.5

Sulfuric Acid 

Mist H2SO4 0.0018 800 1.4 6.3 0.0018 1.4 6.3

Footnotes 

1. Potential controlled emission rates for CO, NOx, PM/PM10, PM2.5, SO2, VOC, and fluorides are based on the 

proposed BACT emission limits in this control technology review. 

2. The lead emission factor is from the U.S. EPA document, Compilation of Air Pollutant Emission Factors, 

AP-42, 5th Edition, Wood Residue Combustion in Boilers, Table 1.6-4. 

3. The mercury emission factor is based on the proposed case-by-case MACT emission limit for mercury 

contained in Appendix D of the application. 

4. Sulfuric acid mist emissions are estimated to be 2% of the sulfur dioxide emissions on a mass basis. 

 
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3.2 Natural Gas-Fired Package Boilers B02 and B03. 

The potential emissions for each natural gas-fired package boiler are summarized in Table 3-2. 

TABLE 3-2. Potential air emissions for each package Boiler B02 and B03. 

Uncontrolled 

Emission Factor 

Maximum 

Heat Input 

Potential to Emit Pollutant 

lb/mmft3 lb/mmBtu mmBtu/hr lb/hr tons/yr

Carbon Monoxide CO 63.0 0.06 175 10.50 32.6

Nitrogen Oxides NOx 21.0 0.02 175 3.50 10.9

Particulate Matter PM/PM10 7.6 0.0076 175 1.33 4.1

Particulate Matter PM2.5 7.6 0.0076 175 1.33 4.1

Sulfur Dioxide SO2 0.60 0.0006 175 0.11 0.3

Organic Compounds OC 5.5 0.006 175 1.05 3.3

Lead Pb 0.00050 0.0000005 175 0.000083 0.00026

Mercury Hg 0.00026 0.0000002 175 0.000043 0.00013

Fluorides (as HF) HF 0.0 0.00062 175 0.11 0.34

Sulfuric Acid Mist H2SO4 0.006 0.000006 175 0.0011 0.0033

Footnotes 

1. For natural gas combustion, the CO and NOx emission rates are based on concentrations of 100 and 9 ppm at a 

flue gas excess oxygen content of 5%. Potential emissions are based on CO and NOx emission rates of 0.10 and 

0.02 lb/mmBtu, respectively. 

E = KChF(20.9) where, E = Emission Rate, lb/mmBtu 

 20.9 - %O2 F = F-Factor, dscf/mmBtu 

 

Natural Gas Combustion K Ch, ppm F, dscf/mmBtu %O2 E, lb/mmBtu

Carbon Monoxide CO 7.59E-08 75 8,710 5.0 0.058 

Nitrogen Oxides NOx 1.19E-07 9 8,710 5.0 0.012 

2. The emission factors for uncontrolled PM, PM10, PM2.5, VOC, lead, and mercury emissions are from the U.S. 

EPA’s AP-42, Compilation of Air Pollutant Emission Factors, 5th Edition, section 1.4, Natural Gas Combustion. 

All PM10 emissions are assumed to be PM2.5. 

3. Sulfuric acid mist emissions for natural gas combustion are based on 1% conversion of SO2 to SO3. 

6. Potential emissions are based on limiting the fuel use to: 

Natural Gas: HI = 1,085,000 mmBtu, 12-month average 6,200 hour/yr 
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3.3 Biomass Fuels Material Handling Processes. 

3.3.1 Process P121: Biomass Fuels Unloading, Screening, Hogging, and 

Conveying.

Based on the control technology review in Appendix C, the dust collector will be equipped with filters 

which are expected to control PM/PM10, and PM2.5 emissions to a maximum design outlet grain loading 

of 0.004 gr/dscf, and 0.002 gr/dscf, respectively. Therefore, the maximum PM/PM10, and PM2.5

emission rates are: 

E = (109,300 ft3

/min)(60 min/hr)(0.004 gr/ft3)(1.0 lb/7,000 gr) = 3.75 lb PM/PM10/hr 

E = (3.75 lb/hr)(8,760 hr/yr)(1.0 ton/2,000 lb) = 16.4 ton PM/PM10/yr 

E = (109,300 ft3

/min)(60 min/hr)(0.002 gr/ft3)(1.0 lb/7,000 gr) = 1.87 lb PM2.5/hr 

E = (1.87 lb/hr)(8,760 hr/yr)(1.0 ton/2,000 lb) = 8.2 ton PM2.5 /yr

3.3.2 Process F122: Self Unloading Truck Biomass Fuels Unloading

Biomass fuels may be delivered by self unloading semi trailer trucks and unloaded to a hopper feeding the 

truck dumper conveyor system. The U.S. EPA’s AP-42, Compilation of Air Pollutant Emission 

Factors, 5th Edition, section 13.2.4, Equation 1 may be used for estimating emissions from this unloading 

process which is a drop operation: 

1.4

1.3

2

5 (0.0032)

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡

= M

U

E k

where, E = Emission factor, pound per ton of biomass fuels unloaded 

U = Mean wind speed, mph = 6.9 

M = Material moisture content, % = 25 

k = Particle size multiplier (dimensionless) 

k = 0.053 (for PM2.5) = 0.35 (for PM10) = 0.74 (for PM)

The normal moisture content for biomass fuels is expected to range from 25-50% on an as-received basis. 

Based on a mean wind speed of 6.9 miles per hour, the uncontrolled emission factor for unloading biomass 

fuels is 0.0000075 lb/ton (PM2.5), 0.0000496 lb/ton (PM10), and 0.00010 lb/ton (PM). 

As noted previously, the majority of the biomass fuels received will normally be delivered by fixed bed 

trucks which will be unloaded using the truck dumper which is included as part of Process P121. For the 

self unloading trucks which will unload to a reclaim hopper, the maximum theoretical truck unloading rate 
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is 25 tons per truck, and 5 trucks per hour, or a total of 125 ton per hour. The maximum annual use is 

expected to be 778,700 tons per year. Based on these values, the maximum uncontrolled PM2.5, PM10, and 

PM emissions are expected to be 6, 39, and 82 pounds per year, respectively. 

3.3.3 Process F123: Renewable Fuels Storage and Reclaim. 

Emissions from the load-in and load-out or reclaim “drop” operations may be estimated using the U.S. 

EPA’s AP-42, Compilation of Air Pollutant Emission Factors, 5th Edition, section 13.2.4, Equation 1: 

1.4

1.3

2

5 (0.0032)

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡

= M

U

E k

where, E = Emission factor, pound per ton of biomass fuels unloaded 

U = Mean wind speed, mph = 1.0 

M = Material moisture content, % = 25% 

k = Particle size multiplier (dimensionless) 

k = 0.053 (for PM2.5) = 0.35 (for PM10) = 0.74 (for PM)

The normal moisture content for renewable biomass fuels is expected to range from 25-50% on an asreceived basis. Based on a mean wind speed of 1.0 miles per hour inside the building, the uncontrolled 

emission factor for unloading biomass fuels is 6.0 x 10-7 lb/ton (PM2.5), 4.0 x 10-6 lb/ton (PM10), and 8.5 x 

10-6 lb/ton (PM). Based on these values, the maximum uncontrolled PM2.5, PM10, and PM emissions are 

expected to be 1, 6, and 14 pounds per year, respectively. 

3.3.4 Process P124: Boilerhouse Fuel Storage Silos. 

The bin vents are expected to have an airflow of 300 cubic feet per minute at an uncontrolled grain 

loading of 0.04 grains per dry standard cubic foot of exhaust gas. Based on the control technology 

review, we have concluded that the bin vents can achieve a PM and PM10 outlet grain loading of 0.004 

gr/dscf, and a PM2.5 outlet grain loading of 0.002 gr/dscf. Therefore, potential controlled PM/PM10

emissions would be 0.01 lb/hr and 0.045 ton/yr; potential controlled PM2.5 emissions would be 0.005 

lb/hr and 0.022 ton/yr. 

3.3.5 Process F125: Renewable Fuels Delivery Truck Haul Roads. 

Emissions from the truck haul truck traffic may be calculated using the paved roads emission factor 

from AP-42 (revision 11/2006), Section 13.2.1: Paved Roads, Equation (1): 

C sL W EF k u − ⎥

⎦

⎤ ⎢

⎣

⎡ ⎥

⎦

⎤ ⎢

⎣

⎡ =

0.65 1.5

2 3

where, EFu = Vehicle Emission Factor, lb/mile traveled 
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We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010 

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k = 0.0024 [Table 13.2.1-1, for PM2.5] = 0.016 [PM10] = 0.082 [PM] 

sL = silt loading, g/m2

 = 0.6 

W = Average weight of truck (empty = 15 tons; loaded = 40 tons) 

W = 27.5 tons 

 C = emission factor for vehicle fleet exhaust, brake wear and tire wear. 

 C = 0.00036 lb/VMT [Table 13.2.1-2, for PM2.5] 

 C = 0.00047 lb/VMT [Table 13.2.1-2, for PM10 and PM] 

The silt loading of 0.6 g/m2

 is the ubiquitous silt loading default value for roads with less than 500 

miles average daily travel (ADT) from AP-42, Table 13.2.1-3. The vehicle weight is the average truck 

weight, with a loaded weight of 40 tons, and an empty weight of 15 tons. Based on these values, the 

fuel and ash haul truck traffic is expected to have uncontrolled emission factors of 0.030 pounds per 

vehicle mile traveled (lb/VMT) for PM2.5, 0.20 lb/VMT (PM10), and 1.04 lb/ton (PM). 

The renewable fuel haul trucks are expected to deliver up to 10 loads per hour, and up to 778,700 tons 

per year, equal to 3,115 hours of operation and up to 31,150 deliveries. The total paved road round trip 

travel for each delivery is expected to be 3,000 feet, or 0.57 mile. Therefore, the total annual paved road 

vehicle miles traveled will be 17,754 miles per year. Based on these values, the maximum uncontrolled

PM2.5, PM10, and PM emissions for the renewable fuels truck traffic would be 0.3, 1.8, and 9.2 tons per 

year, respectively. 

3.4 Process P131: CFB Boiler Bed Material Silo and Process P132: 

CFB Boiler Ash Silo. 

Both the CFB boiler bed material silo bin vent and the ash silo bin vent are expected to have a 

volumetric flow rate of 1,000 acfm (each). Based on the control technology review, we have concluded 

that the bin vents can achieve a PM and PM10 outlet grain loading of 0.004 gr/dscf, and a PM2.5 outlet 

grain loading of 0.002 gr/dscf. Therefore, potential controlled PM/PM10 emissions for each process 

would be 0.034 lb/hr and 0.15 ton/yr; potential controlled PM2.5 emissions would be 0.012 lb/hr and 

0.075 ton/yr. 

3.5 Process F133: Boiler Ash Haul Roads. 

Emissions from the truck haul truck traffic may be calculated using the paved roads emission factor 

from AP-42 (revision 11/2006), Section 13.2.1: Paved Roads, Equation (1) as described above. The 

maximum ash generation rate would be 29,200 tons per year. Based on a vehicle capacity of 25 tons, 

this annual ash generation rate would require 1,168 shipments. In addition, the maximum daily haul rate 

would be 8 shipments per day. The total paved road round trip travel for each delivery is expected to be 

3,000 feet, or 0.57 mile. Therefore, the total annual vehicle miles traveled will be 1,168 vehicles and 

0.57 miles per vehicle, or 666 miles per year. Based on these values, the maximum uncontrolled PM2.5, 

PM10, and PM emissions for the ash truck traffic would be 0.01, 0.07, and 0.35 tons per year, respectively. 
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3.6 Process P141: Cooling Tower. 

In a mechanical draft cooling tower, the circulating cooling water is introduced into the top of the tower. 

As the water falls through the tower, an air flow is induced in a countercurrent flow using an induced 

draft fan. A portion of the circulating water evaporates, cooling the remaining water. A small amount of 

the water is entrained in the induced air flow in the form of liquid phase droplets or mist. Demisters are 

used at the outlet of cooling towers to reduce the amount of water droplets entrained in the air. The 

water droplets that pass through the demisters and are emitted to the atmosphere are called drift loss. 

When these droplets evaporate, the dissolved solids in the droplet become particulate matter. 

Therefore, cooling towers are sources of PM, PM10, and PM2.5 emissions. 

Cooling tower PM emissions are calculated based on the circulating water flow rate, the total dissolved 

solids (TDS) in the circulating water, and the design drift loss according to the following equation: 

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡ = 100

%DL

10

C E (60 min/hr)(8.345 lb water/gal) 6

TDS kQ

Where, E = Particulate matter emissions, pounds per hour 

 Q = Circulating water flow rate, gallons per minute = 22,000 gpm 

 CTDS = Circulating water total dissolved solids, parts per million = 1,600 ppm 

 DL = Drift loss, % = 0.0005% 

 k = particle size multiplier, dimensionless 

The value of the particle size multiplier (k) is based on the distribution of water droplet size in the 

cooling tower drift loss. The diameter of the airborne particle that would be produced by the 

evaporation of the liquid water from a drift droplet is given by the following equation1

: 

 Where, ddroplet = Maximum diameter of the drift droplet that would produce a dry 

particle size of dparticle or smaller 

 dparticle = Dry particle (particulate matter) particle size, microns

 ρsalt = Density of particle = 2.5 g/cm3

 ρwater = Density of water = 1.0 g/cm3

 CTDS = Circulating water total dissolved solids, parts per million, ppm 

For a circulating water total dissolved solids (TDS) level of 1,600 ppm, the drift loss droplet size would 

need to be smaller than 116 microns in size to form PM10 emissions, and less than 29 microns to form 

PM2.5. The table below is the drift loss droplet size distribution for this cooling tower. From this table, 

 

1

 From the paper Cooling Tower Emissions Quantification Using the Cooling Technology Institute Test Code ATC40, Cooling Technology Institute, Paper No. TP03-08, K. Hennon, D. Wheeler, Power Generation Technologies. 

1/3 6 10 ⎥

⎦

⎤ ⎢

⎣

⎡ =

water TDS

salt

droplet particle C

d d

ρ

ρ
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We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010 

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82% of the cooling tower drift loss (i.e., droplet particle sizes less than 130 microns), would result in 

PM10 emissions, and 0.23% of the cooling tower drift loss would result in PM2.5 emissions. 

Size Distribution for Cooling Tower Particulate Emissions * 

EPRI Droplet Diameter, um EPRI % Mass Smaller 

10 0.00 

20 0.20 

30 0.23 

40 0.51 

50 1.82 

60 5.70 

70 21.35 

90 49.81 

110 70.51 

130 82.02 

150 88.01 

180 91.03 

210 92.47 

240 94.09 

270 94.69 

300 96.29 

350 97.01 

400 98.34 

450 99.07 

500 99.07 

600 100.00 

* Methodology and EPRI droplet diameter and % mass smaller values 

from Reisman, J. and Frisbie, G., "Calculating Realistic PM10

Emissions from Cooling Towers." 

TABLE 3-3. Potential emissions for the new mechanical draft cooling tower, Process P141. 

Flowrate CTDS Drift Loss Emission Rate 

POLLUTANT 

gal/min ppm % 

k

lb/hr ton/yr

Particulate Matter PM 22,000 1,600 0.0005% 1.00 0.088 0.386

Particulate Matter PM10 22,000 1,600 0.0005% 0.82 0.072 0.317

Particulate Matter PM2.5 22,000 1,600 0.0005% 0.0023 0.00020 0.00087
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3.7 Process P151: Emergency Diesel Engine Feed Water Pump. 

The potential emissions for this new diesel engine driven feed water pump based on these standards are 

summarized in Table 3-4. 

TABLE 3-4. Potential emissions for the diesel engine driven feed water pump based on limiting 

operation to 100 hours per year. 

Emission 

Factor 

Engine 

Output Potential to Emit Pollutant 

g/hp-hr hp lb/hr tons/year 

Carbon Monoxide CO 2.61 400 2.30 0.11

Nitrogen Oxides NOx 3.00 400 2.64 0.13

Particulate Matter PM/PM10 0.15 400 0.132 0.0066

Particulate Matter PM2.5 0.12 400 0.106 0.0053

Sulfur Dioxide SO2 0.0057 400 0.0050 0.0003

Volatile Organic Compounds VOC 3.00 400 2.64 0.13

Lead Pb 0.000034 400 0.000030 0.000002

Mercury Hg 0.000011 400 0.000010 0.000001

Fluorides HF 0.0010 400 0.00090 0.000045

Sulfuric Acid Mist H2SO4 0.00057 400 0.00050 0.000025

 

Footnotes 

1. NOx, PM, and PM10, emission factors are the NSPS standards in 40 CFR Part 60, Subpart IIII, Table 4 for 

model year 2009 and later stationary fire pump engines between 175 and 300 horsepower. 

2. SO2 emissions are based on 0.0015% sulfur fuel oil and a maximum oil consumption of 24.0 gph: 

Emissions = (0.0015 lb S/100 lb oil)x(2.0 lb SO2/lb S)x(24 gal oil/hr)x(7.0 lb oil/gal) 

Emissions = 0.005 lb/hr 

3. Lead and mercury emissions are based on the emission factors for distillate oil combustion from the U.S. EPA's 

Compilation of Air Pollutant Emission Factors, AP-42, Table 1.3-10. For example, the lead emission factor is 9 

pounds of lead per 1012 Btu of fuel oil: 

Emissions = (9.0 x 10-12 lb Pb/Btu) x (24 gal/hr) x (140,000 Btu/gal) = 0.00003 lb/hr 

4. Fluoride emissions are based on the emission factor for No. 6 oil combustion from the U.S. EPA's AP-42, Table 

1.3-11. The fluoride emission factor is 0.0373 lb per 1,000 gallons of oil: 

Emissions = (0.0373 lb F/1,000 gallons oil) x (24 gal/hr) = 0.0009 lb/hr 

6. Sulfuric acid emissions are estimated at 10% of the total sulfur dioxide emissions. 
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Chapter 4. Applicable Air Pollution 

Control Regulations. 

4.1 Total Project Emissions and the Prevention of Significant 

Deterioration (PSD) Program. 

Under the Prevention of Significant Deterioration (PSD) program in NR 405.02(22)(a), Wis. Adm. 

Code, the major stationary source threshold for this facility is 100 tons per year. Table 3-1 is a 

summary of the potential emissions for the facility based on the proposed control technologies and 

emission limits representing the best available control technology (BACT) as summarized in Chapter 4. 

Based on the total potential emissions in Table 4-1, the Project will be subject to the PSD program for 

carbon monoxide (CO), nitrogen oxides (NOx), particulate matter (PM/PM10), fine particulate matter 

(PM2.5), sulfur dioxide (SO2), organic compounds (VOC), and fluorides (as HF). Note that this PSD 

applicability analysis is based only on the new facility. Although emissions from the existing Domtar 

Mill will be reduced after this Project, no netting or project emissions accounting has been used to 

reduce the potential emissions for the new facility. 

TABLE 4-1. Total facility emissions and the PSD applicability for the We Energies' 50 MW 

biomass fuels-fired cogeneration facility. 

Potential to Emit, ton/year 

 POLLUTANT Boiler 

B01 

Boilers 

B02 & B03

Diesel 

Pump 

Material 

Handling

Cooling 

Tower TOTAL 

PSD 

Significant 

Threshold

OVER?

Carbon Monoxide CO 700.8 65.1 0.11 766 100 YES 

Nitrogen Oxides NOx 350.4 21.7 0.13 372 40 YES 

Particulate Matter PM10 105.1 8.2 0.007 17.1 0.3 131 15 YES 

Particulate Matter PM2.5 80.6 8.2 0.005 8.4 0.0009 97 10 YES 

Sulfur Dioxide SO2 315.4 0.7 0.0003 316 40 YES 

Organic Compounds VOC 59.6 6.5 0.13 66 40 YES 

Lead Pb 0.11 0.0005 0.000002 0.11 1 NO 

Mercury Hg 0.01 0.0003 0.000001 0.01 N/A 

Fluorides (as HF) HF 3.5 0.7 0.000045 4.2 3 YES 

Sulfuric Acid Mist H2SO4 6.3 0.007 0.000025 6.3 7 NO 
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4.2 Biomass-Fuel Fired Boiler B01. 

4.2.1 New Source Performance Standards (NSPS), NR 440, Wis. Adm. Code. 

The New Source Performance Standards for electric steam generating units are contained in NR 440.20, 

Wis. Adm. Code and 40 CFR Part 60, Subpart Da. The applicability and designation of affected facility 

in NR 440.20(1)(a) states that the affected facility to which this section applies is each electric utility 

steam generating unit that is capable of combusting more than 250 million Btu/hour heat input of fossil 

fuel, either alone or in combination with any other fuel, and for which construction or modification is 

commenced after September 18, 1978. Boiler B01 will have a maximum design heat input when firing 

natural gas of less than 250 mmBtu per hour. Therefore, this boiler is not subject to NR 440.20, Wis. 

Adm. Code and 40 CFR Part 60, Subpart Da. 

The New Source Performance Standards for industrial – commercial – institutional steam generating 

units are contained in NR 440.205, Wis. Adm. Code and 40 CFR Part 60, Subpart Db. This subpart 

applies to steam generating units that commence construction, modification, or reconstruction after June 

19, 1984, and that have a heat input capacity greater than 100 mmBtu/hr. Boiler B01 will be subject to 

40 CFR Part 60, Subpart Db. 

4.2.1.1 Nitrogen Oxides (NOx): 0.10 lb/mmBtu. 

The current Subpart Db rules for NOx emissions were published in the Federal Register June 13, 2007. 

Under 40 CFR § 60.44b(d), an affected facility that simultaneously combusts natural gas with wood, 

municipal-type solid waste, or other solid fuel, except coal, may not exceed a NOx emission rate of 0.30 

lb/mmBtu heat input unless the affected facility has an annual capacity factor for natural gas of 10% or 

less and is subject to a federally enforceable requirement that limits operation of the affected facility to 

an annual capacity factor of 10% or less for natural gas. 

Under 40 CFR § 60.44b(d)(l) an affected facility which commenced construction or reconstruction after 

July 9, 1997 and that combusts coal, oil, or natural gas, or a mixture of these fuels, or with any other 

fuels may not exceed 0.20 lb/million Btu heat input unless the affected facility has an annual capacity 

factor for coal, oil, and natural gas of 10% or less and is subject to a federally enforceable requirement 

that limits operation of the facility to an annual capacity factor of 10% or less for coal, oil, and natural 

gas. Under (2), if the affected facility has a low heat release rate and combusts natural gas or distillate 

oil in excess of 30 percent of the heat input from the combustion of all fuels, the limit is determined as: 

En = [(0.10 * Hgo) + (0.20 * Hr)]/(Hgo + Hr) 

Where, En = NOx emission limit, lb/million Btu, 

Hgo = Heat input from combustion of natural gas or distillate oil, and 

Hr = Heat input from combustion of any other fuel. 

Under sub (2), the most stringent limit would be 0.10 lb/mmBtu when firing 100% natural gas or 

distillate fuel oil. 
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4.2.1.2 Particulate Matter (PM): 0.085 lb/mmBtu. 

The current Subpart Db rules for PM emissions were published in the Federal Register June 13, 2007. 

Under 40 CFR § 60.43b(h)(4), an affected facility that commences modification after February 28, 

2005, that combusts over 30 percent wood (by heat input) on an annual basis, and has a maximum heat 

input capacity greater than 250 mmBtu/hr may not exceed a PM emission rate of 0.085 lb/mmBtu heat 

input. The PM emission standards and opacity limits under § 60.43b apply at all times except during 

periods of startup, shutdown, or malfunction. Compliance with the PM emission standards under § 

60.43b are determined through performance testing using Reference Method 5, 5B, or 17. This standard 

does not include condensable PM emissions. 

In addition to the PM standard, under 40 CFR § 60.43b(f), no owner or operator of an affected facility 

that can combust coal, oil, wood, or mixtures of these fuels with any other fuels shall cause to be 

discharged into the atmosphere any gases that exhibit greater than 20 percent opacity (6-minute 

average), except for one 6-minute period per hour of not more than 27 percent opacity. The PM and 

opacity standards apply at all times, except during periods of startup, shutdown, or malfunction. 

4.2.1.3 Sulfur Dioxide (SO2): 0.20 lb/mmBtu. 

The current Subpart Db rules for SO2 emissions were published in the Federal Register June 13, 2007. 

Under 40 CFR § 60.42b(k)(1), an affected facility that commenced construction, reconstruction, or 

modification after February 28, 2005, and that combusts coal, oil, natural gas, a mixture of these fuels, 

or a mixture of these fuels with any other fuels may not exceed: 1) An SO2 emission rate of 0.20 

lb/mmBtu, or 2) 8% of the potential SO2 emission rate (92% reduction) and 1.2 lb/mmBtu. 

4.2.2 National Emission Standards for Hazardous Air Pollutants, NR 460, Wis. 

Adm. Code. 

Section 112 of the 1990 Clean Air Act Amendments requires the U.S. EPA to develop standards to 

control major sources of hazardous air pollutants (HAPs) to levels consistent with the lowest emitting 

facilities in similar source categories. These National Emissions Standards for Hazardous Air Pollutants 

(NESHAPs) require the application of the maximum achievable control technology (MACT). The U.S. 

EPA promulgated National Emission Standards for Hazardous Air Pollutants for Industrial, 

Commercial, and Institutional Boilers and Process Heaters under 40 CFR Part 63, Subpart DDDDD. 

However, this regulation has been vacated. 

Section 112(g)(2) of the CAA requires a permitting authority to conduct a “case-by-case” MACT 

determination for new major sources where EPA has not established applicable standards. Because the 

U.S. EPA has no established MACT standards for new industrial boilers, and because the proposed 

Boiler B01 has potential HAP emissions in excess of the major source threshold, this boiler is subject to 

the case-by-case MACT requirements under 40 CFR Part 63. 

This Project meets the definition of “construct a major source” in 40 CFR. § 63.41(2). Boiler B01 will 

be constructed at an existing facility and it will be a major source of HAPs in and of itself. However, 

section 112(g) applies to the proposed boiler but not to the existing Domtar Mill. (61 Fed. Reg. 68384, 
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68385 and 68390, December 27, 1996. A new unit at an existing major source must itself be inherently 

emitting). See also U.S. EPA document dated March 13, 1997, Questions and Answers on 112(g) Final 

Rule, Q9, A9 (when a new major process unit is added to an existing facility, only the new process unit 

is subject to review under 112(g), not the entire facility). Based upon the definition of “construct a 

major source” within 40 CFR § 63.41 the biomass-fired CFB boiler is the only unit subject to section 

112(g), since it is the only unit associated with this Project that would itself be a major source of HAPs. 

4.2.3 Federal Acid Rain Program, NR 409 Wis. Adm. Code. 

The federal Acid Rain Program regulations in 40 CFR 72.6(a)(3)(i) state that a utility unit that is a new 

unit shall be an affected unit, and any source that includes such a unit shall be an affected source, 

subject to the requirements of the Acid Rain Program. A “utility unit” means a unit owned or operated 

by a utility that serves a generator in any State that produces electricity for sale. Finally, “Unit” means a 

fossil fuel-fired combustion device. Because Boiler B01 fires natural gas (although only as a startup 

and load stabilization fuel), and because Boiler B01 serves a 50 MW electric generator, Boiler B01 is an 

affected unit under the federal Acid Rain Program. 

4.2.4 Clean Air Interstate Rule, NR 432, Wis. Adm. Code. 

On March 10, 2005, the U.S. EPA announced the Clean Air Interstate Rule (CAIR), a rule designed to 

achieve reductions in nitrogen oxides (NOx) and sulfur dioxide (SO2) emissions which the EPA linked 

to the interstate transport of fine particulate matter (PM2.5). The CAIR is based on a cap-and-trade 

program in which affected sources use allowances to cover NOx and SO2 emissions. In Wisconsin, 

CAIR NOx allowances are allocated under NR 432, Wis. Adm. Code. 

NR 432.01 Applicability; purpose. (1) APPLICABILITY. 

(a) This chapter applies to the owner or operator of any source that 

includes a CAIR NOx unit or a CAIR renewable unit. A CAIR 

NOx unit is any stationary, fossil fuel−fired boiler or stationary, 

fossil fuel−fired combustion turbine which has served at any time, 

since the later of November 15, 1990 or the start−up of the unit’s 

combustion chamber, a generator with nameplate capacity of more 

than 25 MWe producing electricity for sale, except for those units 

that are excluded under par. (b). 

Note: In addition, a CAIR NOx unit is subject to the requirements of 40 CFR part 97, 

Subparts AA, BB, CC, FF, GG, HH, AAAA, BBBB, CCCC, FFFF, GGGG, and 

HHHH. 

Although Boiler B01 is primarily fueled with biomass fuels, Boiler B01 will also fire natural gas – a 

fossil fuel – during startup and load stabilization. Because Boiler B01 will fire a fossil fuel and will 

serve a generator with nameplate capacity of more than 25 MWe and will produce electricity for sale, 

Boiler B01 will be a CAIR NOx unit. 

Under NR 432.02(15), a “CAIR renewable unit” is an installed and operational electric generating 

facility, located in Wisconsin, commencing operation after January 1, 2001 that generates renewable 

energy serving a generator with nameplate capacity greater than 25 MWe. Because “renewable energy” 
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means electricity derived from a renewable resource, and because “Renewable resource” includes 

biomass, this unit qualifies as a CAIR renewable unit under NR 432.07, Wis. Adm. Code. 

4.2.5 Section 112(r) Prevention of Accidental Releases (40 CFR Part 68). 

The CAA amendments of 1990 included language that requires chemical accident prevention provisions 

for affected facilities. Section 112(r), Prevention of Accidental Releases, established requirements for 

owners and operators of stationary sources that produce, process, handle or store regulated chemicals. 

The purpose of this requirement is to prevent and mitigate accidental releases of these substances by 

preparing a detailed risk assessment and implementing a number of safety procedures through the 

preparation of a Risk Management Plan. 

Affected facilities are those stationary sources that store, use or handle any of the 140 listed hazardous 

substances in amounts greater than the listed threshold quantities. An analysis will be done after the 

design is finalized to determine if the Plant will store any of the listed chemicals or substances in 

quantities near or above the threshold levels. Regardless, the Plant will still comply with the general 

duty clause of the CAA section 112(r)(1). 

4.2.6 State of Wisconsin Requirements. 

4.2.6.1 Control of Hazardous Pollutants under NR 445, Wis. Adm. Code. 

Wisconsin regulates hazardous air pollutants (HAP) under NR 445, Wis. Adm. Code. The applicability 

and purpose under NR 445.01 is stated below. 

NR 445.01 Applicability; purpose. (1) APPLICABILITY. 

(a) This chapter applies to all stationary air contaminant sources 

which may emit hazardous contaminants and to their owners and 

operators. 

Note: Owners and operators of sources of emissions of hazardous air contaminants 

associated with agricultural waste should refer to s. NR 445.08 (6) (d) prior to 

undertaking any activities under this chapter. 

(b) The emission limitations and control requirements in this 

chapter do not apply to hazardous air contaminants emitted by the 

emissions units, operations or activities that are regulated by an 

emission standard promulgated under section 112 of the Clean Air 

Act (42 USC 7412). Hazardous air contaminants “regulated by an 

emission standard promulgated under section 112 of the Act” 

means the hazardous air contaminants that are regulated by section 

112 by the name of the contaminant, by virtue of regulation of 

another substance as a surrogate for the contaminant, or by virtue 

of regulation of a species or category of hazardous air 

contaminants that includes the contaminant. 

Note: An example of regulated “by virtue of regulation of another substance as a 

surrogate” would be using the measurement of one contaminant to represent the 

emission rate of another, harder to measure contaminant. Examples of regulated “by 

virtue of the regulation of a species or category” would be the use of terms such as 

“volatile organic HAP” or “total HAP” emission in lieu of specifically naming 

individual hazardous air contaminants. 

Based on the applicability requirements in NR 445.01(b), NR 445 does not apply to HAPs emitted by 

emissions units that are regulated by an emission standard under section 112 of the Clean Air Act. The 
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applicability rule explains that the HAPs that are regulated by section 112 include those HAPs that are 

regulated by: 1) the name of the contaminant, 2) by virtue of regulation of another substance as a 

surrogate for the contaminant, or 3) by virtue of regulation of a species or category of hazardous air 

contaminants that includes the contaminant. The note explains that regulated “by virtue of the 

regulation of a species or category” would be the use of terms such as “volatile organic HAP” or “total 

HAP” emission in lieu of naming specific HAPs. 

We Energies has prepared a case-by-case MACT analysis for the biomass-fired and natural gas-fired 

boilers. The MACT analysis is based on dividing the HAPs into four categories: 1) Inorganic, solid 

phase HAPs, 2) Inorganic, acid gas HAPs including hydrogen chloride (HCl) and hydrogen fluoride 

(HF), 3) Organic HAPs, and 4) Mercury. We Energies has proposed work practices and emission 

standards which represent the case-by-case MACT for each of these HAP species or categories. 

Table 4-2 is a summary of the HAPs emitted by the biomass-fired boiler, including the HAP category, 

and the proposed case-by-case MACT standard. From Table 4-2, all of the HAPs emitted by the 

biomass boiler that are regulated under NR 445 have a MACT standard, except ammonia. Ammonia is 

not a federal HAP, so the case-by-case MACT analysis did not consider ammonia emissions. Ammonia 

would be emitted as a result of ammonia slip from the SNCR NOx control system. The NR 445.07 

Table A threshold values for emissions from stacks greater than 75 feet are 28.2 pounds per hour and 

612,587 tons per year. At an ammonia slip rate of 30 ppm at 5% excess oxygen, total potential 

ammonia emissions would equal 14.0 lb/hr, and 122,303 lb/year, which are less than the threshold 

values. 

4.2.6.2 Control of Mercury Emission, NR 446, Wis. Adm. Code. 

Wisconsin regulates mercury emissions under NR 446, Wis. Adm. Code. The mercury emission limits 

under NR 446.03 are stated below. 

 NR 446.03 Mercury emission limits. (1) No person 

may cause, allow or permit emissions of mercury in such quantity 

and duration as to cause the ambient air concentration to exceed 

1 μg/m3, averaged over a 30−day period. 

 (2) (a) No person may commence construction or modification 

of a stationary source that results in an increase in annual 

allowable emissions of mercury of 10 pounds or more from the 

new or modified source unless the person has obtained a permit 

under ch. NR 406. The department may not issue a permit under 

ch.NR406 for the source unless the department finds that emissions 

of mercury will be controlled to a level which is best available 

control technology. 

(b) New or modified stationary sources that are subject to an 

emission limit for mercury required under section 111 or 112 of 

the Act (42 USC 7411 and 7412 respectively) are exempt from the 

requirements of this section. 

Because the new biomass-fired boiler is subject to a case-by-case MACT requirement under section 

112(g)(2) of the CAA, this boiler is not subject to the mercury emission limits under NR 446, Wis. 

Adm. Code. 
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4.2.6.3 Particulate Matter. 

Wisconsin regulates emissions of particulate matter from fuel burning installations under NR 415.06, 

Wis. Adm. Code. Under NR 415.06(2)(c), fuel burning installations on which construction or 

modification is commenced after April 1, 1972 with a heat input rating of more than 250 million Btu per 

hour, are limited to emissions from any stack of not more than 0.10 pounds of particulate matter per 

million Btu heat input. 

4.2.6.4 Visible Emissions (Opacity). 

Wisconsin regulates visible emissions under NR 431, Wis. Adm. Code. Direct sources on which 

construction is commenced after April 1, 1972 are regulated under NR 431.05. This section states: 

 NR 431.05 Emission limitations after April 1, 1972. 

No owner or operator of a direct or portable source on which 

construction or modification is commenced after April 1, 1972 

may cause or allow emissions of shade or density greater than 

number 1 of the Ringlemann chart or 20% opacity with the following exceptions: 

 (1) When combustion equipment is being cleaned or a new 

fire started, emissions may exceed number 1 of the Ringlemann 

chart or 20% opacity but may not exceed number 4 of the Ringlemann chart or 80% opacity for 6 minutes in any one hour. 

Combustion equipment may not be cleaned nor a fire started more 

than 3 times per day. 
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TABLE 4-2. Hazardous air emissions for the biomass-fired boiler B01. 

HAP 

Category 

NR 445 

Table A 

Reference 

Hazardous Air Contaminant 

NR 445 

Table A 

Reference

Hazardous Air Contaminant 

24 Antimony 

26 Arsenic 

30 Barium 

43 Beryllium 

71 Cadmium 

107 Chromium, total 

109 Chromium, hexavalent 

111 Cobalt 

113 Copper 

275 Iron 

293 Manganese 

334 Molybdenum 

343 Nickel 

394 Phosphorus 

421 Selenium 

n/a Strontium 

452 Tin 

Inorganic, Solid Phase 

482 Vanadium 

Acid 264 Hydrogen chloride 

Gases 266 Hydrogen fluoride 

1 Acetaldehyde 155 1,2−Dichloroethane 

n/a Acetone 158m Dichloromethane 

5 Acetophenone 160 1,2-Dichloropropane 

6 Acrolein 2,4-Dinitrophenol 

32 Benzene 213 Ethylbenzene 

31 Benzo(a)anthracene 239 Formaldehyde 

37 Benzo(a)pyrene 271 Indeno(1,2,3,c,d)pyrene 

34 Benzo(b)fluoranthene 2-Methylnaphthalene 

37 Benzo(e)pyrene 341 Naphthalene 

 Benzo(g,h,i)perylene 2-Nitrophenol 

35 Benzo(j,k)fluoranthene 4-Nitrophenol 

36 Benzo(k)fluoranthene 99 Pentachlorobiphenyl 

47 bis(2-Ethylhexyl)phthalate 377 Pentachlorophenol 

 Bromomethane (Methyl bromide) 384 Phenol 

 2-Butanone (MEK) Propanal (Propionaldehyde) 

80 Carbon tetrachloride Propionaldehyde 

91 Chlorine 429 Styrene 

95 Chlorobenzene 379 Perchloroethylene 

102 Chloroform 454 Toluene 

103 Chloromethane 462 1,1,1-Trichloroethane 

117 Crotonaldehyde 463 Trichloroethene 

137 Dibenzo(a,h)anthracene Trichlorofluoromethane (CFC−11) 

145 1,2-Dibromoethene 465 2,4,6-Trichlorophenol 

99 Total Polychlorinated biphenyls 485 Vinyl Chloride 

Organic 

192 Total 2,3,7,8 TCDD (Dioxins) 491 o-Xylene 

 296 Mercury 

 20 Ammonia 
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4.3 Natural Gas-Fired Boilers B02 and B03. 

4.3.1 New Source Performance Standards (NSPS). 

The natural gas-fired package boilers B02 and B03 do not provide steam for electric generation. 

Therefore, Boilers B02 and B03 will be subject to the New Source Performance Standards for industrial 

– commercial – institutional steam generating units in NR 440.205, Wis. Adm. Code and 40 CFR Part 

60, Subpart Db. This subpart applies to steam generating units that commence construction, 

modification, or reconstruction after June 19, 1984, and that have a heat input capacity greater than 100 

mmBtu/hr. 

4.3.1.1 Nitrogen Oxides (NOx): 0.20 lb/mmBtu. 

The NOx standards in Subpart Db are specified by the type of fuel combusted. In NR 440.205(5)(a), the 

NOx emission limit is 0.20 lb/mmBtu for a high heat release boiler firing natural gas. This boiler will 

have a maximum heat release rate of more than 70,000 Btu/hr-ft3

, a high heat release rate. Compliance 

with the NOx emission limit is to be determined on a 30-day rolling average basis and applies at all 

times, including startup, shutdown, and/or malfunction in accordance with 40 CFR 60.44b(i) and (h). 

Boilers with a heat input capacity of 250 mmBtu/hr or less with an annual capacity factor for natural gas 

greater than 10% can install a continuous monitoring system for NOx or can use operating conditions to 

predict emissions in accordance with 40 CFR 60.48b(g). 

4.3.1.2 Particulate Matter (PM): No Standard. 

The current Subpart Db rules for PM emissions were published in the Federal Register June 13, 2007. 

The only NSPS PM standard that is applicable to similar natural gas and distillate fuel oil-fired boilers is 

the opacity standard when fuel oil is fired under 40 CFR 60.43b(f) and NR 440.205(4)(f). This 

paragraph limits the opacity of emissions when distillate fuel oil is fired to no more than 20% (6-minute 

average). The exception is one 6-minute period per hour with opacity may not exceeding 27%. Because 

these are natural gas-fired boilers, this opacity standard does not apply. 

4.3.1.3 Sulfur Dioxide (SO2): No Standard. 

The SO2 standards in Subpart Db are only applicable when distillate fuel oil is fired. Because these 

boilers will fire only natural gas, there are no applicable NSPS SO2 standards. 

4.3.2 National Emission Standards for Hazardous Air Pollutants (NESHAP). 

Section 112 of the 1990 Clean Air Act Amendments requires the U.S. EPA to develop standards to 

control major sources of HAPs to levels consistent with the lowest emitting facilities in similar source 

categories. These National Emissions Standards for Hazardous Air Pollutants (NESHAPs) require the 

application of the maximum achievable control technology (MACT). The U.S. EPA promulgated 

NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters under 40 CFR Part 

63, Subpart DDDDD. However, this regulation has been vacated. 
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Section 112(g)(2) of the CAA requires a permitting authority to conduct a “case-by-case” MACT 

determination for new major sources where EPA has not established applicable standards. This Project 

meets the definition of “construct a major source” in 40 CFR. § 63.41(2). Based upon the definition of 

“construct a major source” within 40 CFR § 63.41 the natural gas-fired Boilers B02 and B03 are not 

subject to s. 112(g), since these boilers are not major source of HAPs. Never-the-less, We Energies has 

prepared a case-by-case MACT analysis for these boilers. 

4.3.3 Federal Acid Rain Program. 

The natural gas-fired Boilers B02 and B03 do not serve a generator that produces electricity for sale. 

Therefore, these boilers are not utility units, and these boilers are not subject to the Acid Rain Program. 

4.3.4 Control of Hazardous Pollutants under NR 445, Wis. Adm. Code. 

Under NR 445.07(5)(a), emissions from the combustion of group 1 virgin fossil fuels are exempt from 

the requirements of NR 445. Group 1 virgin fossil fuels include natural gas and diesel fuel. Therefore, 

the requirements of NR 445 do not apply to Boilers B02 and B03. 

4.4 Diesel Engine Driven Feedwater Pump, Process P151. 

The new diesel (compression ignition or CI) engine driven feed water pump will be an emergency diesel 

engine with 6 cylinders and a total displacement of 8.1 liters, or 1.35 liters per cylinder. This engine 

will be rated at 400 horsepower, and will be subject to the Standards of Performance for Stationary 

Compression Ignition Internal Combustion Engines, 40 CFR Part 60, Subpart IIII. There are two 

possible applicable standards for this new diesel engine in 40 CFR § 60.4205 depending on whether or 

not the engine is considered a fire pump: 

§ 60.4205 What emission standards must I 

meet for emergency engines if I am an 

owner or operator of a stationary CI internal 

combustion engine? 

 (b) Owners and operators of 2007 

model year and later emergency 

stationary CI ICE with a displacement of 

less than 30 liters per cylinder that are 

not fire pump engines must comply 

with the emission standards for new 

nonroad CI engines in § 60.4202, for all 

pollutants, for the same model year and 

maximum engine power for their 2007 

model year and later emergency 

stationary CI ICE. 

(c) Owners and operators of fire pump 

engines with a displacement of less than 

30 liters per cylinder must comply with 

the emission standards in table 4 to this 

subpart, for all pollutants. 
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The applicable standards for new nonroad CI engines in § 60.4202(a)(2) states that engines with a 

maximum engine power greater than or equal to 50 HP, the engine must meet the certification emission 

standards for new nonroad CI engines for the same model year and maximum engine power in 40 CFR 

89.112 and 40 CFR 89.113 for all pollutants beginning in model year 2007. The applicable emission 

standards in 40 CFR 89.112 for Tier 3 engines with Model 2006 and later include: 

NOx + NMHC.......................3.0 g/hp-hr 

CO .......................................2.61 g/hp-hr 

PM.......................................0.15 g/hp-hr 

The requirements in 40 CFR Part 60, Subpart IIII, Table 4 include the following for model year 2009 

and later stationary fire pump engines with maximum engine power between 300 and 600 horsepower: 

NOx + NMHC.......................3.0 g/hp-hr 

CO ......................................................n/a 

PM.......................................0.15 g/hp-hr 

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Chapter 5. Proposed BACT Limits. 

5.1 CFB Boiler B01. 

Based on the control technology review in Appendix A, We Energies is proposing to utilize an 

advanced circulating fluidized bed boiler designed to fire natural gas and biomass fuels, selective noncatalytic reduction, and a fabric filter baghouse. Table 5-1 summarizes the proposed control 

technologies and emission limits which represent the best available control technology (BACT) for this 

new biomass fuel fired boiler. 

TABLE 5-1. Proposed control technologies and emission limits representing BACT for the 

biomass-fired boiler B01. 

POLLUTANT PROPOSED CONTROL TECHNOLOGY 

PROPOSED 

LIMIT, 

lb/mmBtu 

POTENTIAL 

TO EMIT, 

tons/year 

Carbon Monoxide 

(CO) 

Advanced Circulating Fluidized Bed Boiler and 

Good Combustion Practices 0.20 701 

Nitrogen Oxides 

(NOx) 

Circulating Fluidized Bed Boiler and 

Selective Non-Catalytic Reduction 0.10 350 

PM < 10 microns 

(PM10) Fabric Filter Baghouse 0.03 105 

PM < 2.5 microns 

(PM2.5) 

Fabric Filter Baghouse with 

Felted Filter Media Bags 0.023 88 

Sulfur Dioxide 

(SO2) 

Circulating Fluidized Bed Boiler and Low Sulfur 

Fuels including Biomass Fuels and Natural Gas 0.09 315 

Organic 

Compounds (VOC) 

Circulating Fluidized Bed Boiler and 

Good Combustion Practices 0.017 60 

Fluorides 

(as HF) 

Circulating Fluidized Bed Boiler and Low 

Fluoride Fuels including Biomass Fuels and 

Natural Gas 

n/a 3.5 
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5.2 Natural Gas-Fired Boilers B02 and B03. 

The proposed boilers B02 and B03 will be natural gas-fired package boilers designed to provide up to 

125,000 pounds per hour of steam. To deliver this steaming capacity, each boiler will have a maximum 

design heat input capacity of 175 million Btu per hour. Based on the control technology review in 

Appendix B of this application, We Energies is proposing to equip each boiler with ultra-low NOx

burners and flue gas recirculation to control emissions of CO, NOx, PM/PM10, PM2.5, and VOCs. 

Table 5-2 summarizes the proposed control technologies and emission limits which represent the best 

available control technology (BACT) for these new package boilers. 

TABLE 5-2. Proposed control technologies and emission limits representing BACT for the 

natural gas-fired Boilers B02 and B03. 

Pollutant Proposed Control Technology and Emission Limits 

Carbon Monoxide 

(CO) 

(1) CO emissions shall be controlled using good combustion practices as BACT. 

(2) CO emissions may not exceed 0.09 lb/mmBtu when firing natural gas. 

Nitrogen Oxides 

(NOx) 

(1) NOx emissions shall be controlled using Ultra Low NOx Burners and Flue 

Gas Recirculation in combination with good combustion practices as 

BACT. 

(2) NOx emissions may not exceed 0.02 lb/mmBtu, averaged over any 30-day 

period. 

Particulate Matter 

(PM) and PM10

(1) PM and PM10 emissions shall be controlled using natural gas as fuel and 

good combustion practices as BACT. 

(2) PM and PM10 emissions may not exceed 0.0076 lb/mmBtu. 

PM2.5

(1) PM2.5 emissions shall be controlled using natural gas as fuel and good 

combustion practices as BACT.. 

(2) PM2.5 emissions may not exceed 0.0076 lb/mmBtu when firing natural gas. 

Sulfur Dioxide 

(SO2) 

(1) SO2 emissions shall be controlled using natural gas as fuel as BACT. 

(2) SO2 emissions may not exceed 0.0006 lb/mmBtu. 

Organic 

Compounds (VOC) 

(1) VOC emissions shall be controlled using good combustion practices as 

BACT. 

(2) VOC emissions may not exceed 0.006 pounds per million Btu of heat input. 

Fluorides (as HF) (1) Fluoride (as HF) emissions shall be controlled using natural gas as fuel as 

BACT. 
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5.3 Balance of Plant Equipment. 

This Project will require new biomass fuel handling equipment, biomass boiler ash handling equipment, 

a new cooling tower, and a new diesel engine driven feed water pump. The proposed control 

technologies and emission limits representing the best available control technology (BACT) for these 

processes and emission units are summarized in Table 5-3. 

TABLE 5-3. Proposed control technologies and emission limits representing BACT for We 

Energies’ 50 MW Biomass Fuels Cogeneration Facility balance of plant equipment. 

Process 

ID Description Proposed BACT Requirements 

P121 

Biomass Fuels Unloading, 

Screening, Hogging, and 

Conveying Dust Collector 

F122 Self Unloading Truck Biomass 

Fuels Unloading 

(1) PM emissions shall be controlled using buildings 

or enclosures combined with dust collection systems 

or wet dust suppression systems as BACT. 

(2) PM/PM10 emissions shall be limited to 0.004 

gr/dscf. 

(3) PM2.5 emissions shall be limited to 0.002 gr/dscf. 

F123 Biomass Fuels Storage and 

Reclaim 

(1) Particulate matter (PM), PM10, and PM2.5

emissions shall be controlled using a biomass fuels 

storage building designed to enclose the entire 

storage pile and the reclaim activities as BACT. 

P124 Boilerhouse Fuel Storage Silos 

P131 CFB Boiler Bed Material Silo 

P132 CFB Boiler Ash Silo 

(1) PM, PM10, and PM2.5 emissions shall be controlled 

using a bin vent filter as BACT. 

(2) PM/PM10 emissions shall be limited to 0.004 

gr/dscf. 

(3) PM2.5 emissions shall be limited to 0.002 gr/dscf. 

F125 Biomass Fuels Delivery Truck 

Haul Roads 

F133 Boiler Ash Haul Roads 

(1) PM, PM10, and PM2.5 emissions shall be controlled 

using paved roadways in combination with a wet dust 

suppression system as BACT. 

P141 Cooling Tower 

(1) PM, PM10, and PM2.5 emissions from the 

mechanical draft cooling tower, Process P144, shall be 

controlled using high efficiency drift eliminators as 

BACT. 

(2) The cooling tower drift eliminators shall be 

designed for a drift loss of no more than 0.0005%. 

P151 Emergency Diesel Engine Feed 

Water Pump 

(1) The diesel fire water pump shall comply with the 

applicable NSPS in 40 CFR § 60.4205 as BACT. 

(2) The diesel fuel may not exceed 0.0015% sulfur. 

(3) The diesel feed water pump may not be operated 

more than 100 hours in any 12-month period. 

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Chapter 6. Hazardous Air Pollutants 

and Case-by-Case MACT Analysis. 

6.1 Biomass-Fuel Fired Boiler B01. 

Federal hazardous air pollutant (HAPs) emitted from the biomass-fueled boiler may be classified in 

four categories: 1) Inorganic, solid phase HAPs, 2) Inorganic, acid gas HAPs including hydrogen 

chloride (HCl) and hydrogen fluoride (HF), 3) Organic HAPs, and 4) Mercury. The proposed emission 

standards representing the case-by-case MACT for these HAP categories are summarized in Table 6-1. 

The limits in Table 6-1 reflect the combustion of biomass fuels and natural gas in an advanced 

circulating fluidized bed boiler, in combination with a fabric filter baghouse. These control 

technologies are similar to those used on the best performing similar units reviewed in this analysis. 

TABLE 6-1. Proposed emission standards representing MACT for Boiler B01. 

HAP CATEGORY PROPOSED EMISSION LIMIT 

Inorganic, solid 

phase HAPs 

Inorganic, solid phase HAP emissions from the circulating fluidized bed 

boiler shall be controlled using a fabric filter baghouse as MACT. 

The proposed PM, PM10, and PM2.5 BACT emission limits represent MACT. 

Organic HAPs 

Organic HAP emissions from the biomass fuels-fired circulating fluidized bed 

boiler shall be controlled using good combustion practices as MACT. 

The proposed CO and VOC BACT emission limits represent MACT. 

Hydrogen Chloride 

(HCl) 

Hydrogen chloride (HCl) emissions from the circulating fluidized bed boiler 

shall be controlled using biomass fuels in combination with a fabric filter 

baghouse as MACT. 

Hydrogen chloride (HCl) emissions may not exceed 0.018 lb/mmBtu. 

Hydrogen Fluoride 

(HF) 

Hydrogen fluoride (HF) emissions from the circulating fluidized bed boiler 

shall be controlled using biomass fuels in combination with a fabric filter 

baghouse as MACT. 

Mercury 

Mercury emissions from the circulating fluidized bed boiler shall be 

controlled using biomass fuels in combination with a fabric filter baghouse as 

MACT. 

Mercury emissions may not exceed 2.9 pounds per trillion Btu. 
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TABLE 6-2. Potential hazardous air pollutant emissions for the biomass-fired boiler B01 (2 pages). 

Emission 

Factor 

Heat Input 

Capacity Potential to Emit HAP Category Hazardous Air Pollutant 

lb/mmBtu mmBtu/hr lb/hr tons/yr 

Antimony 7.9E-06 800 0.006 0.028 

Arsenic 2.2E-05 800 0.018 0.077 

Beryllium 1.1E-06 800 0.001 0.004 

Cadmium 4.1E-06 800 0.003 0.014 

Chromium, total 2.1E-05 800 0.017 0.074 

Chromium, hexavalent 3.5E-06 800 0.003 0.012 

Cobalt 6.5E-06 800 0.005 0.023 

Lead 4.8E-05 800 0.038 0.168 

Manganese 1.6E-03 800 1.280 5.606 

Nickel 3.3E-05 800 0.026 0.116 

Phosphorus 2.7E-05 800 0.022 0.095 

Inorganic, Solid Phase 

Selenium 2.8E-06 800 0.002 0.010 

Inorganic Hydrogen chloride 0.018 800 14.4 63.1 

Acid Gases Hydrogen fluoride 0.001 800 0.8 3.5 

Acetaldehyde 8.3E-04 800 0.664 2.908 

Acetophenone 3.2E-09 800 0.0000 0.000 

Acrolein 7.5E-05 800 0.0601 0.263 

Benzene 4.2E-03 800 3.360 14.717 

Benzo(a)anthracene 6.5E-08 800 0.000052 0.000 

Benzo(a)pyrene 2.6E-06 800 0.002080 0.009 

Benzo(b)fluoranthene 1.0E-07 800 0.000080 0.000 

Benzo(e)pyrene 2.6E-09 800 0.000002 0.000 

Benzo(g,h,i)perylene 9.3E-08 800 0.000074 0.000 

Benzo(j,k)fluoranthene 1.6E-07 800 0.000128 0.001 

Benzo(k)fluoranthene 3.6E-08 800 0.000029 0.000 

bis(2-Ethylhexyl)phthalate 4.7E-08 800 0.000038 0.000 

Bromomethane (Methyl bromide) 1.5E-05 800 0.012 0.053 

2-Butanone (MEK) 5.4E-06 800 0.004 0.019 

Carbon tetrachloride 4.5E-05 800 0.036 0.158 

Chlorine 7.9E-04 800 0.632 2.768 

Chlorobenzene 3.3E-05 800 0.026 0.116 

Chloroform 2.8E-05 800 0.022 0.098 

Chloromethane (Methyl chloride) 2.3E-05 800 0.018 0.081 

Dibenzo(a,h)anthracene 9.1E-09 800 0.000 0.000 

Organic 

1,2-Dibromoethene 5.5E-05 800 0.044 0.193 

Dichlorobiphenyl (PCB) 7.4E-10 800 

Heptachlorobiphenyl (PCB) 6.6E-11 800 
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TABLE 6-2. Potential hazardous air pollutant emissions for the biomass-fired boiler B01 (2 pages). 

Emission 

Factor 

Heat Input 

Capacity Potential to Emit HAP Category Hazardous Air Pollutant 

lb/mmBtu mmBtu/hr lb/hr tons/yr 

Hexachlorobiphenyl (PCB) 5.5E-10 800 

Monochlorobiphenyl (PCB) 2.2E-10 800 

Pentachlorobiphenyl (PCB) 1.2E-09 800 

Tetrachlorobiphenyl (PCB) 2.5E-09 800 

Trichlorobiphenyl (PCB) 2.6E-09 800 

Total Polychlorinated biphenyls (PCB) 7.9E-09 800 0.000006 0.000 

Total Equiv. 2,3,7,8 TCDD (Dioxins) 3.0e-9 800 0.000002 0.00001 

1,2−Dichloroethane (EDC) 2.9E-05 800 0.023 0.102 

Dichloromethane 2.9E-04 800 0.232 1.016 

1,2-Dichloropropane 3.3E-05 800 0.026 0.116 

2,4-Dinitrophenol 1.8E-07 800 0.000 0.001 

Ethyl benzene 3.1E-05 800 0.025 0.109 

Formaldehyde 4.4E-03 800 3.520 15.418 

Indeno(1,2,3,c,d)pyrene 8.7E-08 800 0.00006960 0.000 

2-Methylnaphthalene 1.6E-07 800 0.00012800 0.001 

Naphthalene 9.7E-05 800 0.078 0.340 

4-Nitrophenol 1.1E-07 800 0.0000880 0.000 

Pentachlorophenol (PCP) 5.1E-08 800 0.0000408 0.000 

Phenol 5.1E-05 800 0.041 0.179 

Propanal (Propionaldehyde) 3.2E-06 800 0.003 0.011 

Propionaldehyde 6.1E-05 800 0.049 0.214 

Styrene 1.9E-03 800 1.520 6.658 

Tetrachloroethene (Perchloroethylene) 3.8E-05 800 0.030 0.133 

Toluene 9.2E-04 800 0.736 3.224 

1,1,1-Trichloroethane 3.1E-05 800 0.025 0.109 

Trichloroethene 3.0E-05 800 0.024 0.105 

Trichlorofluoromethane (CFC−11) 4.1E-05 800 0.033 0.144 

2,4,6-Trichlorophenol 2.2E-08 800 0.000 0.000 

Vinyl Chloride 1.8E-05 800 0.014 0.063 

Organic 

o-Xylene 2.5E-05 800 0.020 0.088 

 Mercury 2.9E-06 800 0.002 0.010 

 TOTAL 122.2 

Footnotes 

1. The emission factors are for waste wood combustion in the U.S. EPA’s AP-42, Compilation of Air Pollutant 

Emission Factors, 5th Edition, Wood Residue Combustion, Tables 1.6-3 and 1.6-4. 
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6.2 Natural Gas-Fired Boilers B02 and B03. 

The proposed natural gas-fueled boilers are also a potential source of HAP emissions. However, 

because these are natural gas-fueled boilers, total potential HAP emissions for each boiler will be 1.04 

tons per year. As a result, these boilers will be minor sources of HAP emissions and the section 112(g) 

case-by-case MACT requirements are not applicable. See 61 Fed. Reg. 68384, 68388 (December 27, 

1996; sources that take enforceable limits resulting in emissions below the major source threshold do 

not meet the definition of “construct a major source” under section 112(g)). 

Although We Energies believes section 112(g) of the CAA is not applicable to these natural gas-fueled 

boilers, a case-by-case MACT evaluation was preformed in the event that section 112(g) is considered 

applicable. Table 6-3 is a summary of the proposed case-by-case MACT requirements for the control of 

HAP emissions from each natural gas-fueled boiler. These emission limits are based on the best 

performing similar units. 

TABLE 6-3. Proposed emission limits representing MACT for each natural gas-fueled boiler. 

HAP CATEGORY PROPOSED EMISSION LIMIT 

Inorganic, solid Proposed PM and PM10 BACT emission limits represent MACT. 

Organic Proposed CO and VOC BACT emission limits represent MACT. 

Inorganic, acid gas 

HCl emissions shall be controlled by firing only natural gas. 

HF emissions shall be controlled by firing only natural gas. 

Mercury Mercury emissions shall be controlled by firing only natural gas. 
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TABLE 6-4. Potential hazardous air pollutant (HAP) emissions for each natural gas-fired boiler. 

Emission Factor Heat 

Input Potential to Emit Pollutant CAS No. 

lb/106 scf lb/mmBtu mmBtu/hr lb/hr ton/yr 

2-Methylnaphthalene 91-57-6 2.40E-05 2.40E-08 175 0.000004 0.00001

3-Methylchloranthrene 56-49-5 1.80E-06 1.80E-09 175 0.000000 0.00000

7,12 Dimethylbenz(a)anthracene 1.60E-05 1.60E-08 175 0.000003 0.00001

Acenaphthene 83-32-9 1.80E-06 1.80E-09 175 0.000000 0.00000

Acenaphthylene 203-96-8 1.80E-06 1.80E-09 175 0.000000 0.00000

Anthracene 120-12-7 2.40E-06 2.40E-09 175 0.000000 0.00000

Benz(a)anthracene 56-55-3 1.80E-06 1.80E-09 175 0.000000 0.00000

Benzene 71-43-2 2.10E-03 2.10E-06 175 0.000368 0.00114

Benzo(a)pyrene 50-32-8 1.20E-06 1.20E-09 175 0.000000 0.00000

Benzo(b)fluoranthene 205-99-2 1.80E-06 1.80E-09 175 0.000000 0.00000

Benzo(g,h,i)perylene 191-24-2 1.20E-06 1.20E-09 175 0.000000 0.00000

Benzo(k)fluoranthene 205-82-3 1.80E-06 1.80E-09 175 0.000000 0.00000

Chrysene 218-01-9 1.80E-06 1.80E-09 175 0.000000 0.00000

Dibenzo(a,h)anthracene 53-70-3 1.20E-06 1.20E-09 175 0.000000 0.00000

Dichlorobenzene 25321-22-6 1.20E-03 1.20E-06 175 0.000210 0.00065

Fluoranthene 206-44-0 3.00E-06 3.00E-09 175 0.000001 0.00000

Fluorene 86-73-7 2.80E-06 2.80E-09 175 0.000000 0.00000

Formaldehyde 50-00-0 7.50E-02 7.50E-05 175 0.013125 0.04069

Hexane 110-54-3 1.80E+00 1.80E-03 175 0.315000 0.97650

Indeno(1,2,3-cd)pyrene 193-39-5 1.80E-06 1.80E-09 175 0.000000 0.00000

Naphthalene 91-20-3 6.10E-04 6.10E-07 175 0.000107 0.00033

Phenanathrene 85-01-8 1.70E-05 1.70E-08 175 0.000003 0.00001

Pyrene 129-00-0 5.00E-06 5.00E-09 175 0.000001 0.00000

Toluene 108-88-3 3.40E-03 3.40E-06 175 0.000595 0.00184

Hydrogen chloride 1.24E-05 175 0.002170 0.00673

Arsenic 7440-38-2 2.00E-04 2.00E-07 175 0.000035 0.00011

Barium 7440-39-3 4.40E-03 4.40E-06 175 0.000770 0.00239

Beryllium 7440-41-7 1.20E-05 1.20E-08 175 0.000002 0.00001

Cadmium 7440-43-9 1.10E-03 1.10E-06 175 0.000193 0.00060

Chromium 7440-47-3 1.40E-03 1.40E-06 175 0.000245 0.00076

Cobalt 7440-48-4 8.40E-05 8.40E-08 175 0.000015 0.00005

Copper 7440-50-8 8.50E-04 8.50E-07 175 0.000149 0.00046

Manganese 7439-96-5 3.80E-04 3.80E-07 175 0.000067 0.00021

Mercury 7439-97-6 2.60E-04 2.60E-07 175 0.000046 0.00014

Molybdenum 7439-98-7 1.10E-03 1.10E-06 175 0.000193 0.00060

Nickel 7440-02-0 2.10E-03 2.10E-06 175 0.000368 0.00114

Selenium 7782-49-2 2.40E-05 2.40E-08 175 0.000004 0.00001

Vanadium 7440-62-2 2.30E-03 2.30E-06 175 0.000403 0.00125

TOTAL, All HAPs 1.04 

Footnotes 

The emission factors are for waste wood combustion in the U.S. EPA’s AP-42, Compilation of Air Pollutant 

Emission Factors, 5th Edition, Natural Gas Combustion, Tables 1.4-3 and 1.4-4 

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Chapter 7. Dispersion Modeling 

Analysis. 

The purpose of a dispersion modeling analysis is to demonstrate, through the use of air quality 

dispersion models, that allowable emissions from the proposed source will not cause or contribute to 

violations of any National Ambient Air Quality Standard (NAAQS), or of any applicable Prevention of 

Significant Deterioration (PSD) increment. These applicable standards are summarized in Table 7-1. 

Detroit Edison conducted a detailed dispersion modeling analysis for this Project. The following is a 

summary of the analysis contained in Appendix E of this application. 

TABLE 7-1. National ambient air quality standard (NAAQS), modeling Significance Levels, and 

PSD Class II Increment, ug/m3

. 

Pollutant Averaging 

Period NAAQS Modeling Sig. Level 

PSD Class II 

Increment 

Nitrogen Oxides Annual 100 1 25 

(NO2) 1-hour 188 n/a n/a 

Carbon Monoxide 8-hour 10,000 500 n/a 

(CO) 1-hour 40,000 2000 n/a 

Particulate Matter Annual 50 1 17 

(PM10) 24-hour 150 5 30 

Particulate Matter Annual 15 0.3 n/a 

(PM2.5) 24-hour 35 1.2 n/a 

Total Suspended 

Particulates (TSP) 24-hr 150 n/a n/a 

Ozone** (O3) 8-hour 80 n/a n/a 

Annual 80 1 20 

24-hour 365 5 91 Sulfur Dioxide 

(SO2) 

3-hour 1,300 25 512 

3-month 0.15 n/a n/a 

Lead 

Quarterly 1.5 n/a n/a 

Footnotes 

The SILs listed for PM2.5 are the lowest of EPA’s currently proposed values. 

TSP is a State of Wisconsin standard. 
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7.1 Dispersion Model 

The latest version of EPA’s preferred regulatory model AERMOD (09292) was used in this dispersion 

modeling analysis, with five years of representative meteorological data from the Wausau Municipal 

Airport (processed by the DNR). The modeling procedures followed standardized EPA and DNR 

guidance. Note that the guidance for conducting PM2.5 and 1-hr NO2 impact analyses is currently 

evolving. 

7.2 Modeling Analysis Overview 

The air quality analysis was performed in two steps, a significant impact analysis, and when necessary a 

cumulative impact analysis. The significant impact analysis first estimates ambient impacts resulting 

from emissions from only the proposed Project, and for only those pollutants with Project emission 

increases above the PSD Significant Emission Rates. If the proposed Project's ambient impacts exceed 

the SILs for any pollutant and averaging interval, the requirement to perform a cumulative NAAQS and 

PSD Increment analysis is then triggered for that pollutant and averaging interval. The cumulative 

analysis is performed using the subset of receptors at which the project resulted in significant impacts. 

The cumulative impact analysis expands the significant impact analysis by considering emissions from 

both the proposed source and other existing or permitted sources, and also considers existing 

background air quality concentrations. 

7.3 Dispersion Modeling Results. 

7.3.1 Significant Impact Assessment. 

In this dispersion modeling analysis, a significant impact analysis was first performed to determine the 

increases in ambient air concentrations due only to the proposed Project sources for those pollutants 

with emissions that exceed the significant emission levels. When the maximum ambient concentrations 

of a pollutant are below the significant impact level (“SIL”) for all averaging periods, the emissions 

from the proposed source are not expected to have a significant impact on ambient air concentrations 

and further air quality analysis is not required. If the source's ambient impacts exceed the SIL for any 

pollutant and averaging interval, the extent of the geographical area in which the source exceeds the SIL 

is determined, and a cumulative impact analysis is performed for that pollutant and averaging interval. 

As a result of initial results, cumulative impact modeling was performed for NO2, SO2, PM10, and PM2.5. 

The results of the significant impact analysis are summarized in Table 7-2. From Table 7-2, the 

maximum impacts from the Project for carbon monoxide (CO), NO2, and the annual SO2 impacts are all 

below the significant impact levels. Therefore, emissions from the Project will have an insignificant 

impact on air quality for these pollutants and averaging intervals and meet the NAAQS requirements. 
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TABLE 7-2. Results of the significant impact analysis. 

Pollutant Averaging Period Significant Impact Level, 

μg/m3

Highest Modeled 

Concentration, μg/m3

8-hour 500 99 CO 

1-hour 2,000 209 

NO2 Annual 1 0.92 

Annual 1 0.98 

SO2 24-hour 5 12.6 

3-hour 25 55.6 

Annual 1 5.6 PM10 24-hour 5 20.4 

Annual 0.3 1.2 PM2.5 24-hour 1.2 6.4 

Footnotes 

The SILs listed for PM2.5 are the lowest of EPA’s currently proposed values. 

7.3.2 Cumulative NAAQS Assessment. 

For those pollutants/averaging periods for which the Project impacts are greater than the significance 

levels, cumulative modeling analyses were performed that considered emissions from both the Project 

sources and other nearby sources. The DNR provided the cumulative NAAQS and PSD source 

inventory for other facilities in the impact area, which included the nearby Domtar and Lignotech 

emission sources, as well as the main boiler sources at the Weston Power Plant. 

EPA has promulgated a 1-hr NO2 NAAQS, but has not yet provided 1-hr NO2 SILs to determine when a 

cumulative 1-hr NO2 NAAQS analysis is required. Therefore, even though the annual NO2 impacts 

from the Project are insignificant and do not trigger a cumulative annual NO2 NAAQS analysis, a 

cumulative 1-hr NO2 NAAQS analysis was performed. Because the annual NO2 impact was 

insignificant, it is reasonable to model only the Project emission sources for the 1-hr NO2 NAAQS 

analysis. However, the nearby Domtar and Lignotech sources were also included in the 1-hr NAAQS 

analysis, and the maximum 1-hr NO2 preliminary background concentration was also added to the 

modeled concentrations. Because EPA has not yet developed an AERMOD post-processor to calculate 

the modeled 1-hr NO2 concentrations in the exact same form as the 1-hr NO2 NAAQS, and based on 

discussions with DNR, a conservative method was used to compare modeled concentrations to the 1-hr 

NAAQS. The highest of the eighth-highest (H8H) modeled concentration from any individual year in 

the meteorological data period was added to the background concentration, and the total was compared 

to the 1-hr NO2 NAAQS. 

EPA’s guidance for determining compliance with the 24-hr PM2.5 NAAQS is currently evolving. The 

results in this analysis are based on the established method (programmed into the AERMOD model) of 

determining the highest of the eighth-highest (H8H) 24-hr concentrations for each year in the 

meteorological data period, and then averaging those across all years to calculate the maximum 98th
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percentile concentration. The PM2.5 NAAQS modeling analyses may need to be revised to address new 

EPA guidance when the air permit application is submitted. 

The results of the cumulative NAAQS analysis are summarized in Table 7-3. The NAAQS results 

demonstrate that the Project will not cause or contribute to air quality impacts that exceed the NAAQS. 

TABLE 7-3. Cumulative NAAQS modeling results. 

Pollutant Averaging 

Interval 

Cumulative 

Impact, 

μg/m3

Background, 

μg/m3

Total, 

μg/m3

NAAQS 

μg/m3 % of NAAQS

NO2 1-hour 61 11.9 73.2 188 39% 

24-hour 249 11.2 260.2 365 71% 

SO2

3-hour 951 11.8 962.8 1300 74% 

PM10 24-hour 41.8 29.4 71.2 150 47% 

Annual 2.3 8.7 11.0 15 73% 

PM2.5

24-hour 9.0 25.6 34.6 35 99% 

TSP 24-hour 103.6 39.7 143.3 150 96% 

Lead 3 month 0.00066 0.01 0.01066 0.15 7% 

7.3.3 Cumulative PSD Increment Analysis. 

If the proposed source's maximum modeled air pollutant concentrations exceed the significant impact 

level (SIL) for any pollutant and averaging interval, a cumulative PSD increment impact analysis is also 

performed for that pollutant and averaging interval. The results of the cumulative Class II PSD 

increment analysis are summarized in Table 7-4. The SO2 3-hr and 24-hr and the PM10 24-hr 

concentrations are the highest second-high concentrations. The PSD increment results demonstrate that 

the Project will not cause or contribute to air quality impacts that exceed the PSD increments. 

TABLE 7-4. Cumulative PSD Increment Modeling Results. 

Pollutant Averaging 

Interval 

Maximum 

Impact, ug/m3

PSD Increment 

ug/m3

% of PSD 

Increment 

Annual 5.7 17 34% 

PM10

24-hour 21.0 30 70% 

24-hour 86.1 91 95% 

SO2

3-hour 300 512 58% 
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Chapter 8. Additional Impacts 

Analysis. 

The Prevention of Significant Deterioration program requires an additional impact analysis pursuant to 

NR 405.13, Wis. Adm. Code, and the Code of Federal Regulations, 40 CFR 52.21(o). NR 405.13 states: 

NR 405.13 Additional impact analyses. (1) The 

owner or operator shall provide an analysis of the impairment to 

visibility, soils, and vegetation that would occur as a result of the 

major source or major modification and general commercial, 

residential, industrial and other growth associated with the major 

source or major modification. The owner or operator need not provide an analysis of the impact on vegetation having no significant 

commercial or recreational value. 

(2) The owner or operator shall provide an analysis of the air 

quality impact projected for the area as a result of general, commercial, residential, industrial and other growth associated with 

the major source or major modification 

The purpose of this analysis is to assess the potential impact the proposed project will have on visibility, 

soils, and vegetation, as well as the impact of general commercial, residential, and industrial growth 

associated with the proposed project. 

8.1 Analysis on Soils, Vegetation, and Visibility. 

The analysis of impacts on vegetation and soils is based on EPA guidance. The National Ambient Air 

Quality Standards (NAAQS) are designed to protect “health and welfare”, including “welfare” effects 

on water, vegetation, and soils, and are a useful benchmark for evaluating soil and vegetation impacts. 

In addition, model predicted concentrations were compared to other effects screening levels for sensitive 

species presented in EPA’s “A Screening Procedure for the Impacts of Air Pollution Sources on Plants, 

Soils, and Animals,” December 12, 1980, EPA 450/2-81-078, and “Air Quality Criteria for Oxides of 

Nitrogen, Summary of Vegetation Impacts” Volume II, August 1993, EPA 600/8-91/049bF. The 

maximum modeled annual NO2 concentrations from the project were less than 1 μg/m3

, which is far 

below the EPA direct effects screening concentration of 94 to 188 μg/m3

 for annual NO2 averages. The 

maximum modeled 1-hr NO2 concentrations were 73 μg/m3

, which is far below the EPA direct effects 

screening concentration of 3,760 μg/m3

 for 4-hr NO2 averages. The maximum modeled ambient SO2

concentrations from the project were 56 μg/m3

 for the 3-hr average and 0.98 μg/m3 for the annual 

average, which are far below the direct effects screening concentrations of 786 μg/m3

 for 3-hr and 18 

μg/m3

 for annual averages. Since the ambient impacts from the Project do not exceed the NAAQS nor 

EPA screening thresholds for sensitive vegetation and soils, the dispersion modeling analysis 

demonstrates that there are no harmful effects to vegetation and soils. 
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Near the proposed project site, under certain meteorological conditions, the combustion source stacks 

will emit a visible steam plume which, after traveling a relatively short distance, will dissipate by 

dispersion and evaporation. The applicant has also performed cooling tower visibility modeling 

analyses to estimate the potential for ground-level fogging and icing associated with visible vapor 

plumes, and ground-level fogging and icing impacts are expected to be visible for approximately 2 

hours per year. 

The existing four mill boilers and steam turbine plant will be retired once the new facility is operational. 

As a result of the biomass CFB boiler’s air quality technology and the retirement of Domtar’s existing 

boilers, the overall emissions from the mill site is expected to be reduced. Therefore, this Project will 

have a positive overall impact on soils, vegetation, and visibility. 

8.2 Associated Growth and Secondary Emissions. 

The emissions resulting from residential, commercial, and industrial growth associated with, but not 

directly a part of the project, must also be considered when conducting the air quality analysis. 

According to the U.S. Bureau of the Census, Census of Population and Housing, the population of 

Marathon County in 2008 was 131,000. Given this large local population, the construction associated 

with the Project and the subsequent operation of the Project will not have a significant impact to the 

local population. In addition, local municipal services will not be adversely impacted by this Project. 

There is currently sufficient fire protection and rescue services for the construction and operation of the 

Project. The Project will be located entirely within an existing industrial site, which currently hosts 

electric and steam generation facilities which are owned and operated by Domtar, as well as 

existing papermaking facilities. Therefore, the Project is not expected to have a measurable effect on 

the residential, commercial, or industrial growth of the area. 

8.3 Class I Air Quality Analysis Requirements. 

In the Clean Air Act Amendments of 1977, Congress specified the classification of lands for PSD 

purposes. Areas where existing air quality is considered to be of national importance were classified as 

Class I areas. These mandatory “Federal Class I areas” include all international parks, national 

memorial parks larger than 5,000 acres, and national parks larger than 6,000 acres that were in existence 

when the Amendments were passed. Congress also allowed States and Federally Recognized Indian 

tribes the option of redesignating Class II areas to Class I status to provide additional air quality 

protection. In Wisconsin, EPA has approved a request by the Forest County Potawatomi Community’s 

(FCP Community) Tribal Council to redesignate certain portions of the FCP Community Reservation 

near Crandon Wisconsin as a “non-Federal Class I area”. 

If a proposed major source or major modification may affect a Class I area, the PSD regulations require 

the reviewing authority to provide written notification of any such proposed source to the Federal Land 

Manager and the U.S. Department of Interior and U.S. Department of Agriculture officials delegated 

permit review responsibility. The meaning of the term "may affect" is interpreted by EPA policy to 

include all major sources or major modifications which propose to locate within 100 kilometers of a 

Class I area. 
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Wisconsin has two Class I PSD areas, the federal Rainbow Lake Area located in the Chequamagon 

National Forest (located approximately 200 km distant from the proposed facility), and the non-Federal 

Forest County Potawatomi area in Forest County (located approximately 99 km distant from the 

proposed facility). Generally, if a PSD project is located within 100 km of a Class I area, a Class I air 

quality impact analysis may be required. However, based on guidance developed by the Federal Land 

Managers of Class I areas, an “initial screening test” may be performed to determine if air quality and 

visibility impact analyses are required. This screening test uses the sum of the annual total emissions (in 

tons per year) of SO2, NOX, PM10, and H2SO4, divided by the distance to the Class I area (in km), to 

determine the “Q/D” ratio. If the ratio is less than 10, then the Federal Land Managers do not require 

Class I impact analyses. Based on the emissions of the proposed facility and the distances to the Class I 

areas, the ratio is calculated to be 8.3 for the FCP Class I area and 4.1 for the Rainbow Lakes area. 

Therefore, a Class I analysis for the Project is not required for either of the Wisconsin Class I areas. 
Prevention of Significant Deterioration 

Air Pollution Control Construction Permit Application 

Appendix A. 

Control Technology Review for the 

Biomass-Fired Boiler B01. 

50 MW Biomass Fuels-Fired Cogeneration Facility to be 

Located at the Domtar – Rothschild Mill.

March, 2010 

Prepared for: 

We Energies 

231 W. Michigan St. 

Milwaukee, WI 53203 

Prepared By: 

 

RTP ENVIRONMENTAL ASSOCIATES INC.® 

903 Superior Avenue, Suite 6 

Tomah, WI 54660 

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Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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Executive Summary 

This document is a Control Technology Review for the proposed new biomass fuels-fired boiler at We 

Energies’ 50 MW Biomass Fuels Cogeneration Facility to be located at the Domtar – Rothschild Mill. 

This control technology review is required for major new sources under the Prevention of Significant 

Deterioration (PSD) program under NR 405.08, Wis. Adm. Code. The proposed boiler will be a 

circulating fluidized bed (CFB) boiler with a maximum design heat input capacity of 800 million Btu per 

hour. The primary boiler fuels will be wood, bark, wood waste, forest residues, and wastewater treatment 

plant sludge from the Domtar Paper Mill. The boiler will also be designed to fire natural gas for a startup 

fuel and for load stabilization and supplemental firing, with a maximum natural gas firing rate of less than 

250 mmBtu per hour. 

Based on this control technology review, We Energies is proposing to utilize an advanced circulating 

fluidized bed boiler designed to fire natural gas and biomass fuels, selective non-catalytic reduction, and a 

fabric filter baghouse. The following table summarizes the proposed control technologies and emission 

limits which represent the best available control technology (BACT) for this new biomass fuels-fired 

boiler. 

Proposed control technologies and emission limits representing BACT for the biomass-fired boiler. 

POLLUTANT PROPOSED CONTROL TECHNOLOGY 

PROPOSED 

LIMIT, 

lb/mmBtu 

POTENTIAL 

TO EMIT, 

ton/year 

Carbon Monoxide 

(CO) 

Advanced Circulating Fluidized Bed Boiler and 

Good Combustion Practices 0.20 701 

Nitrogen Oxides 

(NOx) 

Circulating Fluidized Bed Boiler and 

Selective Non-Catalytic Reduction 0.10 350 

Particulate Matter 

(PM/PM10) Fabric Filter Baghouse 0.03 105 

PM < 2.5 microns 

(PM2.5) 

Fabric Filter Baghouse with 

Felted Filter Media Bags 0.023 81 

Sulfur Dioxide 

(SO2) 

Circulating Fluidized Bed Boiler and Low Sulfur 

Fuels including Biomass Fuels and Natural Gas 0.09 315 

Organic 

Compounds (VOC) 

Circulating Fluidized Bed Boiler and 

Good Combustion Practices 0.017 60 

Fluorides 

(as HF) 

Circulating Fluidized Bed Boiler and Low Fluoride 

Fuels including Biomass Fuels and Natural Gas n/a 3.5 

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Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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Table of Contents 

Chapter 1. Introduction and Source Description................................................8

1.1 Fluidized Bed Boiler Technology.................................................................................................... 9

1.2 CFB Boiler Fuels. ............................................................................................................................ 9

1.3 CFB Boiler Design......................................................................................................................... 10

1.4 Potential Air Emissions.................................................................................................................. 10

Chapter 2. Control Technology Review Methodology......................................12

2.1 Best Available Control Technology Definition. ............................................................................ 12

2.2 Top Down BACT Methodology. ................................................................................................... 13

2.3 New Versus Modified Facilities. ................................................................................................... 13

2.4 Technical Feasibility...................................................................................................................... 14

2.5 Economic Feasibility. .................................................................................................................... 15

2.5.1 Average Cost Effectiveness. ............................................................................................. 15

2.5.2 Incremental Cost Effectiveness......................................................................................... 16

2.5.3 Agency Decisions on Cost Effectiveness. ........................................................................ 16

Chapter 3. Carbon Monoxide (CO) Control Technology Review. ..................21

3.1 BACT Baseline. ............................................................................................................................. 21

3.2 STEP 1. Identify All Available Control Technologies. ................................................................ 21

3.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 21

3.3.1 Oxidation Catalysts........................................................................................................... 22

3.3.2 Thermal Oxidation............................................................................................................ 23

3.3.3 Good Combustion Practices.............................................................................................. 23

3.4 STEP 3. Rank the Technically Feasible Control Technologies. ................................................... 25

3.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 25

3.6 STEP 5. Proposed Carbon Monoxide BACT Determination........................................................ 25

Chapter 4. Nitrogen Oxides (NOx) Control Technology Review. ....................26

4.1 BACT Baseline. ............................................................................................................................. 26

4.2 STEP 1. Identify All Potential Control Strategies. ....................................................................... 26

4.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 28

4.3.1 Fluidized Bed Boilers. ...................................................................................................... 28

4.3.2 Low NOX Burners and Overfire Air. ................................................................................ 28

4.3.3 Overfire Air (Staged Combustion).................................................................................... 29

4.3.4 Flue Gas Recirculation...................................................................................................... 29

4.3.5 Oxygen-Enhanced Combustion. ....................................................................................... 29
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4.3.6 Natural Gas or Coal Reburning......................................................................................... 30

4.3.7 Selective Catalytic Reduction........................................................................................... 30

4.3.8 High Dust SCR. ................................................................................................................ 31

4.3.9 Tail Gas SCR. ................................................................................................................... 33

4.3.10 Selective Non-Catalytic Reduction................................................................................... 34

4.3.11 Catalytic Absorption/Oxidation (SCONOxTM)................................................................. 35

4.3.12 Emerging Control Technologies....................................................................................... 35

4.3.13 Summary of the Technically Feasible Controls................................................................ 36

4.4 STEP 3. Rank the Technically Feasible Control Technologies. ................................................... 37

4.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 38

4.5.1 Rank No. 1: Selective Catalytic Reduction...................................................................... 38

4.5.2 Rank No. 2: Selective Non-Catalytic Reduction. ............................................................ 41

4.6 STEP 5. Proposed Nitrogen Oxide BACT Determination............................................................ 42

Chapter 5. Particulate Matter and PM10 Control Technology Review...........43

5.1 Reference Method 202 and Artifact Formation. ............................................................................ 43

5.2 Other Test Method 28. ................................................................................................................... 45

5.3 Particulate Matter and PM10........................................................................................................... 45

5.4 Basis for Evaluating PM Limits..................................................................................................... 46

5.5 BACT Baseline. ............................................................................................................................. 46

5.6 STEP 1. Identify Potential Control Technologies......................................................................... 46

5.7 STEP 2. Identify Technically Feasible Control Technologies...................................................... 48

5.7.1 Fabric Filter Baghouses. ................................................................................................... 48

5.7.2 Dry Electrostatic Precipitators. ......................................................................................... 49

5.7.3 Wet Electrostatic Precipitators.......................................................................................... 50

5.7.4 Wet Scrubbers................................................................................................................... 50

5.7.5 Mechanical Collectors. ..................................................................................................... 50

5.8 STEP 3. Rank the Technically Feasible Technologies. ................................................................. 51

5.9 STEP 4. Evaluate the Most Effective Controls............................................................................. 51

5.9.1 Rank No. 1: Fabric Filter Baghouse. ............................................................................... 51

5.10 STEP 5. Proposed Filterable Particulate Matter and PM10 BACT Determination........................ 52

Chapter 6. PM2.5 Control Technology Review...................................................53

6.1 BACT Baseline. ............................................................................................................................. 53

6.2 STEP 1. Identify All Potential Control Technologies................................................................... 54

6.2.1 Direct PM2.5 Emissions. .................................................................................................... 54

6.2.2 PM2.5 Precursors................................................................................................................ 54

6.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 54

6.3.1 Fabric Filter Baghouses. ................................................................................................... 54
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6.3.2 Dry Electrostatic Precipitators. ......................................................................................... 58

6.3.3 Wet Electrostatic Precipitators.......................................................................................... 58

6.3.4 Wet Scrubbers................................................................................................................... 58

6.3.5 Mechanical Collectors. ..................................................................................................... 58

6.4 STEP 3. Rank the Technically Feasible Technologies. ................................................................. 59

6.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 60

6.5.1 Rank No. 1: Fabric Filter Baghouse with Advanced Filter Media. ................................. 60

6.6 STEP 5. Proposed PM2.5 BACT Determination............................................................................ 60

Chapter 7. Sulfur Dioxide (SO2) Control Technology Review.........................61

7.1 BACT Baseline. ............................................................................................................................. 61

7.2 STEP 1. Identify Potential Control Technologies......................................................................... 61

7.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 63

7.3.1 Wet Flue Gas Desulfurization........................................................................................... 63

7.3.2 Dry Flue Gas Desulfurization. .......................................................................................... 66

7.3.3 Sorbent Injection............................................................................................................... 67

7.3.4 Emerging Flue Gas Desulfurization Technologies. .......................................................... 68

7.3.5 Low Sulfur Fuels and Fuel Cleaning. ............................................................................... 69

7.4 STEP 3. Rank the Technically Feasible Technologies. ................................................................. 71

7.4.1 Low Sulfur Biomass Biomass Fuels. ................................................................................ 71

7.4.2 Wet Flue Gas Desulfurization........................................................................................... 72

7.4.3 Dry Flue Gas Desulfurization. .......................................................................................... 72

7.4.4 Dry Sorbent Injection........................................................................................................ 72

7.4.5 Ranking of the Technically Feasible Control Options...................................................... 72

7.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 73

7.5.1 Rank No. 1: Wet Flue Gas Desulfurization. .................................................................... 73

7.5.2 Rank No. 2: Dry Flue Gas Desulfurization...................................................................... 75

7.5.3 Rank No. 3: Sorbent Injection. ........................................................................................ 76

7.5.4 Rank No. 4: Low Sulfur Biomass Fuels. ......................................................................... 76

7.6 STEP 5. Proposed Sulfur Dioxide BACT Determination............................................................. 77

Chapter 8. Organic Compound (VOC) Control Technology Review. ............78

8.1 BACT Baseline. ............................................................................................................................. 78

8.2 STEP 1. Identify All Available Control Technologies. ................................................................ 78

8.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 79

8.3.1 Oxidation Catalysts........................................................................................................... 79

8.3.2 Thermal Oxidation............................................................................................................ 79

8.3.3 Good Combustion Practices.............................................................................................. 81

8.4 STEP 3. Rank the Technically Feasible Control Technologies. ................................................... 81
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8.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 81

8.6 STEP 5. Proposed VOC BACT Determination. ........................................................................... 82

Chapter 9. Fluorides (as HF) Control Technology Review. .............................83

9.1 BACT Baseline. ............................................................................................................................. 83

9.2 STEP 1. Identify All Potential Control Technologies................................................................... 83

9.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 85

9.3.1 Flue Gas Desulfurization Systems. ................................................................................... 85

9.3.2 Sorbent Injection............................................................................................................... 85

9.4 STEP 3. Rank The Technically Feasible Control Technologies................................................... 85

9.4.1 Biomass Biomass Fuels. ................................................................................................... 85

9.4.2 Flue Gas Desulfurization. ................................................................................................. 87

9.4.3 Sorbent Injection............................................................................................................... 87

9.4.4 Ranking of the Technically Feasible Control Options...................................................... 87

9.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 88

9.6 STEP 5. Proposed Fluorides BACT Determination...................................................................... 90

Tables 

TABLE 1-1. Potential air pollutant emissions for the proposed biomass-fired boiler...............................11

TABLE 2-1. Summary of recent BACT economic analyses in which the control technology was rejected 

as not cost effective for BACT. ..........................................................................................................17

TABLE 3-1. Carbon monoxide (CO) BACT emission limits for similar biomass fuel-fired boilers.........24

TABLE 4-1. Biomass-fired boiler nitrogen oxides (NOx) emission limits representing BACT.................27

TABLE 4-2. Summary of the technical feasibility of retrofit NOx control technologies. ..........................36

TABLE 4-3. Ranking of the technically feasible NOx control technologies for the biomass boiler. ........37

TABLE 4-4. Cost effectiveness of the NOx control technology options for the biomass-fired boiler.......40

TABLE 5-1. Biomass-fired boiler particulate matter/PM10 BACT emission limits. ..................................47

TABLE 5-2. Ranking of the technically feasible PM control technologies for the biomass-fired boiler..51

TABLE 6-1. Ranking of the technically feasible PM2.5 control technologies. ..........................................59

TABLE 7-1. Biomass-fired boiler sulfur dioxide (SO2) BACT emission limits. .......................................62

TABLE 7-2. Typical proximate and ultimate analyses for several biomass fuels.....................................69

TABLE 7-3. Wood fuels analyses data and uncontrolled SO2 emission rates...........................................70

TABLE 7-4. Ranking of the technically feasible SO2 control technologies..............................................72

TABLE 7-5. Cost effectiveness of the SO2 control technology options for the biomass-fired boiler. ......74

TABLE 8-1. Biomass-fired boiler VOC emission limits representing BACT. ..........................................79
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TABLE 9-1. Biomass-fired boiler hydrogen fluoride (HF) emission test results.......................................84

TABLE 9-2. Ranking of the technically feasible HF control technologies. ..............................................87

Figures 

FIGURE 1-1. Typical CFB boiler power block showing the furnace, cyclone, baghouse, and stack. ........8

FIGURE 4-1. High dust SCR catalyst plugging, fouling, and structural support failure...........................31

FIGURE 3-2. Coal and biomass ash composition showing the high levels of potassium and sodium in 

biomass ash relative to coal ash..........................................................................................................32

FIGURE 4-1. Reference Method 5 and Method 202 sample train.............................................................44

FIGURE 4-2. Reference Method 5 and Other Method 28 sample train. ...................................................45

FIGURE 5-2. Depiction of the flue gas flow through the fabric filter baghouse filter cake showing the 

mechanism for particulate collection. .................................................................................................48

FIGURE 6-1. Cumulative emission factor for PM emissions versus the particle size. .............................55

FIGURE 7-1. Typical modern wet flue gas desulfurization system absorber tower. ................................64

Attachments

Attachment 1. Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) 

system. 

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s CUECost Air Pollution 

Control Systems Economics Spreadsheets, and cost estimates for sorbent injection. 

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50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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Chapter 1. Introduction and Source 

Description. 

This document is a Control Technology Review for the proposed new biomass fuels-fired boiler at We 

Energies’ 50 MW Biomass Fuels Cogeneration Facility to be located at the Domtar – Rothschild Mill. 

This control technology review is required for major new sources under the Prevention of Significant 

Deterioration (PSD) program under NR 405.08, Wis. Adm. Code. 

The proposed boiler will be a circulating fluidized bed (CFB) boiler designed to provide up to 550,000 

pounds per hour of steam at 1,550 psig and 950 o

F. The boiler will have a maximum design heat input 

capacity of 800 million Btu per hour. The primary boiler fuels will be woody biomass consisting of 

logging residues, and wastewater treatment plant wood residue from the Domtar Paper Mill. The boiler 

will also be designed to fire natural gas for a startup fuel and for combustion stabilization, with a 

maximum natural gas firing rate of less than 250 mmBtu per hour. A typical CFB boiler power block 

showing the boiler, the CFB cyclone, the fabric filter baghouse, and the stack is shown in Figure 1-1. 

FIGURE 1-1. Typical CFB boiler power block showing the furnace, cyclone, baghouse, and stack. 
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Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

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1.1 Fluidized Bed Boiler Technology. 

The atmospheric pressure, fluidized bed boiler technology was developed to minimize SO2 and NOx

emissions from the combustion of high sulfur fuels such as coal and petroleum coke. The fluidized bed 

boiler combustion process minimizes NOx formation and removes SO2 in the boiler before post 

combustion air pollution control systems. Fluidized bed boilers are also excellent boilers for firing highly 

variable and low heat value fuels such as biomass. 

There are two major fluidized bed boiler types: the bubbling fluidized bed (BFB), and the circulating 

fluidized bed (CFB) boiler. In the BFB boiler, the bed of materials including the limestone, fuel, and ash 

is suspended by the combustion air flowing upward through an air distribution plate at velocities of 1 to 5 

ft/sec. In a BFB boiler, the fluidized bed is typically about 4 feet deep, and is characterized by a sharp 

density profile at the top of the bed. The sharp drop off in density indicates the end of the fluidized bed. 

In a BFB boiler, the bed level is easy to see, and there is a distinct transition between the bed and the 

space above. Solid material is drained from the bed to maintain the desired bed depth. Some solid 

material is also entrained in the flue gas and is carried out of the furnace with the flue gas. 

The CFB boiler is a more advanced fluidized bed boiler technology. CFB boilers have higher fluidizing 

air velocities ranging from 10 to 20 ft/sec, lack a distinct transition from the dense bed at the bottom of 

the furnace to the dilute zone above, and have a very high flow rate of re-circulated solids. The high 

fluidizing air velocity results in a turbulent fluidized bed and a high rate of entrained solids carried out of 

the boiler. These solids are separated from the combustion gases by cyclones located at the outlet of the 

boiler furnace and are returned to the furnace to maintain the bed in the furnace and to improve 

combustion efficiency. 

When firing high sulfur containing fuels, limestone is injected with solid fuel to create a fuel and 

limestone “bed”. For low sulfur fuels such as biomass fuels, sand is used rather than limestone to avoid 

excessive calcium in the bed which can lead to particle agglomeration, excessive particle size, and even 

“freeze-up” of the fluidized bed. The limestone or sand particles create an abrasive bed of particles which 

assists in eroding fuel particles and completing the combustion process. Combustion air introduced at the 

bottom of the furnace keeps the mixture of fuel, limestone, sand, char, and ash “fluidized” in a constantly 

upward flowing stream. Although the fuel and limestone/sand are solids, the combination of fuel, 

limestone/sand, ash, and combustion air exhibit fluid-like properties. The highly turbulent, erosive 

conditions of the CFB achieves very high combustion efficiencies even though combustion takes place at 

relatively low temperatures of 1,500 to 1,650°F. 

1.2 CFB Boiler Fuels. 

The primary fuel for the CFB boiler will be woody biomass fuels. The primary target source and anchor 

fuel for this project will be woody biomass. For purposes of this application, “biomass” means a resource 

that derives energy from wood or plant material or residue, clean solid wood waste and crops grown for 

use as a resource. It excludes edible portions of food crops, refuse derived fuel, treated wood, municipal 

solid waste, sewerage sludge, and animal waste. Fuel sources may include but are not limited to: 
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 logging residue 

 discarded woody material from primary manufacturing facilities such 

as paper mills, sawmills, or chip mills 

 on-site wastewater treatment plant residue 

 leftover woody material from secondary manufacturers such as door, 

window, cabinet manufacturers 

 woody biomass from municipality wood waste, tree services, and 

construction companies 

 clean solid wood waste from discarded wood packaging such as 

pallets/crating and from construction and demolition activities 

 woody biomass plantations, energy crops and agricultural residues 

The design fuel – forest residues - will have a heat value of 8,430 Btu per pound on a bone-dry basis, or 

approximately 4,530 Btu per pound on an as-received basis. The biomass fuel consumption rate will be 

46 tons per hour (dry basis), or 86 tons per hour on an as-received basis when burning the design fuel. 

The boiler will also be equipped with natural gas start-up burners. Natural gas may also be used as a 

support fuel using secondary lance burners during upset conditions or for short periods when the biomass 

moisture is higher than normal.

1.3 CFB Boiler Design. 

The Company is proposing to construct a steam/electric cogeneration facility, to be located on the Domtar 

property. The facility will be designed to produce 50 MW net electric generation, as well as provide the 

full process steam requirements of the Domtar paper mill. In normal operating mode, process steam for 

the mill will be extracted from the turbine generator, slightly reducing net generation capability. The CFB 

boiler will be equipped with a single steam drum and multiple economizer, generating bank, superheater 

and steam attemperator systems. High pressure, high temperature steam will be fed to a new 50 MW 

(electric) steam turbine electric generator set. The boiler will be equipped with air heaters to preheat the 

combustion air using hot flue gases and/or steam to improve thermal efficiency and to compensate for 

high moisture biomass. Steam soot blowers will be located at strategic positions to maintain heating 

surfaces clean. There will be a single electrically driven induced draft fan downstream of the baghouse. 

The CFB boiler will have a recirculating sand system to replace the sand purged from the fluidized bed 

with the ash. The sand system will consist of a sand silo which will feed sand by gravity to the sand chute 

that ends in the furnace. The ash will bind itself to the sand in the bed. As a result, the mixture will be 

collected in a cyclone for the sand to be screened and recirculated back to the boiler combustion zone. 

The heavier particles will be discharged onto a conveyor system which will transfer the ash to the ash 

silo. The sand consumption will be dependent on the fuel and sand quality. 

1.4 Potential Air Emissions. 

Potential emissions for this biomass fuels-fired, circulating fluidized bed boiler are summarized in Table 

1-1. 
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TABLE 1-1. Potential air pollutant emissions for the proposed biomass-fired boiler. 

Uncontrolled 

Emission 

Factor 

Heat Input 

Capacity 

Maximum Theoretical 

Emissions 

Control 

Efficiency 

Controlled 

Emission 

Factor 

Pollutant 

lb/mmBtu mmBtu/hr lb/hr tons/yr % lb/mmBtu 

Carbon Monoxide CO 0.20 800 160 701 0.20 Nitrogen Oxides NOx 0.15 800 120 526 33.3% 0.10 Particulate Matter PM/PM10 12.0 800 9,600 42,048 99.75% 0.030 Particulate Matter PM2.5 12.0 800 9,600 42,048 99.81% 0.023 Sulfur Dioxide SO2 0.09 800 72 315 0.0% 0.09 Organic Compounds OC 0.017 800 13.6 60 0.017 Lead Pb 0.00003 800 0.02 0.11 0.00003 Mercury Hg 0.0000029 800 0.0023 0.010 0.0000029 Fluorides (as HF) HF 0.001 800 0.8 3.5 0.001 Sulfuric Acid Mist H2SO4 0.0018 800 1.4 6.3 0.0018 

Footnotes 

1. Potential controlled emission rates for CO, NOx, PM/PM10, PM2.5, SO2, VOC, and fluorides are based on the proposed 

BACT emission limits in this control technology review. 2. The lead emission factor is from the U.S. EPA document, Compilation of Air Pollutant Emission Factors, AP-42, 5th Edition, Wood Residue Combustion in Boilers, Table 1.6-4. 3. The mercury emission factor is based on the proposed case-by-case MACT emission limit for mercury contained in Appendix D of the application. 4. Sulfuric acid mist emissions are estimated to be 2% of the sulfur dioxide emissions on a mass basis. 
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Chapter 2. Control Technology Review 

Methodology. 

2.1 Best Available Control Technology Definition. 

The Clean Air Act and the Prevention of Significant Deterioration (PSD) rules in the Code of Federal 

regulations, 40 CFR 52.21(b)(12) define “best available control technology” (BACT) as: 

 “...an emission limitation based on the maximum degree of reduction for each pollutant subject to 

regulation under this Act which would be emitted from any proposed major stationary source or major 

modification which the administrator on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, determines is achievable for such source or 

modification through application of production processes and available methods, systems, and 

techniques, including fuel cleaning or treatment of innovative fuel combustion techniques for control of 

each such pollutant. In no event shall application of BACT result in emissions of any pollutant which 

would exceed the emissions allowed by any applicable standard under 40 CFR Parts 60 and 61.” 

In Wisconsin, BACT is defined as: 

...means an emissions limitation, including a visible emissions standard, based on the maximum degree 

of reduction for each air contaminant subject to regulation under the Act which would be emitted from 

any proposed major stationary source or major modification which the department, on a case-by-case 

basis, taking into account energy, environmental, and economic impacts, and other costs, determines is 

achievable for such source or modification through application of production processes or available 

methods, systems, and techniques, including clean fuels, fuel cleaning or treatment or innovative fuel 

combination techniques for control of the air contaminant. In no event may application of best available 

control technology result in emissions of any air contaminant which would exceed the emissions 

allowed by any applicable standard under chs. NR 440 and 445 to 449 and under sections 111 and 112 

of the Act (42 USC 7411 and 7412). Emissions from any source utilizing clean fuels or any other means 

to comply with this subsection may not be allowed to increase above the levels that would have been 

required under this subsection as it existed prior to enactment of the 1990 clean air Act amendments on 

November 15, 1990. If the department determines that technological or economic limitations on the 

application of measurement methodology to a particular emissions unit would make the imposition of 

an emissions standard infeasible, a design, equipment, work practice, operational standard or 

combination thereof, may be prescribed instead to satisfy the requirement for the application of best 

available control technology. The standard shall, to the degree possible, set forth the emissions 

reduction achievable by implementation of such design, equipment, work practice or operation, and 

shall provide for compliance by means which achieve equivalent results. 

(NR 405.02(7), Wis. Adm. Code)

The BACT requirement applies for a given pollutant to each individual new or modified emission unit 

when the project, on a facility-wide basis, has a significant net emissions increase for that pollutant. 

Individual BACT determinations are performed on a unit-by-unit, pollutant-by-pollutant basis. 
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2.2 Top Down BACT Methodology. 

The U.S. EPA recommends a “top-down” approach in conducting a BACT analysis. This method 

evaluates progressively less stringent control technologies until a level of control considered BACT is 

reached, based on the environmental, energy, and economic impacts. The top-down method was used in 

this analysis. The five steps of a top-down BACT analysis are: 

1. Identify all available control technologies with practical potential for application to the emission 

unit and regulated pollutant under evaluation; 

2. Eliminate all technically infeasible control technologies; 

3. Rank remaining control technologies by effectiveness and tabulate a control hierarchy; 

4. Evaluate most effective controls and document results; and 

5. Select BACT, which will be the most effective practical option not rejected, based on economic, 

environmental, and/or energy impacts. 

The impact analysis of any BACT review includes an evaluation of environmental, energy, technical, and 

economic impacts. The net environmental impact associated with a control alternative may be considered 

if dispersion modeling analyses are performed. The energy impact analysis estimates the direct energy 

impacts of the control alternatives in units of energy consumption. If possible, the energy requirements 

for each control option are assessed in terms of total annual energy consumption. The most important 

issue of the BACT review is generally the economic impact. The economic impact of a control option is 

assessed in terms of cost effectiveness and ultimately, whether the option is economically reasonable. The 

economic impacts are reviewed on a cost per ton controlled basis, as directed by the U.S. EPA’s Office of 

Air Quality Planning and Standards (OAQPS) Cost Control Manual, Fifth Edition. 

The EPA has consistently interpreted the statutory and regulatory BACT definitions as containing two 

core requirements, which EPA believes must be met by any BACT determination, irrespective of whether 

it is conducted in a “top-down” manner. First, the BACT analysis must include consideration of the most 

stringent available technologies: i.e., those that provide the “maximum degree of emissions reduction.” 

Second, any decision to require a lesser degree of emissions reduction must be justified by an objective 

analysis of “energy, environmental, and economic impacts” contained in the record. 

2.3 New Versus Modified Facilities. 

There can be significant differences in the technical and economic feasibility of retrofitting controls on 

existing boilers, versus the use of these same controls on new boilers. In addition, a given control 

technology may not be able to achieve the same level of control when retrofitted onto existing units as the 

same control technology can achieve on new units. For example, the use of low NOx burners on existing 

boilers often cannot achieve the same NOx, CO, and VOC emission rates as the use of low NOx burners 

on a new boiler which has been designed to optimize the low NOx burner design. This can in turn affect 

the ultimate NOx emission rates which can be achieved by post combustion controls such as selective 

catalytic reduction. 
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Retrofitting controls on existing boilers can also have significantly different costs as compared to the use 

of these same technologies on new units. Retrofitting controls on existing boilers can have numerous 

issues, including site constraints and room for the new controls, demolition requirements for existing 

controls, and down time during construction and interconnection of the new systems. 

2.4 Identifying Potential Control Technologies. 

As stated in the U.S. EPA’s October 1990 New Source Review Workshop Manual, the first step in a "topdown" analysis is to identify, for the emissions unit in question, all "available" control options. Available 

control options are those air pollution control technologies or techniques with a practical potential for 

application to the emissions unit and the regulated pollutant being evaluated. Air pollution control 

technologies and techniques include the application of production process or available methods, systems, 

and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control 

of the affected pollutant, including technologies employed outside of the United States. In some 

circumstances, inherently lower-polluting processes are appropriate for consideration as available control 

alternatives. The control alternatives should include not only existing controls for the source category in 

question, but also (through technology transfer) controls applied to similar source categories and gas 

streams, and innovative control technologies. Technologies required under lowest achievable emission 

rate (LAER) determinations are available for BACT purposes and must also be included as control 

alternatives and usually represent the top alternative. In Step 1, applicants should identify all control 

options with potential application to the emissions unit under review. 

2.5 Technical Feasibility. 

Step 2 of the BACT analysis involves the evaluation of all of the identified available control technologies 

from Step 1 to determine their technical feasibility. A control technology is technically feasible if it has 

been previously installed and operated successfully at a similar emission source, or there is technical 

agreement that the technology can be applied to the emission source. Technical infeasibility is 

demonstrated through clear physical, chemical, or other engineering principles that demonstrate that 

technical difficulties preclude the successful use of the control option. 

The technology must be commercially available for it to be considered as a candidate for BACT. EPA’s 

New Source Review Workshop Manual, page B.12 states, “Technologies which have not yet been applied 

to (or permitted for) full scale operations need not be considered available; an applicant should be able to 

purchase or construct a process or control device that has already been demonstrated in practice.” In 

general, if a control technology has been "demonstrated" successfully for the type of emission source 

under review, then it would normally be considered technically feasible. For an undemonstrated 

technology, “availability” and “applicability” determine technical feasibility. Page B.17 of the New 

Source Review Workshop Manual states: 

Two key concepts are important in determining whether an undemonstrated 

technology is feasible: "availability" and "applicability." As explained 

in more detail below, a technology is considered "available" if it can be 

obtained by the applicant through commercial channels or is otherwise 
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available within the common sense meaning of the term. An available 

technology is "applicable" if it can reasonably be installed and operated 

on the source type under consideration. A technology that is available 

and applicable is technically feasible. Availability in this context is 

further explained using the following process commonly used for bringing 

a control technology concept to reality as a commercial product: 

• concept stage; 

• research and patenting; 

• bench scale or laboratory testing; 

• pilot scale testing; 

• licensing and commercial demonstration; and 

• commercial sales. 

 

Applicability involves not only commercial availability (as evidenced by past or expected near-term 

deployment on the same or similar type of emission source), but also involves consideration of the 

physical and chemical characteristics of the gas stream to be controlled. A control method applicable to 

one emission source may not be applicable to a similar source depending on differences in physical and 

chemical gas stream characteristics. 

2.6 Economic Feasibility. 

Economic feasibility is normally evaluated according to the average and incremental cost effectiveness. 

From the U.S. EPA’s New Source Review Manual, page B.31, average cost effectiveness is the dollars 

per ton of pollutant reduced. The incremental cost effectiveness is the cost per ton reduced from the 

technology being evaluated as compared to the next lower technology. The EPA NSR Review Manual 

states that, “where a control technology has been successfully applied to similar sources in a source 

category, an applicant should concentrate on documenting significant cost differences, if any, between the 

application of the control technology on those sources and the particular source under review”. 

2.6.1 Average Cost Effectiveness. 

In the EPA’s New Source Review Manual, page B.37, average cost effectiveness is calculated as: 

Average Cost Effectiveness Control option annualized cost 

($ per ton removed) = Baseline emission rate – Control option emissions rate 

The average cost effectiveness is based on the overall reduction in the air pollutant from the baseline 

emission rate. In the draft Workshop Manual, the EPA states that the baseline emission rate represents 

uncontrolled emissions for the source. However, the manual also states that when calculating the cost 

effectiveness of adding controls to inherently lower emitting processes, baseline emissions may be 

assumed to be the emissions from the lower emitting process itself. 
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2.6.2 Incremental Cost Effectiveness. 

In addition to determining the average cost effectiveness of a control option, the U.S. EPA’s New Source 

Review Manual states that the incremental cost effectiveness between dominant control options should 

also be calculated. The incremental cost effectiveness compares the costs and emissions performance 

level of a control option to those of the next most stringent control option: 

Incremental Cost ($ per Control option annualized cost – Next control option annualized cost 

incremental ton removed) = Next control option emission rate – Control option emissions rate 

2.6.3 Agency Decisions on Cost Effectiveness. 

Numerous permitting authorities have made decisions regarding the economic feasibility of air pollution 

controls for coal-fired electric utility boilers which represent BACT. Table 3-1 is a summary of recent 

BACT economic analyses by various review agencies in which the control technology was rejected as not 

cost effective for BACT. The determinations in Table 3-1 include decisions for PM, PM10, NOx, and SO2

emissions for biomass-fired boilers, pulverized coal-fired boilers, circulating fluidized bed boilers, and 

gas turbines. While cost effectiveness is determined on a case-by-case basis, the following information 

on comparative economic costs of BACT options gives some perspective on the costs that similar sources 

have typically not been expected to bear as BACT. 
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TABLE 2-1. Summary of recent BACT economic analyses in which the control technology was rejected as not cost 

Cost Effectiveness of 

Rejected Technology, 

Facility State $ per ton controlled Boiler Type Pollutant Control Technology Rejected Average Incremental 

Control 

Technolo

Selected 

1 DTE Energy – Stoneman Power Plant WI Stoker NOx SCR $9,217 SNCR 3 We Energies – Concord Generating Station WI Gas Turb NOx SCR 8,236 - Good Combusti2 Longleaf Energy Associates GA PC SO2 Wet FGD - $8,964 Dry FGD 4 Rocky Mountain Power Hardin MT PC SO2 Wet FGD $1,395 $23,855 Dry FGD 

5 Intermountain Power 3 UT PC PM / PM10 Baghouse w/ Teflon Bags $31 $14,000 Baghouse 

Ryton Ba

NOx SCR at 0.04 $2,004 $10,303 SCR at 0.

6 

Basin Electric - Dry Fork Station WY PC SO2 Wet FGD $1,595 $15,299 Dry FGD 

7 Black Hills Power & Light - WYGEN2 WY PC NOx SCR at 0.06 $4,156 $7,742 SCR at 0.8 Black Hills Power & Light – WYGEN3 WY PC PM / PM10 Baghouse w/ Teflon Bags $134 $14,609 Baghouse 

Fiberglass B

9 

Deseret Power Cooperative - Bonanza UT CFB SO2 Wet FGD $418 $10,540 Dry FGD 

Wet FGD - $27,365 

10 

Southern Montana Electric Coop- Highwood MT CFB SO2 Dry FGD - $7,939 Ash Reinjec

11 Montana-Dakota Utilities Gascoyne Station ND CFB NOx SCR $7,545 $14,339 SNCR 12 Red Trail Energy Ethanol Plant ND CFB SO2 Wet FGD $1,041 $10,252 Dry FGD 13 River Hill Power Company PA CFB SO2 Wet FGD - >$5,000 Dry FGD 14 Cargill - Blair Ethanol Plant NE CFB SO2 Dry FGD - $5,900 No Post Con

NOx SNCR - $5,600 SNCR 

15 ADM – Columbus Ethanol Plant NE CFB SO2 Ca Inj. - $6,700 
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1. In a PSD permit for the conversion of two coal-fired boilers to wood combustion, the Department 

concluded that the use of regenerative selective catalytic reduction with an average NOx control cost 

of $9,217 per ton was not economically feasible. 

2. In a PSD permit for 320 MW of simple cycle combustion turbine capacity, the Department concluded 

that the use of selective catalytic reduction with an average NOx control cost of $8,236 per ton was 

not economically feasible. 

3. In a PSD permit issued by the State of Georgia in 2006 for a new pulverized coal-fired utility boiler at 

Longleaf Energy Associates, Georgia determined that the incremental cost effectiveness of $8,964/ton 

for wet FGD compared to dry FGD for SO2 control was not cost effective. The average cost 

effectiveness of the selected BACT option, dry FGD, was $724/ton. Georgia’s PD is available online 

at: http://www.air.dnr.state.ga.us/airpermit/psd/dockets/longleaf/permitdocs/0990030pd.pdf. 

4. In a PSD permit issued by the State of Montana in 2005 for a new pulverized coal fired utility boiler 

at Rocky Mountain Power’s Hardin project, Montana concluded that an incremental cost 

effectiveness of $23,855/ton for a wet FGD system as compared to a dry FGD system was excessive 

for BACT. The average cost effectiveness of the wet FGD option was $1,395/ton. The average cost 

effectiveness of the selected BACT option, dry FGD, was $918/ton. (Ref: Montana’s Permit 

Analysis for Hardin project, Permit #3185-02, pages 15 and 17, dated May 16, 2005.) 

5. In a PSD permit issued by the State of Utah in 2004 for a new pulverized coal-fired electric utility 

boiler at Intermountain Power’s Unit 3, Utah concluded that an incremental cost effectiveness of 

$14,000/ton to $16,350/ton, comparing different types of baghouse fabric filter bags (Ryton-type bags 

versus specialty coated bags) for PM/PM10 control, was excessive for BACT. The average cost 

effectiveness of the selected BACT option for PM10 control (a baghouse with Ryton-type bags) was 

$31/ton. (Ref: Utah’s Modified Source Plan Review for IPP3 project, March 22, 2004, available 

online at: http://www.airquality.utah.gov/Permits/PmtPowerPlants.htm.) 

6. In a PSD permit issued by the State of Wyoming in 2007 for a new pulverized coal-fired electric 

utility boiler at Basin Electric’s Dry Fork Station, Wyoming concluded that an incremental cost 

effectiveness of $23,755/ton for NOx control, comparing SCR at 0.043 lb/mmBtu to SCR at 0.040 

lb/mmBtu, was excessive for BACT. The average cost effectiveness for SCR at 0.040 lb/mmBtu was 

$2,004/ton; the average cost effectiveness for SCR at 0.043 lb/mmBtu was $1,751/ton. Although 

Wyoming stated that an incremental cost effectiveness of $10,303/ton was reasonable for SCR at 

0.043 lb/mmBtu, for other reasons described by Wyoming the selected NOx control was SCR at 0.05 

lb/mmBtu, with an incremental and average cost effectiveness of $3,512/ton and $1,511/ton, 

respectively. 

Wyoming also concluded that an incremental cost effectiveness of $15,299/ton for SO2 control, 

comparing a dry FGD system at 0.073 lb/mmBtu to a wet FGD at 0.054 lb/mmBtu, was excessive for 

BACT. The average cost effectiveness of the eliminated wet FGD option at 0.054 lb/mmBtu was 

$1,595/ton. Although Wyoming determined that an incremental cost effectiveness of $9,296/ton was 

reasonable for a dry FGD at 0.043 lb/mmBtu, for other reasons described by Wyoming the selected 

BACT option for SO2 control was a dry FGD system at 0.08 lb/mmBtu, with an average cost 

effectiveness of $1,159/ton. (Ref: Wyoming’s Analysis for the Dry Fork project, NSR-AP-3546, 

February 5, 2007.) 

7. In a PSD permit issued by the State of Wyoming in 2002 for a new pulverized coal-fired electric 

utility boiler at Black Hills Power & Light’s WYGEN2 project, Wyoming concluded that an 

incremental cost effectiveness of $7,742/ton, comparing low-NOx burners plus SCR at 0.06 lb/mmBtu 

to low-NOx burners plus SCR at 0.08 lb/mmBtu, for NOx control was reasonable for BACT. 

However, for other reasons described by Wyoming, the selected BACT option was low-NOx burners 
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plus SCR at 0.07 lb/mmBtu, with an average cost effectiveness between $4,067/ton and $4,156/ton. 

(Ref: Wyoming’s Permit Application Analysis for the WYGEN2 project, NSR-AP-92, April 24, 

2002.) 

8. In a PSD permit issued by the State of Wyoming in 2006 for a new pulverized coal-fired electric 

utility boiler at Black Hills Power & Light’s WYGEN3 project, Wyoming indicated that an 

incremental cost effectiveness of $14,609/ton, comparing a baghouse with fiberglass or 

polyphenylene sulfide filter bags, listed as capable of achieving 0.012 lb/MmBtu, to a baghouse with 

specialty filter bags such as Teflon, listed as capable of achieving 0.011 to 0.010 lb/MmBtu, for 

PM/PM10 control, was excessive for BACT. The average cost effectiveness of the selected BACT 

option, a baghouse with fiberglass or polyphenylene sulfide filter bags, was $130/ton; the average 

cost effectiveness of the eliminated option, a baghouse with specialty filter bags, was $134/ton. (Ref: 

Wyoming’s Permit Application Analysis for the WYGEN3 project, NSR-AP-3934, October 9, 2006.) 

9. In a PSD permit issued by the U.S. EPA Region 8 in August, 2007 for a circulating fluidized bed 

(CFB) boiler at the Deseret Power Cooperative’s Bonanza Power Plant, the EPA concluded that an 

incremental cost of $10,540 per ton of SO2 removed to install a wet FGD system rather than a dry 

FGD system was too high to justify the expenditure. The average cost effectiveness for the wet FGD 

system was $418 per ton of SO2 controlled; the average cost effectiveness for the dry FGD system 

selected as BACT was $397/ton of SO2 controlled. Further, the EPA concluded that the costs for 

alternative sources of coal in lieu of waste coal of $20,241 per ton of SO2 controlled was also 

excessive as BACT. 

10. In a PSD permit issued by the State of Montana in May, 2007 for a CFB boiler at Southern Montana 

Electric Cooperative’s Highwood Generating Station, Montana concluded that a cost of $27,365/ton 

of SO2 control, for a combination of limestone injection, low-sulfur coal and wet FGD was excessive 

for BACT. Montana also concluded that a cost of $7,939/ton of SO2 controlled, for a combination of 

limestone injection, low-sulfur coal and dry FGD, was excessive for BACT. The selected SO2 BACT 

option was a combination of limestone injection, low-sulfur coal, and hydrated ash reinjection with a 

cost effectiveness of $4,054/ton. (Ref: Montana’s “Permit Analysis” for Air Quality Permit #3423-00, 

May 30, 2007, from the Montana Department of Environmental Quality.) 

11. In a PSD permit issued by the State of North Dakota in early 2005 for a CFB boiler at MontanaDakota Utilities Gascoyne Generating Station, North Dakota concluded that an incremental cost 

effectiveness of $14,339/ton, comparing SCR at 0.04 lb/mmBtu to SNCR at 0.09 lb/mmBtu, for NOx

control, was excessive for BACT. The average cost effectiveness of SCR was $7,545/ton. The 

average and incremental cost effectiveness of the selected BACT option, SNCR, was $2,926/ton. 

(Ref: North Dakota’s Permit Analysis, March 2005, North Dakota Department of Health, 

Environmental Health Section.) 

12. In a PSD permit issued by the State of North Dakota in 2004 for a CFB boiler at the Red Trail 

Energy’s Richardton, ethanol plant, North Dakota determined that an incremental cost effectiveness 

of $10,252/ton, comparing wet FGD plus limestone injection to dry FGD plus limestone injection, for 

SO2 control was not cost effective. The average cost effectiveness of wet FGD plus limestone 

injection was $1,041/ton; the average cost effectiveness of dry FGD plus limestone injection was 

$527/ton. North Dakota rejected wet FGD and determined that BACT is dry FGD plus limestone 

injection. (Ref: North Dakota’s Analysis for Red Trail Energy project, May 2004, North Dakota 

Department of Health, Environmental Health Section, Air Quality Division.) 

13. In a PSD permit issued by the State of Pennsylvania in 2005 for a CFB boiler at the River Hill Power 

Company, Pennsylvania concluded that all SO2 BACT options involving wet FGD systems were 

economically infeasible at an incremental dollar per ton value greater than $5,000 per ton of SO2
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removed. Pennsylvania concluded that the use of dry FGD was economically feasible for the control 

of SO2 at an incremental cost of $1,511 per ton of SO2 removed. Pennsylvania also concluded that an 

incremental cost effectiveness of $15,975/ton, comparing the use of the waste coal to the nearest 

alternative source of coal with lower sulfur content, was excessive as BACT for SO2 emissions. (Ref: 

Pennsylvania’s “Plan Approval Review Memo, Application #17-00055A,” May 2, 2005.) 

14. In a PSD permit issued by the State of Nebraska in 2006 for a CFB boiler at Cargill’s Blair ethanol 

production plant, Nebraska indicated that an incremental cost effectiveness of $5,900/ton, comparing 

limestone injection alone to limestone injection plus dry FGD for SO2 control, was excessive for 

BACT. (Ref: Nebraska permit CP06-0008, Sept. 8, 2006, available at 

http://www.epa.gov/region07/programs/artd/air/nsr/archives/2006/finalpermits/cargill_blair_final_psd

_permit.pdf.) 

15. In a PSD permit issued by the State of Nebraska in 2006 for a CFB boiler at ADM’s Columbus corn 

milling and ethanol production plant, Nebraska indicated that incremental cost effectiveness of 

$5,600/ton for NOx control (comparing SNCR at 0.07 lb/mmBtu to SNCR at below 0.07), and an 

incremental cost effectiveness of $6,700/ton for SO2/H2SO4/HF control (comparing limestone 

injection to “additional” limestone injection), were excessive for BACT. Nebraska listed incremental 

cost-effectiveness of $2,174 for the selected BACT option for NOx control (SNCR at 0.07 lb/mmBtu). 

(Ref: Nebraska permit CPM02-0006, August 4, 2006, available online at: 

http://www.epa.gov/region07/programs/artd/air/nsr/archives/2006/finalpermits/adm_columbus_final_

psd_permit.pdf.) 

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Chapter 3. Carbon Monoxide (CO) 

Control Technology Review. 

Carbon monoxide (CO) is emitted from biomass-fired boilers as a result of incomplete combustion. 

Incomplete combustion can also result in reduced boiler efficiency and emissions of particulate matter, 

volatile organic compounds, and organic hazardous air pollutants. CO and VOC emissions from the 

combustion of biomass fuels are normally expected to be somewhat elevated as compared to the 

combustion of natural gas, fuel oil, and coal because of the high moisture content and relatively low 

heating value of most biomass fuels. Because fuel costs represent the highest single operating cost for this 

boiler, this biomass-fired boiler is designed to achieve the highest combustion efficiencies practicable. 

CO emissions can be reduced by operating the boiler with higher furnace temperatures, higher excess 

oxygen levels, and longer furnace residence times. Unfortunately, techniques for reducing CO emissions 

can increase NOx emissions. Achieving low CO and low NOx emissions is therefore a balancing act in 

boiler design and operation. 

3.1 BACT Baseline. 

There are no specific Wisconsin state implementation plan (SIP) requirements or new source performance 

standards for CO emissions from biomass or fossil fuel-fired boilers. Therefore, baseline emissions are 

the uncontrolled emissions from the boiler. 

3.2 STEP 1. Identify All Available Control Technologies. 

Table 3-1 is a summary of carbon monoxide (CO) BACT emission limits for new biomass-fired boilers 

contained in the U.S. EPA’s RACT/BACT/LAER Clearinghouse, and in other permits issued in the 

United States. Emission limits range from 0.10 to 1.15 pounds per million Btu. Except for one facility, 

the only technology selected for all permitted biomass-fired boilers is good combustion practices. For the 

South Point Biomass Generation facility (Ohio, 2006), the facility was required to install an oxidation 

catalyst. However, this facility has not been constructed and therefore has not demonstrated compliance 

with a BACT emission limit. Note that from Table 3-1, of the top 6 ranked facilities, i.e., the Public 

Service of NH - Schiller Station, South Point Biomass Generation, Yellow Pine Energy Company, 

Nacogdoches Power, LLC, Mancelona Renewable, and Northern Michigan University, only the South 

Point Biomass boiler is a stoker boiler. The other boilers are fluidized bed boilers. 

3.3 STEP 2. Identify Technically Feasible Control Technologies. 

Available control technologies for the control of CO emissions include good combustion practices, 

oxidation catalysts, and thermal oxidation. 
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3.3.1 Oxidation Catalysts. 

Oxidation catalysts are used to reduce CO emissions from natural gas or oil-fired combustion turbines, 

with typical CO reductions of 50 – 90%. However, oxidation catalysts have limited demonstration on 

biomass-fired boilers, and we are not aware of any demonstration or commercial operation of oxidation 

catalysts on a fluidized bed boiler. Boilers have several characteristics that make the use of oxidation 

catalysts technically infeasible, including catalyst fouling and poisoning by the wood fly ash, and low 

excess oxygen levels in the flue gas. 

CO oxidation catalysts are generally noble metal catalysts which are susceptible to poisoning from sulfur 

and calcium bearing compounds. These catalysts may experience rapid deactivation and fouling in 

biomass-fired boiler flue gas streams with high particulate loading. To be effective, the oxidation catalyst 

must be placed in a location with gas temperatures of at least 600 o

F. This location would be near the 

boiler economizer outlets, a location with high ash loading and low excess oxygen levels. 

A research effort to assess catalyst deactivation mechanisms was presented at the 2008 Advanced 

Combustion Engineering Research Center conference1

 reported that SCR catalyst poisoning is the 

predominant deactivation mechanism resulting from biomass combustion. Note that oxidation catalysts 

and SCR catalysts have similar poisoning mechanisms. The study ranks the order of poisoning of the 

alkali-metals and alkaline-earth metals from having the most effect to lesser effect as potassium, followed 

by sodium, followed by calcium, and states that the “effects are proportional to basicity of the exhaust 

gas.” The study includes Figure 3-2 showing the difference in of coal versus biomass ash composition. 

Figure 3-2 shows that the relative proportion of potassium is much greater in the biomass ash than in the 

coal ash. Because of the presence of these base compounds and the low acid gas constituents such as 

sulfur dioxide (SO2), biomass flue gas tends to be basic while especially high sulfur coal combustion flue 

gas tends to be acidic. This exacerbates the catalyst deactivation and is the primary reason that oxidation 

catalyst and SCR systems located in a high dust environment are not applicable to biomass combustors. 

This problem is worsened by the CFB boiler design which has an extremely high dust loading. Erosion, 

plugging, and blinding are major potential problems in fluidized bed boiler applications due to the very 

high particulate loading in the boiler. 

To reduce the fouling and catalyst poisoning problems, the oxidation catalyst can be located downstream 

of the particulate matter control device. However, this “tail gas” oxidation catalyst control configuration 

does not eliminate fouling and deactivation, since the exhaust gas stream remains highly alkaline. 

In addition to this severe poisoning problem, the use of oxidation catalysts in this boiler application have 

another problem; the lack of sufficient excess oxygen to effectively reduce CO emissions. Oxidation 

catalysts operate according to the following general reaction: 

 2CO + O2 → 2CO2 

 

1

 Guo, X., et. al. Poisoning/Deactivation Study of V2O5/TiO2 SCR Catalysts, ACERC Annual Conference, 

February 2008. 
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Typical excess oxygen (O2) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in biomassfired boilers. These low excess O2 levels will limit the effectiveness of the oxidation catalyst. 

Because of these serious technical problems and the fact that oxidation catalysts have not been 

demonstrated on similar circulating fluidized bed biomass boilers, we have concluded that oxidation 

catalysts are not a technically feasible CO control technology for these biomass-fired boilers. 

FIGURE 3-2. Coal and biomass ash composition showing the high levels of potassium and 

sodium in biomass ash relative to coal ash. 

 (Source: Guo, X., et. al. Poisoning / Deactivation Study of V2O5/TiO2 SCR Catalysts, ACERC Annual 

Conference, February 2008.) 

3.3.2 Thermal Oxidation 

Thermal oxidation has never been required nor used on a biomass-fired boiler, and its theoretical ability 

to reduce CO emissions from these boilers has not been demonstrated in practice and is questionable. 

Thermal oxidation would involve injecting additional air into the flue gas and heating the oxygen 

enriched mixture to approximately 1,500 o

F to oxidize CO to carbon dioxide. However, since the 

combustion of the reheat fuel would itself result in CO emissions, there is no evidence that thermal 

oxidation would result in any CO emission reductions. Since thermal oxidation has never been 

demonstrated on a biomass-fired boiler, and because there is no evidence that it could reduce CO 

emissions, thermal oxidation is not a technically feasible CO control technology for these boilers. 

3.3.3 Good Combustion Practices 

Good combustion practices or combustion controls generally include the following components: 
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1. Good air/fuel mixing in the combustion zone. 

2. High temperatures and low oxygen levels in the primary combustion zone. 

3. Overall excess oxygen levels high enough to complete combustion while maximizing 

boiler thermal efficiency. 

4. Sufficient residence time to complete combustion. 

In biomass-fired boilers, good combustion practices is the only technically feasible CO control 

technology. Combustion efficiency is related to the three “T’s” of combustion: Time, Temperature, and 

Turbulence. These components of combustion efficiency are designed into utility boilers to maximize 

fuel efficiency and reduce the highest single operating cost of a utility boiler: FUEL. A fourth critical 

parameter is the level of oxygen in the boiler, referred to as the excess air or excess oxygen level. 

Therefore, combustion control is accomplished primarily through boiler design as it relates to time, 

temperature, and turbulence, and through boiler operation as it relates to excess oxygen levels. 

Combustion design for modern boilers is intended to simultaneously minimize formation of CO and NOx

emissions. This is a difficult task, since emissions of NOx and emissions of CO are inversely related. 

That is, measures used to reduce NOx emissions often lead to increases in CO emissions. Therefore, the 

boiler design to minimize CO emissions is interrelated with the boiler design to minimize NOx formation. 

TABLE 3-1. Carbon monoxide (CO) BACT emission limits for biomass fuel-fired boilers. 

Facility State Permit 

Date 

Capacity, 

mmBtu/hr Primary Fuel Limit, lb/mmBtu 

Pub. Service of NH - Schiller Station NH Oct-04 720 Wood 0.10 

South Point Biomass Generation OH Apr-06 318 Wood 0.10 

Yellow Pine Energy Company GA May-09 1,529 Wood 0.15 

Nacogdoches Power, LLC TX Mar-07 1,374 Wood 0.15 

Mancelona Renewable MI Nov-09 565 Wood/Biomass 0.17 

Northern Michigan University MI Nov-09 210 Wood/Biomass 0.17 

Fibrominn Biomass Power MN Feb-05 792 Poultry Litter 0.24 

Virginia PWC - Laurention Energy MN Aug-05 230 Wood 0.30 

District Energy St. Paul, Inc. MN Nov-01 550 Wood 0.30 

Sierra Pacific Aberdeen facility WA Oct-02 310 Waste Wood 0.35 

S.D. Warren Company ME Nov-01 1,300 Wood 0.40 

Stoneman Power Plant WI Jan-09 340 Wood 0.40 

Koda Energy MN Aug-07 308 Wood / Nat. Gas 0.43 

Martinsville Thermal LLC VA Sep-03 120 Wood 0.44 

Wheelabrator Sherman Energy ME Apr-99 315 Wood 0.45 

Northern Sun ND May-06 100 Wood / Hulls 0.63 

Skagit County Lumber Mill WA Jan-06 430 Wood 0.93 

Sierra Pacific Industries CA Dec-02 245 Wood 1.15 
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3.4 STEP 3. Rank the Technically Feasible Control Technologies. 

Based on the above analysis, the only technically feasible CO control technology for biomass-fired 

boilers is good combustion practices. From Table 3-1, recent BACT determinations have CO limits 

ranging from 0.10 to 1.15 lb/mmBtu. The proposed CFB boiler is an advanced boiler which is expected 

to achieve low CO emission rates. However, boiler startup, shutdown, and load changes can causes CO 

emissions to increase because of unstable combustion conditions. CO emissions are also sensitive to 

boiler operating conditions. Changes in operating conditions, such as rapid changes in load, can have a 

significant, though temporary, impact on emissions. This condition is further exasperated during boiler 

startup because the boiler itself is relatively cool, and the low air flow rates make it difficult to obtain 

good air/fuel mixing. For these reasons, CO emissions can “spike” when transient conditions occur 

during boiler startup and shut down. 

Based on the analysis of this boiler, we have concluded that this boiler can achieve CO emission rates of 

0.20 lb/mmBtu, excluding periods of startup and shutdown, averaged over any 30-day period. In 

addition, we have concluded that this boiler can achieve an emission rate of 0.20 lb/mmBtu including all 

periods, averaged over any consecutive 12-month period. 

3.5 STEP 4. Evaluate the Most Effective Controls. 

Because the only technically feasible control technology for the control of CO emissions from this boiler 

is good combustion practices, further evaluation is unnecessary. 

3.6 STEP 5. Proposed Carbon Monoxide BACT Determination. 

Based on this analysis, We Energies has concluded that the use of good combustion practices is the best 

available control technology (BACT) for CO emissions from the biomass-fired boiler B01. Based on this 

analysis, We Energies proposes the following limits as BACT for the control of CO emissions from the 

biomass-fired, fluidized bed boiler B01. 

(1) Carbon monoxide (CO) emissions from the biomass-fired boiler B01 

shall be controlled using good combustion practices as the best 

available control technology. 

(2) Carbon monoxide (CO) emissions may not exceed 0.20 pounds per 

million Btu of heat input, excluding periods of boiler startup and shut 

down, averaged over any consecutive 30-day period. 

(3) Carbon monoxide (CO) emissions may not exceed 0.20 pounds per 

million Btu of heat input, for all periods, including periods of boiler 

startup and shut down, averaged over any consecutive 12-month period. 

(4) Carbon monoxide (CO) emissions from the biomass-fired boiler B01 

shall be continuously monitored and recorded using a continuous 

emissions monitoring system meeting the requirements of 40 CFR Part 

60 Appendix B, and NR 439.06(4), Wis. Adm. Code. 

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Chapter 4. Nitrogen Oxides (NOx) 

Control Technology Review. 

Nitrogen oxides (NOx) consist of several compounds, including nitrogen oxide (NO), and nitrogen 

dioxide (NO2). During combustion, NO usually accounts for more than 90% of the total NOx emissions. 

However, since NO is subsequently converted to NO2 in the atmosphere, the mass emission rate of NOx

are normally reported as NO2. NOx is formed during combustion by two major mechanisms; thermal 

formation, called “Thermal NOx”, and fuel formation, called “Fuel NOx”. Thermal NOx results from the 

high temperature oxidation of nitrogen (N2) and oxygen (O2). Thermal NOx formation is influenced by 

the flue gas residence time and excess oxygen, but, as its name implies, thermal NOx formation is 

primarily influenced by temperature. Thermal NOx formation increases exponentially with temperature, 

and becomes significant at temperatures above 2800 °F. Fuel NOx results from the oxidation of organic 

nitrogen compounds in the fuel. Fuel bound nitrogen is more easily converted to NOx during combustion. 

Fuel NOx may account for up to 80% of the total NOx emissions from solid fuel combustion. 

4.1 BACT Baseline. 

Boiler B01 will be subject to the Standards of Performance for Industrial-Commercial-Institutional Steam 

Generating Units under 40 CFR Part 60, Subpart Db. This subpart applies to steam generating units that 

commence construction, modification, or reconstruction after June 19, 1984, and that have a heat input 

capacity greater than 100 mmBtu/hr. The current Subpart Db rules for NOx emissions were published in 

the Federal Register June 13, 2007. Under 40 CFR § 60.44b(d), an affected facility that simultaneously 

combusts natural gas with wood, municipal-type solid waste, or other solid fuel, except coal, may not 

exceed a NOx emission rate of 0.30 lb/mmBtu heat input unless the affected facility has an annual 

capacity factor for natural gas of 10% or less and is subject to a federally enforceable requirement that 

limits operation of the affected facility to an annual capacity factor of 10% or less for natural gas. 

4.2 STEP 1. Identify All Potential Control Strategies. 

There are two major technology categories for controlling NOx emissions from this biomass-fired boiler: 

combustion controls and post-combustion controls. Combustion NOx controls include technologies such 

as advanced fluidized bed boilers to avoid NOx formation. Post combustion NOx controls reduce 

emissions after NOx has been created. The most common post combustion control techniques involve the 

injection of ammonia into the flue gas at various locations in the boiler or downstream of the boiler to 

control NOx emissions. When ammonia is injected upstream of a catalyst, the process is called Selective 

Catalytic Reduction (SCR); when injected in the boiler without a catalyst, the process is called Selective 

Non-Catalytic Reduction (SNCR). Combustion and post combustion controls may be used together to 

achieve the lowest emission rates. The following NOx control technologies were identified: 
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Combustion Controls 

• Staged Combustion 

• Low NOx burners (LNB) 

• Overfire air (OFA) 

• Flue Gas Recirculation (FGR) 

• Oxygen-Enhanced Combustion (OEC) 

• Fuel Reburn 

Post Combustion Controls 

• Selective Non-Catalytic Reduction (SNCR) 

• Selective Catalytic Reduction (SCR) 

• SCONOxTM 

• Emerging Control Technologies. 

Table 4-1 is a summary of the NOx BACT emission limits for similar biomass-fired boilers in the U.S. 

EPA’s RBLC, and in other permits identified for similar units. 

TABLE 4-1. Biomass-fired boiler nitrogen oxides (NOx) emission limits representing BACT. 

Facility State Permit 

Date 

Capacity, 

mmBtu/hr Primary Fuel Control System 

Limit, 

lb/mmBtu 

Clean Power Berlin, LLC NH Sep-09 390 Wood SCR 0.065 

Concord Steam Corporation NH Feb-09 305 Wood SCR 0.065 

Pub. Serv. of NH - Schiller Station NH Oct-04 720 Wood SNCR 0.075 

South Point Biomass Generation OH Apr-06 318 Wood SCR 0.088 

Mancelona Renewable MI Nov-09 565 Biomass SNCR 0.10 

Yellow Pine Energy Company GA May-09 1,529 Wood SNCR 0.10 

Nacogdoches Power, LLC TX Mar-07 1,374 Wood SNCR 0.10 

Northern Michigan University MI Nov-09 210 Wood None 0.15 

Darrington Energy Cogeneration WA Feb-05 403 Wood / Bark SNCR 0.12 

Skagit County Lumber Mill WA Jan-06 430 Wood / Bark SNCR 0.13 

Virginia PWC - Laurention Energy MN Aug-05 230 Wood SNCR 0.15 

Hibbing PUC - Laurention Energy MN Aug-04 230 Wood SNCR 0.15 

Sierra Pacific Aberdeen facility WA Oct-02 310 Waste Wood SNCR 0.15 

District Energy St. Paul, Inc. MN Nov-01 550 Wood 

Natural Gas SNCR 0.15 0.11 

Koda Energy MN Aug-07 308 Wood 

Natural Gas SNCR 0.25 0.18 

Fibrominn Biomass Power MN Feb-05 792 Manure SNCR 0.16 

S.D. Warren Company ME Nov-01 1,300 Wood SNCR 0.20 

Stoneman Power Plant WI Jan-09 340 Wood SNCR 0.20 

Hillman Power MI Jul-02 300 Wood /TDF SNCR 0.20 

Sierra Pacific Industries CA Dec-02 245 Wood SNCR 0.23 

Boralex Stratton Energy, LP ME Jan-05 672 Wood RSCR 0.24 

Boise White Paper LLC WA Feb-06 343 Wood / Bark OFA 0.30 

Martinsville Thermal LLC VA Sep-03 120 Wood GCP 0.40 

Footnotes 

For the District Energy St. Paul and the Koda Energy facilities, the second limit is for natural gas firing.
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4.3 STEP 2. Identify Technically Feasible Control Technologies. 

There are two key concepts in determining the feasibility of potential control technologies: “availability” 

and “applicability.” A technology is considered “available” if it can be obtained commercially, has 

completed a commercial demonstration, and has reached the point of licensing. When considering a 

technology’s applicability, technical judgment must be exercised to determine if it can reasonably be 

installed and operated on the proposed source. In determining the feasibility of a given technology to 

achieve a given emission rate over the long term there is a third concept, “demonstrated in practice.” A 

performance level or emission rate is “demonstrated in practice” if a unit with similar operating 

conditions has a continuous, proven performance record. 

4.3.1 Fluidized Bed Boilers. 

The fluidized bed boiler combustion process has inherently low NOx emissions due to the relatively low 

combustion temperatures in the boiler. Modern, advanced fluidized bed boilers include staged 

combustion to spread the combustion process out in the boiler and minimize the combustion temperature 

to minimize NOx formation. The fluidized bed boiler technology was developed to reduce SO2 and NOx

emissions from the combustion of coal and other high sulfur fuels such as petroleum coke. Fluidized bed 

boilers have a great advantage in that they are inherently flexible for fuels selection, making fluidized bed 

boilers ideal for biomass combustion. 

In the furnace of the fluidized bed boiler, limestone or an inert material such as sand is injected with solid 

fuel to create a “bed”. Combustion air forced in at the bottom of the furnace keeps the bed in a constantly 

upward moving flow. The mixture of fuel, limestone, char and ash is suspended or “fluidized” in this 

upwardly flowing stream. Although the fuel and limestone are solids, the combination of fuel, limestone, 

and ash particles and combustion air exhibit fluid-like properties. The highly turbulent, erosive 

conditions of the fluidized bed result in very high combustion efficiencies even though combustion takes 

place at relatively low combustion temperatures of 1,500 to 1,650°F. Because thermal NOx formation 

increases dramatically at temperatures in excess of 2,800°F, the lower fluidized bed boiler temperatures 

significantly reduces NOx formation. 

Based on vendor information, the NOx emission rate from an advanced fluidized bed boiler firing biomass 

without post combustion controls will typically be 0.15 lb/mmBtu. This “uncontrolled” NOx emission 

rate is 30 – 50% less than the uncontrolled NOx emission rate for conventional stoker boilers used for 

biomass firing. Based on this review, fluidized bed boilers are a feasible control option for this project. 

4.3.2 Low NOX Burners and Overfire Air. 

Low NOx burners (LNB) are designed to control the mixing of air and fuel to reduce the peak 

temperatures of combustion in coal-fired boilers. Fluidized bed boilers do not use burners to inject the 

fuel into the boiler. Therefore LNBs are not technically feasible for fluidized bed boilers. 
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4.3.3 Overfire Air (Staged Combustion). 

Overfire air (OFA) is a combustion staging processes typically used in conjunction with low NOx burners. 

A portion of the combustion air is redirected from the LNB to a higher elevation in the furnace to reduce 

peak flame temperatures by reducing the concentration of oxygen in portions of the furnace. This 

technique is used in pulverized coal and stoker-fired boilers to create an oxygen depleted zone where 

unburned hydrocarbon species act to reduce the NOx that was formed near the coal burner or traveling 

grates. The overfire air creates an oxidation zone to complete combustion. NOx formation is minimized 

by completing combustion in an air-lean environment. 

Overfire air systems are similar to the staged combustion used in state-of-the-art fluidized bed boilers. In 

a fluidized bed boiler, primary air is introduced at the bottom of the boiler to fluidize the bed while 

secondary air is added at a higher elevation to complete combustion. Staged combustion or overfire air is 

a part of the standard design for all new fluidized bed boilers. 

4.3.4 Flue Gas Recirculation. 

Flue gas recirculation (FGR) is an additional combustion process often used in conjunction with low NOx

burners to reduce peak flame temperatures and create an oxygen depleted zone in the boiler by reducing 

the concentration of oxygen in portions of the furnace. Flue gas recirculation reduces the oxygen content 

of the air at the base of the furnace by diluting the primary air blown into the furnace with recirculated 

flue gas from the back pass of the boiler. This technique is used in pulverized coal and stoker-fired 

boilers to create an oxygen depleted reducing zone where unburned hydrocarbon species act to reduce the 

NOx that was formed near the coal burner. This oxygen depleted zone also reduces the peak flame 

temperatures which minimizes NOx formation. FGR systems are NOx reduction techniques used in 

smaller pulverized coal-fired boilers. This process is not necessary for a fluidized bed boiler because the 

peak flame temperatures and NOx emissions are already minimized by the fluidized bed design. 

Therefore, FGR is not an applicable NOx control technology for fluidized bed boilers. 

4.3.5 Oxygen-Enhanced Combustion. 

Oxygen-Enhanced Combustion (OEC) is a combustion control technology aimed at reducing the 

formation of thermal NOx. Praxair Technology, Inc. has developed a method of using oxygen to achieve 

additional NOx reduction from low NOx burners on pulverized coal-fired boilers. Field tests were 

conducted at the James River Power Station Unit 3, a wall-fired boiler. In pilot- and full-scale testing, 

NOx emissions were reduced by as much as 60%, to levels below 0.15 lb/mmBtu, when a small portion of 

low-NOx burner combustion air was replaced with locally injected oxygen. 

OEC has never been demonstrated or used on a fluidized bed boiler. Because there is no operational 

experience with OEC on fluidized bed boilers, and because the application of OEC to fluidized bed 

boilers has significant technological questions, OEC is not a technically feasible control option for this 

boiler. 
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4.3.6 Natural Gas or Coal Reburning 

Natural gas or coal reburning are NOx control techniques used primarily for reducing NOx emissions from 

existing utility scale coal-fired boilers. Reburning redistributes a portion of both fuel and air into the 

upper regions of the boiler furnace to create a second flame zone, generating chemically reducing 

conditions that destroy NOx in the primary combustion zone. In large utility pulverized coal-fired boilers, 

fuel reburning is conducted between the upper burner row and the furnace exit. Most reburn systems 

divert 10 to 20% of the total boiler heat input to the upper furnace. If reburn conditions are not carefully 

controlled, high temperature corrosion problems can occur which can damage the boiler.

At least five utility coal-fired demonstrations of reburn are in different levels of operation. In the best 

applications, reburning may reduce NOx emissions to 0.15 lb/mmBtu. However, to be effective in 

reducing NOx emissions natural gas or coal reburning requires a large furnace volume to adequately stage 

combustion. The, natural gas and/or coal reburning process is not applicable to fluidized bed boilers 

which are not designed to allow reburning. Therefore, natural gas and coal reburning are not technically 

feasible control options for this biomass-fired boiler. 

4.3.7 Selective Catalytic Reduction. 

Selective Catalytic Reduction (SCR) is a post combustion NOx control system that can substantially 

reduce NOx emissions from boilers. SCR systems consist of an ammonia (NH3) injection system and a 

catalytic reactor. Urea can be decomposed in an external reactor to form ammonia for use in an SCR. 

The ammonia injection grid is located upstream of the catalyst. Ammonia reacts with NOx and O2 in the 

presence of the catalyst to form molecular nitrogen (N2) and water according to the following general 

equations: 

 4NH3 + 4NO + O2 → 4N2 + 6H2O 

 4NH3 + 2NO2 + O2 → 3N2 + 6H2O 

 2NH3 + NO + NO2 → 2N2 + 3H2O 

This process is called “selective” because ammonia reacts preferentially with NOx in the flue gas in the 

presence of a catalyst. A catalyst is used to enhance NOx reduction and ammonia utilization. The most 

common catalyst for utility boiler applications is a vanadium-based material supported on a honeycomb 

substrate that is installed in multiple layers in the catalytic reactor. Secondary reactions also occur in the 

presence of the SCR catalyst, including the oxidation of SO2 to SO3 and the oxidation of elemental 

mercury. 

The SCR reactor operating temperature is critical to SCR performance. For most boiler applications, the 

SCR catalyst has an optimum operating range of 650 - 750 o

F. There are two types of SCR systems 

designed to achieve this operating temperature, called ’high dust‘ and ’low dust‘ systems. A ’high dust‘ 

SCR is located upstream of the air heater and particulate control system, usually in the back pass of the 

boiler downstream of the economizer. A ’low dust‘ or ’tail gas‘ SCR is located downstream of the air 

heater and particulate control system. In a ‘low dust’ SCR application, flue gas reheating is necessary to 

increase the flue gas temperature to the correct operating temperature required by the SCR process. 
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4.3.8 High Dust SCR. 

High dust SCR systems have been demonstrated on pulverized coal-fired boilers. However, we are not 

aware of a high dust SCR systems on fluidized bed boilers burning either biomass or coal. This is 

because a high dust SCR system on a fluidized bed boiler would be subject to very high particulate 

loading. In addition, for a biomass-fired fluidized bed boiler, there would be high concentrations of 

alkaline earth metals from the biomass ash. 

There are four basic mechanisms for deactivation of an SCR catalyst which reduce or eliminate the ability 

of the SCR system to control NOx emissions: 1. Poisoning; 2. Plugging; 3. Fouling; and 4. Erosion. 

Poisoning results from chemical attack on the surface of the catalyst. Plugging involves microscopic 

blockage of catalyst pores by small ash particles. Fouling involves macroscopic blockage of the catalyst 

through a build-up of ash. Erosion of the catalyst surface is due to the abrasive nature of the particulates 

in a high dust environment and can lead to deactivation through the wearing away of the catalyst surface. 

Figure 4-1 is an example of SCR catalyst fouling and plugging. 

FIGURE 4-1. High dust SCR catalyst plugging, fouling, and structural support failure. 

All of these deactivation mechanisms are at work on a high dust SCR catalyst. The primary mechanisms 

for deactivation of an SCR catalyst in a wood-fired fluidized bed boiler is catalyst poisoning where the 

active sites on the surface of the catalyst are chemically attacked by alkali metals such as sodium and 

potassium, alkaline-earth metals such as calcium, and fouling due to the very high dust loading. 
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There have been several investigations into the effect of biomass firing on SCR performance. One study 

entitled Biomass Impacts on SCR Catalyst Performance2

 documents the high level of alkali and alkalineearth compounds in biomass as compared with various grades of coal. One conclusion of that report 

notes that intimate contact between the alkali and alkaline-earth metals in the high dust environment act 

as “effective poisons” of the SCR catalyst. The results of another research effort to assess catalyst 

deactivation mechanisms was presented at the 2008 Advanced Combustion Engineering Research Center 

(ACERC) conference3

 and has a similar conclusion; catalyst poisoning is the predominant deactivation 

mechanism resulting from biomass combustion. The study ranks the order of poisoning of the alkalimetals and alkaline-earth metals from having the most effect to lesser effect as potassium, followed by 

sodium, followed by calcium, and states that the “effects are proportional to basicity of the exhaust gas.” 

Figure 4-2 is from this study and shows the difference in the ash composition of coal versus biomass. 

Figure 4-2 shows that the relative proportion of potassium is much greater in the biomass ash than in the 

coal ash. Because of the presence of these base compounds and the low acid gas constituents such as 

sulfur dioxide (SO2), biomass flue gas tends to be basic while especially high sulfur coal combustion flue 

gas tends to be acidic. This exacerbates the catalyst deactivation and is the primary reason that SCR 

systems located in a high dust environment are not applicable to biomass-fired boilers. 

FIGURE 4-2. Coal and biomass ash composition showing the high levels of potassium and sodium 

in biomass ash relative to coal ash. 

 (Source: Guo, X., et. al. Poisoning / Deactivation Study of V2O5/TiO2 SCR Catalysts, ACERC Annual 

Conference, February 2008.) 

 

2

 Baxter, L., Biomass Impacts on SCR Catalyst Performance, IEA Bioenergy Task 32, October 2005. 

3

 Guo, X., et. al. Poisoning/Deactivation Study of V2O5/TiO2 SCR Catalysts, ACERC, February 2008. 
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Figure 4-2 shows that the relative proportion of potassium is much greater in the biomass ash than in the 

coal ash. Because of the presence of these base compounds and the low acid gas constituents such as 

sulfur dioxide (SO2), biomass flue gas tends to be basic while especially high sulfur coal combustion flue 

gas tends to be acidic. This exacerbates the catalyst deactivation and is the primary reason that SCR 

systems located in a high dust environment are not applicable to biomass combustors. This problem is 

worsened by the CFB boiler design which has an extremely high dust loading. Erosion, plugging, and 

blinding are major potential problems in fluidized bed boiler applications due to the very high particulate 

loading in the boiler. Based on this analysis, high dust SCR is not a technically feasible NOx control 

technology for this biomass-fired, CFB boiler. 

4.3.9 Tail Gas SCR. 

A tail gas SCR system arrangement where the SCR catalyst is located downstream of the particulate 

control device can reduce deactivation problems. In a tail gas SCR arrangement, the ammonia injection 

rate to the SCR must be very carefully controlled to prevent excess ammonia – called ammonia slip - 

from being carried over, since there are no pollution control systems to control the ammonia downstream 

of the tail gas SCR. In a tail gas SCR system, ammonia slip should be kept as low as possible to avoid 

emissions of ammonia vapor and the potential formation of ammonium bisulfate. The ammonium 

bisulfate that is carried over in the flue gas would add to the total PM10 and PM2.5 emissions since there 

are no downstream collection devices to capture these emissions in the tailgas SCR arrangement. 

There are two possible catalysts for a tailgas SCR arrangement, including low temperature and high 

temperature catalysts. Both catalyst types may require reheat of the flue gas, especially if any type of flue 

gas desulfurization (FGD) is used. However, low temperature catalysts which require less (or possibly 

no) reheat are extremely sensitive to sulfite (SO3) poisoning. In a low dust SCR with a standard catalyst, 

reheat would be required to raise the temperature from about 290 o

F (the baghouse exit temperature) to 

650 o

F. In a low dust SCR with a low temperature catalyst, reheat may be required to raise the 

temperature to 450 o

F. 

The Boralex Stratton Energy, LP biomass-fired plant in Maine has a regenerative SCR system. Boralex 

voluntarily installed this system with the goal of achieving NOx reductions in order to certify the facility 

as a renewable energy generator by the State of Connecticut. Connecticut is focused on low NOx energy 

provided by renewable energy sources combusting qualified fuels. Once certified, Boralex was allowed 

the opportunity to compete for the sale of renewable energy credits (RECs) directly to those generators or 

their energy marketing representatives which must have these credits to meet their Renewable Portfolio 

Standard (RPS) requirements. To be eligible for Connecticut’s RPS Program, the NOx emission rate can 

not exceed 0.075 lb/mmBtu on a quarterly basis. This plant received a minor modification to its air permit 

in 2005 in which the Maine Department of Environmental Protection concluded that the best available 

control technology (BACT) for NOx emissions from this boiler is the use of RSCR, and an emission limit 

of 0.24 lb/mmBtu. Note that the NOx emission limit of 0.075 lb/mmBtu required to meet the CT RPS

Program is not a requirement of the air permit. 

Based on this review, tailgas SCR is a technically feasible control option for this biomass-fired boiler. 
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4.3.10 Selective Non-Catalytic Reduction. 

In a selective non-catalytic reduction (SNCR) control system, urea or ammonia is injected into the boiler 

where the flue gas temperature is approximately 1,600 to 2,100 °F. At these much higher temperatures 

(as compared to SCR), the reagent, urea [CO(NH2)2] or ammonia [NH3], reacts with NOx, forming 

elemental nitrogen [N2 ] and water without the need for a catalyst. The overall NOx reduction reactions 

are similar to those for SCR. The U.S. EPA estimates SNCR control efficiencies of 25 – 40%4

, although 

higher control efficiencies have been reported in limited applications. However, compared to SCR 

systems, the ammonia to NOx ratio is normally much higher for SNCR systems. For SNCR, ammonia is 

typically injected at an NH3 to NOx molar ratio of 1.2 – 2.0 moles of NH3 per mole of NOx, compared 

with 1.0 - 1.1 moles of NH3 per mole of NOX for SCR. 

The critical parameters for successful and effective control of NOx emissions using SNCR is a proper 

temperature window for SNCR performance, and adequate residence time at that temperature for the 

reaction to occur. If the temperature is too high, the ammonia will undergo chemical decomposition, and 

NOx emission reductions will not be achieved. If the temperature is too low, the ammonia will not react 

with NOx without a catalyst, and again, NOx emissions will not be reduced. To achieve effective SNCR 

performance, multiple ammonia injection points at the proper temperature windows are required to 

thoroughly mix the reagent in the boiler furnace. The limiting factor for an SNCR system is the ability to 

contact the NOx with the reagent without excessive ammonia slip, and without excessive ammonia 

decomposition before the NOx can be reduced. Because of the poor reaction kinetics of SNCR, higher 

levels of ammonia injection are required for SNCR systems as compared to SCR systems. The SNCR 

processes typically requires three or four times as much reagent as SCR systems to achieve similar NOx

reductions, and SNCR cannot achieve NOx reduction efficiencies as high as SCR systems. 

As noted by the U.S. EPA, certain boiler types are more suited for SNCR due to the combustion unit 

design. Boilers with furnace exit temperatures of 1550°F to 1950°F, residence times of greater than one 

second, and high levels of uncontrolled NOx are good candidates5

. SNCR has been widely used in 

fluidized bed boilers where the high alkaline ash loading of the CFB boilers makes ‘high dust’ SCR 

systems technically infeasible.6

 Therefore, SNCR is a technically feasible control option for this biomassfired boiler. 

 

4

 From the U.S. EPA document Compilation of Air Pollutant Emission Factors, AP-42, page 1.1-9. 

5

 From the U.S. EPA document EPA-452/F-03-031, Air Pollution Control Technology Fact Sheet, Selective NonCatalytic Reduction, available at http://www.epa.gov/ttn/catc/dir1/fsncr.pdf. 6

 Examples include the AES Puerto Rico facility, the Reliant Energy Seward Plant, the JEA Northside Units 1 

and 2, the Kentucky Mountain Power project, and the East Kentucky Spurlock plant. 
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4.3.11 Catalytic Absorption/Oxidation (SCONOxTM) 

SCONOxTM is a control technology that has been applied in combustion turbine and industrial 

applications. However, this technology has never been demonstrated on solid fuel-fired boilers. ABB 

Alstom Power purchased a proprietary technology called SCONOxTM from Goal Line Environmental 

Technologies. A SCONOx system has been in operation since December of 1996 on the 30 MW Sun 

Law Energy Federal cogeneration plant in Vernon, California. Since August of 1999, SCONOx has been 

in operation on a 5 MW cogeneration plant at Genetics Institute in Andover, Massachusetts. ABB 

Alstom Power subsequently completed design of a scaled-up SCONOx system for 100 MW and greater 

combined cycle gas turbines. 

The SCONOx system is based on a proprietary catalytic oxidation and absorption technology. In 

operation, NO and CO are first oxidized to NO2 and CO2. Next, NO2 is adsorbed onto an adsorption 

media. When the media is saturated, NO2 is desorbed and treated by the proprietary catalyst. Because the 

operation of SCONOx to oxidize CO to CO2 is identical to the simple use of an oxidation catalyst, there is 

effectively no difference between SCONOx and an oxidation catalyst in terms of CO and VOC control. 

Therefore, SCONOx and an oxidation catalyst are effectively the same technology for controlling CO and 

VOC emissions. 

To date, SCONOx has only been installed on small scale natural gas-fired combustion turbines. 

Therefore, this technology is not technically feasible for solid fuel and biomass-fired boilers. 

4.3.12 Emerging Control Technologies. 

Emerging technologies to reduce NOx emissions include Enviroscrub, Powerspan’s Electro-Catalytic 

Oxidation (ECOTM) scrubber, and the NOxStar and Cascade processes. Enviroscrub and ECO are 

emerging technologies with the potential to reduce NOx emissions and potentially other pollutants as well. 

However, these technologies are either not yet commercially available or are not proven with a long term 

demonstrated level of performance. The most advanced process is the ECO system. ECOTM is an 

emerging post-combustion multi-pollutant control technology including NOX control and has 

demonstrated performance, reliability and economics through testing at a pilot plant. However, no full 

size commercial scale ECOTM systems have been installed or operated. 

Enhanced and hybrid SNCR and SCR systems that are emerging NOx control technologies include 

NOxStar and Cascade. NOxStar is a hydrocarbon enhanced SNCR system that injects hydrocarbons 

downstream of an SNCR system to produce radicals that will further reduce NOx emissions. The Cascade 

process is a hybrid combination of SNCR and SCR systems. A small section of expanded ductwork 

holding SCR catalyst is located downstream of an SNCR system to reduce NOx emissions to levels that 

potentially could be comparable with full size SCR systems. This system does not require the significant 

capital investment or installation space of a full size SCR system. Neither of these systems has 

demonstrated long term levels of performance, and neither of them has been demonstrated on a full scale 

boiler. Due to lack of experience and a proven record of commercial operation, these emerging control 

technologies are not technically feasible for NOx control for this boiler. 
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4.3.13 Summary of the Technically Feasible Controls. 

Table 4-2 is a summary of the technical feasibility of the NOx controls for the biomass-fired boiler. 

TABLE 4-2. Summary of the technical feasibility of retrofit NOx control technologies. 

Technology Technical 

Feasibility 

Low NOx Burners (LNB) No Cannot be applied to fluidized bed boilers. 

Overfire Air (OFA) Yes OFA is an inherent design feature of all 

fluidized bed boilers. 

Flue Gas Recirculation (FGR) No FGR is not technically feasible for fluidized bed 

boilers. 

Oxygen Enhanced Combustion No Never applied to a fluidized bed boiler. 

Natural Gas or Coal Reburn No Never applied to a fluidized bed boiler. 

Selective Non-Catalytic 

Reduction (SNCR) Yes SNCR is commonly used on fluidized bed 

boilers. 

Selective Catalytic Reduction 

(SCR) – High Dust Arrangement No High dust SCR has not been used on a fluidized bed boilers. 

Selective Catalytic Reduction 

(SCR) – Low Dust Arrangement Yes Standard catalyst with gas reheat is technically feasible. Low temperature catalyst is infeasible. 
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4.4 STEP 3. Rank the Technically Feasible Control Technologies. 

4.4.1 Circulating Fluidized Bed Boiler. 

A circulating fluidized bed boiler has inherently low NOx emissions. Based on vendor information, the 

NOx emission rate from this advanced fluidized bed boiler firing biomass without post combustion 

controls will be 0.15 lb/mmBtu. This “uncontrolled” NOx emission rate is 30 – 50% less than the 

uncontrolled NOx emission rate for stoker boilers firing biomass fuels. 

4.4.2 Selective Catalytic Reduction (SCR). 

Tailgas SCR systems can be designed for control efficiencies of 90%. However, SCR cannot be expected 

to achieve this high level of control on a continuous basis, especially on a CFB boiler which already has 

low uncontrolled NOx emissions. For this CFB boiler, a tailgas SCR system is expected to achieve a NOx

emission rate of 0.06 lb/mmBtu, equal to an 60% reduction from the uncontrolled boiler emission rate. 

4.4.3 Selective Non-Catalytic Reduction (SNCR). 

As noted above, the U.S. EPA estimates SNCR control efficiencies of 25 – 40%. This control range is 

supported by other more recent EPA analyses. For example, in the U.S. EPA’s Updates to EPA Base 

Case 2009 ARRA Using the Integrated Planning Model (IPM)- Addendum, EPA provides estimated 

capital and annual operating costs for SNCR design removal efficiencies of 35% and 50%. It is important 

to note that the SNCR effectiveness can be reduced dramatically during low load operation of CFB 

boilers. The typical CFB bed temperature ranges from 1,500 – 1,650 o

F. At low loads, the fluidized bed 

temperature can approach or drop below the minimum SNCR operating temperature of approximately 

1,600 o

F. For this CFB boiler, SNCR is expected to reduce NOx emissions by 33% to 0.10 lb/mmBtu. 

Table 4-3 is a summary of the ranking of the technically feasible NOx control technologies for the 

proposed CSHP biomass-fired boilers. 

 

TABLE 4-3. Ranking of the technically feasible NOx control technologies for the biomass boiler. 

Control System Expected Emission Rate, 

lb/mmBtu 

Circulating Fluidized Bed Boiler with 

Tailgas or Regenerative Selective Catalytic Reduction (SCR) 0.06 

Circulating Fluidized Bed Boiler with 

Selective Non-Catalytic Reduction (SNCR) 0.10 

Circulating Fluidized Bed Boiler with 

Good Combustion Practices 0.15 
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4.5 STEP 4. Evaluate the Most Effective Controls 

4.5.1 Rank No. 1: Selective Catalytic Reduction. 

Environmental and Energy Impacts. 

The use of a tail gas SCR can achieve a NOx emission rate of 0.06 lb/mmBtu for this biomass-fired boiler. 

Based on a capacity factor of 88% and the resulting uncontrolled emissions, a SCR system could reduce 

NOx emissions from this boiler by 278 tons per year, (from 463 to 185 tons per year). 

Although the use of a tailgas SCR system can achieve very low NOx emission rates, SCR would have 

other adverse environmental and energy impacts. First, SCR can have significant environmental impacts 

related to the on site handling and storage of ammonia. 

In addition, ammonia slip emissions from the operation of even a state-of-the-art SCR system would 

result in direct emissions of ammonia and ammonium nitrate. Ammonia released to the atmosphere will 

react with sulfate in the atmosphere to form ammonium sulfate. Together, ammonium sulfate and 

ammonium nitrate are sources of regional haze and PM2.5. Because the only feasible SCR control option 

is a tailgas system, there is no possibility of controlling ammonia slip emissions. Typical levels of 

ammonia slip are expected to be as much as 10 ppmv, equal to an emission rate of 0.0059 lb/mmBtu: 

 E = ChKF (20.9) 

 20.9- %O2

where, E = NH3 Emission rate, lb/mmBtu 

Ch = NH3 concentration = 10 ppmdv 

F = dscf/mmBtu = 9,780 dscf/mmBtu 

 %O2 = Oxygen concentration = 5.0% 

K = 4.61 x 10-8 lb/dscf-ppm NH3 

Energy impacts from the application of the technology would include an electricity penalty from the 

increase in pressure drop across the system. In addition, the tailgas SCR system would require flue gas 

reheat. From Attachment 1, the reheat requirement would consume 38 million cubic feet per year of 

natural gas, or a total annual natural gas heat input of 40,000 mmBtu per year. This is enough natural gas 

to heat approximately 300 homes each year. In addition, the combustion of this natural gas would result in 

non-renewable CO2 emissions of 2,200 tons per year. 

Economic Impacts. 

The costs for SCR on this boiler will include capital costs for the SCR and ancillary equipment. Included 

in the capital costs would be the costs for an air to air heater to preheat the flue gas with the heated gases 

leaving the SCR system. In addition, an SCR system will have substantial operating costs, including 

reagent (ammonia) costs, natural gas reheating costs, labor, auxiliary power requirements, catalyst 
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replacement costs, maintenance costs, and administrative costs. The natural gas costs required to reheat 

the flue gas, based on 2010, natural gas costs, is $190,000 per year. 

Table 4-4 includes a summary of the SCR costs and the estimate of control costs. A detailed cost 

analysis is included in Attachment 1. The SCR system is expected to have a total capital cost of $14.2 

million, an annual O&M cost of $1.3 million, and a total annual cost of $2.9 million. From Table 4-4, the 

tailgas SCR system would reduce NOx emissions by 278 tons per year at an annual capacity factor of 

88%. This results in an average cost effectiveness for the tailgas SCR system of $10,300 per ton of NOx

controlled. 

In addition, the use of an SCR system would have an increased incremental cost of $1.8 million per year 

as compared to the use of SNCR. The SCR system would reduce NOx emissions by 123 tons per year as 

compared to the use of SNCR. This would result in an incremental cost effectiveness of SCR, as 

compared to SNCR, of $14,960 per ton of NOx controlled. 

Conclusions. 

The use of a tail gas SCR can achieve NOx emission rates of 0.06 lb/mmBtu for this biomass-fired boiler. 

Based on an actual annual capacity factor of 88%, and the resulting uncontrolled emissions from the CFB 

boiler, the SCR system could reduce NOx emissions by 278 tons per year (from 463 to 185 tons per year). 

However, the use of SCR would have other adverse environmental, energy, and economic impacts. The 

tailgas SCR system would also consume 38 million cubic feet per year of natural gas, or a total annual 

natural gas heat input of 40,000 mmBtu per year. This is enough natural gas to heat approximately 300 

homes each year. In addition, the combustion of this natural gas would result in non-renewable CO2

emissions of 2,200 tons per year.. The use of a tailgas SCR system would also have significant economic 

impacts. The tailgas SCR system would have a total capital cost of $14.2 million, a total annual cost of 

$2.9 million, and an average cost effectiveness of $10,300 per ton of NOx controlled. Based on the high 

costs for a tail gas SCR system, tailgas SCR is not an economically feasible control technology for this 

biomass-fired boiler. 

Because of the significant, adverse economic and environmental impacts, SCR does not represent BACT 

for this biomass fuels-fired CFB boiler. 
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TABLE 4-4. Cost effectiveness of the NOx control technology options for the biomass-fired boiler. 

Parameter Tailgas SCR SNCR CFB Boiler 

Only 

Control Efficiency 60% 33% 0% 

Controlled Emission Rate, lb/mmBtu 0.06 0.10 0.15 

Total Boiler Heat Input, mmBtu 800 800 800 

Actual Annual Capacity Factor, % 88% 88% 88% 

Actual NOx Emissions, tons per year 185 308 463 

Total Capital Requirement, $ $14,273,400 $4,500,000 $0 

Capital Recovery Factor (CRF) 0.1098 0.1098 0.1098 

Annual Capital Cost, $/yr $1,567,100 $494,100 n/a 

Annual O&M Cost, $/yr $1,292,100 $519,900 n/a 

Total Annual Cost, $/yr $2,859,200 $1,014,000 $0 

Average Annual Cost, $/yr $2,859,200 $1,014,000 

Average NOx Reduction, tons per year 278 154 

Average Cost per Ton Reduced, $ per ton $10,300 $6,580 

Incremental Annual Cost, $/yr $1,845,200 

Incremental NOx Reduction, tons per year 123 

Incremental Cost per Ton Reduced, $ per ton $14,960 

Footnotes 

1. "Annual Capital Cost" is calculated by multiplying the capital recovery factor (CRF) by the Total Capital 

Requirement as detailed in the U.S. EPA's Air Pollution Control Cost Manual – 6th Edition (EPA 452/B-02-001): 

where: 

 i = annual interest rate = 7.0% 

 n = project life, years = 15 

2. The total annual cost is the sum of the annual capital costs and annual O&M costs. 

3. "Average Reduction" is the emissions of the uncontrolled boiler minus the emissions of the control option. 

4. "Average Cost per Ton Reduced" is the Average Annual Cost of the control option divided by the Average PM 

reduction of the control option: 

Control option annual cost Average Cost Effectiveness ($ per ton removed) = Baseline emission rate – Control option emissions rate 

5. "Incremental Annual Cost" is the Total Annual Cost of the control option minus the Total Annual Cost of the 

next most effective control option. 

6. "Incremental Reduction" is the Potential Emission Rate of the next most effective control option minus the 

Potential Emission Rate of the control option. 

7. "Incremental Cost per Ton Reduced" is the Incremental Annual Cost of the control option divided by the 

Incremental PM reduction of the control option: 

 Control option annual cost – Next control option annual cost Incremental Cost ($ per ton removed) = Next control option emission rate – Control option emissions rate 

[ ] (1 ) 1

(1 )

+ −

+ = n

n

i

i i CRF
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4.5.2 Rank No. 2: Selective Non-Catalytic Reduction. 

Environmental and Energy Impacts. 

The use of a circulating fluidized bed boiler with inherently low NOx emissions combined with SNCR can 

achieve NOx emission rates of 0.10 lb/mmBtu for the biomass-fired boiler. Based on a capacity factor of 

88% and the resulting uncontrolled emissions, the use of SNCR could reduce NOx emissions by 154 tons 

per year (from 463 to 308 tons per year). 

As with SCR, the use of SNCR may have environmental impacts related to the on-site handling and 

storage of ammonia. In addition, the use of ammonia would result in ammonia slip emissions which 

would result in direct emissions of ammonia and ammonium nitrate. However, while SNCR requires 

higher levels of ammonia injection to achieve NOx reductions than does an SCR system, the point of 

injection for the SNCR system is before the fabric filter baghouse. Therefore, ammonia slip emissions are 

reduced by reactions with flyash in the fabric filter baghouse. 

Economic Impacts. 

The costs for SNCR on this boiler will include the capital costs for the SNCR system, and operational 

costs. These costs are summarized in Table 4-4. The use of SNCR is expected to have a total capital cost 

of $4.5 million, annual O&M costs of $494,000, and a total annual cost of $1,014,000. The annual capital 

cost is based only on the ammonia reagent costs. From Table 4-4, SNCR would reduce NOx emissions by 

154 tons per year at an 88% annual capacity factor. This results in an average cost effectiveness for 

SNCR of $6,580 per ton of NOx controlled. 

Conclusions. 

The use of a circulating fluidized bed boiler with inherently low NOx emissions combined with SNCR can 

achieve NOx emission rates of 0.10 lb/mmBtu for the biomass-fired boiler. Based on a capacity factor of 

88% and the resulting uncontrolled emissions, the use of SNCR could reduce NOx emissions by 154 tons 

per year. However, as with SCR, the use of SNCR may have environmental impacts related direct 

emissions of ammonia and ammonium nitrate. The use of SNCR would also have significant economic 

impacts. SNCR would have a total annual cost of $1,014,000 and an average cost effectiveness of $6,580 

per ton of NOx controlled. Although this is a high cost, We Energies considers this cost to be achievable. 
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4.6 STEP 5. Proposed Nitrogen Oxide BACT Determination. 

Based on this analysis, We Energies has concluded that the use of a circulating fluidized bed boiler with 

inherently low NOx emissions combined with selective non-catalytic reduction (SNCR) is the best 

available control technology (BACT) for NOx emissions from the biomass fuels-fired boiler. Based on 

this analysis, We Energies proposes the following limits as BACT for the control of NOx emissions from 

the biomass fuels-fired CFB boiler. 

(1) Nitrogen oxide (NOx) emissions from the biomass fuels-fired CFB 

boiler B01 shall be controlled using a circulating fluidized bed boiler 

and selective non-catalytic reduction as the best available control 

technology. 

(2) Nitrogen oxide (NOx) emissions may not exceed 0.10 pounds per 

million Btu of heat input, excluding periods of boiler startup and shut 

down, averaged over any consecutive 30-day period. 

(3) Nitrogen oxide (NOx) emissions may not exceed 0.10 pounds per 

million Btu of heat input, for all periods, including periods of boiler 

startup and shut down, averaged over any consecutive 12-month period. 

(4) Nitrogen oxide (NOx) emissions from the biomass-fired boiler B01 

shall be continuously monitored and recorded using a continuous 

emissions monitoring system meeting the requirements of 40 CFR Part 

60 Appendix B, and NR 439.06(4), Wis. Adm. Code. 

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Chapter 5. Particulate Matter and PM10

Control Technology Review. 

Particulate matter (PM) emissions from solid fuel-fired boilers originate from ash in the fuel, non 

combustible material in the limestone, from products of incomplete combustion, and from the reaction 

products in flue gas desulfurization systems. In Wisconsin, “particulate matter emissions” are defined 

under NR 400.02(119), Wis. Adm. Code, as: 

(119) “Particulate matter emissions” means all finely divided solid or liquid material, other than 

uncombined water, emitted to the ambient air as measured by an applicable reference method or 

an equivalent or alternative method specified by the department. 

Based on this definition, PM may be solid or liquid materials. PM which exists as a solid or liquid at 

temperatures of approximately 250 o

F are measured using U.S. EPA’s Reference Method (RM) 5, and are 

referred to as “front half” emissions. Particulate matter which exists as a solid or liquid at the lower 

temperature of 32 o

F are measured using U.S. EPA’s RM 202, and is commonly referred to as “back half” 

or “condensable” PM. Condensable PM may include acid gases, volatile organic compounds (VOC) and 

other materials, but by definition does not include condensed water vapor. Because of these different 

temperatures at which PM emissions are measured, the amount of PM measured from a source will 

depend upon the reference methods used. 

The measurement of particulate matter under the Standards of Performance for New Stationary Sources, 

40 CFR § 60.50Da(b)(2), and NR 440.20(8)(b)2. require the use of only Reference Method 5 for facilities 

without wet FGD systems or a variation of this method, Method 5B, for facilities with wet FGD systems. 

This is the method required by many states which have approved coal-fired boilers listed in the RBLC. 

However, Wisconsin requires the use of both Reference Methods 5 and Reference Method 202 for 

demonstrating compliance with PM emission limits. Since the federal NSPS standards and many states 

require only Reference Method 5 (or 5B) for demonstrating compliance, the direct comparison of 

emission limits required in other states is not always appropriate. In other words, an emission limit 

requiring both Reference Methods 5 and 202 would be more stringent than an equivalent limit that 

requires only Reference Method 5. 

5.1 Reference Method 202 and Artifact Formation. 

The measurement of PM using RM 202 is further complicated by the well documented problem of 

particulate matter formation in the sample train. The intimate contact of water with flue gas in the sample 

train as shown in the following figure can actually create sulfate, nitrate, and silica “artifacts” by 

converting gaseous pollutants to solids or liquids in the sampling equipment. This phenomenon creates 

condensable particulate matter in the sample train and results in a positive bias indicating more 
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condensable PM than is actually emitted. In developing Reference Method 202, the U.S. EPA recognized 

the potential for artifact formation due to the oxidation of SO2 to SO3 in the sampling equipment7

. To 

address this issue, Method 202 includes a post-test nitrogen (N2) purge for sources emitting SO2. This 

procedure is intended to remove dissolved SO2 from the sample before it can react to form sulfuric acid. 

Unfortunately, as the referenced papers indicate, this procedure is not effective in removing dissolved SO2. 

FIGURE 5-1. Reference Method 5 and Method 202 sample train. 

To Vacuum 

Pump and 

Gas Meter

Stack and Flue 

Gas Flow

Heated Area: 

250 - 300 F

Reference Method 5 

Glass Filter Holder

Impingers in Ice Bath Heated, Glass 

Lined Probe

Sampling

Nozzle

Water in Impingers and 

Method 202 Sample

Temperature 

Sensor

Check Valve

RTP Environmental Associates, Inc.

Reference Method 202 involves evaporating the collected material, mostly water, to a constant end weight. 

However, the procedure recognizes that a constant end weight may not be possible if sulfuric acid is present. 

Since sulfuric acid is hydroscopic, the sample will begin to increase in weight as soon as the sample is taken 

from a dryer into a room with ambient moisture. As a result, Method 202 includes a procedure for titrating 

 

7

 Technical papers published regarding this problem including the following: 

A. D. Williamson and K. W. Baughman, Southern Research Institute, Study of Chemical Species Formed in 

Method 202 Sampling at a Coal Fired Power Plant, Final Report, February 18, 1992. 

E. J. Filadelfia (Carnot) and M. D. McDannel (Fossil Energy Research Corporation), Evaluation of False 

Positive Interference’s Associated with the Use of EPA Method 202, Presented at the 89th Annual Meeting of 

the Air & Waste Management Association, June 23-29, 1996. 

B. Nott, Electric Power Research Institute, Measurement of Condensable Particulate Matter, TR-111327, Final 

Report, September, 1998. 

L. A. Corio (Versar, Inc) and J. Sherwell (Maryland Dept. of Natural Resources), In-Stack Condensable 

Particulate Matter Measurements and Issues, Journal of the Air & Waste Management Assn., February, 2000. 

Other papers include DeWees et al., 1989, US EPA, 1996, and Wien et al., 2001. 
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the sample with ammonium hydroxide to convert the sulfuric acid to ammonium sulfate. Paragraph 5.3.2.4 

specifies procedures for the analysis of sulfate in the sample for purposes of determining the weight of 

ammonium ion (NH4

+

) that must be subtracted to account for the added substance. Unfortunately, Method 

202 does not include any other methods or procedures for preventing artifact formation, nor does it 

include any procedures for quantifying artifacts and subtracting that amount from the total. 

5.2 Other Test Method 28. 

To address these concerns, on April 15, 2009, the U.S. EPA approved Other Method 28, Dry Impinger 

Method For Determining Condensable Particulate Emissions From Stationary Sources. The modified 

sample train is shown in Figure 4-2. This sample train avoids the intimate contact of water with flue gas 

in the impingers, reducing formation of artifact formation in the sampling train. 

FIGURE 5-2. Reference Method 5 and Other Method 28 sample train. 

To Vacuum 

Pump and 

Gas Meter

Stack and Flue 

Gas Flow

Heated Area: 

250 - 300 F

Reference Method 5 

Glass Filter Holder

Impingers in 

Ice Bath

Heated, Glass 

Lined Probe

Sampling

Nozzle

Empty Impingers

Temperature 

Sensor

Check Valve Condenser CPM Filter

Recirculating 

Pump

RTP Environmental Associates, Inc.

5.3 Particulate Matter and PM10

Particulate matter emissions may also be defined by particle size. Often particulate matter emissions are 

referred to as PM which includes all sizes of particulate matter emissions. Particulate matter less than 10 

microns in diameter is called PM10 and include condensable PM by definition. To address this, some 

permits have established a PM limit that does not include condensable material (i.e., filterable PM only), 

and a PM10 limit, significantly larger than the PM limit, that includes both the filterable and condensable 

matter. Many permit emission limits have begun to specify whether or not the emission limit includes 

condensable particulate. Where the limit does include condensable particulate, the emission limits have 

risen in recent years to recognize the contribution of both the filterable and condensable portion of the 

particulate. 
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More is being learned as test results using Method 202 become available from boilers required to meet 

very stringent emission limits using Method 202. As information has been gathered and analyzed 

regarding the contribution of condensable material, the emission limits have either increased, or two 

limits have been required; one for filterable and one for combined filterable plus condensable PM10. 

5.4 Basis for Evaluating PM Limits. 

Based on the above discussion, PM emissions will be evaluated based on the following convention: 

PM Emissions will refer to only front half or filterable PM emissions measured in 

accordance with U.S. EPA Reference Method 5 or 5B. 

PM10 Emissions will refer to both front half or filterable PM emissions measured 

in accordance with U.S. EPA Reference Method 5 or 5B, in combination 

with back half or condensable emissions measured in accordance with U.S. 

EPA Reference Method 202 or other approved method. 

5.5 BACT Baseline. 

The proposed new biomass fuels-fired CFB boiler will be subject to the Standards of Performance for 

Industrial-Commercial-Institutional Steam Generating Units under 40 CFR Part 60, Subpart Db. This 

subpart applies to steam generating units that commence construction, modification, or reconstruction 

after June 19, 1984, and that has a heat input capacity from fuels combusted in the steam generating unit 

greater than 100 mmBtu/hr. The current Subpart Db rules for PM emissions were published in the 

Federal Register June 13, 2007. Under 40 CFR § 60.43b(h)(4), an affected facility that commences 

modification after February 28, 2005, that combusts over 30 percent wood (by heat input) on an annual 

basis, and has a maximum heat input capacity greater than 250 mmBtu/hr may not exceed a PM emission 

rate of 0.085 lb/mmBtu heat input. The PM emission standards and opacity limits under § 60.43b apply 

at all times except during periods of startup, shutdown, or malfunction. Compliance with the PM emission 

standards under § 60.43b are determined through performance testing using Reference Method 5, 5B, or 

17. Note that this standard does not include condensable PM emissions. 

5.6 STEP 1. Identify Potential Control Technologies. 

Table 5-1 is a summary of particulate matter BACT emission limits for both new and modified biomassfired boilers contained in the U.S. EPA’s RACT/BACT/LAER Clearinghouse. The technologies selected 

include fabric filter baghouses and electrostatic precipitators. Other controls include mechanical 

collectors such as multicyclones, and wet venturi scrubbers. Emission limits range from 0.012 to 0.10 

pounds per million Btu. From Table 5-1, the most stringent emission limit is 0.01 lb/mmBtu for the 

Yellow Pine Energy Company in Georgia. The emission limit for the South Point Biomass Generation 

facility is based on a baghouse outlet grain loading of 0.004 gr/dscf. According to the permit to install 

(condition A.V.2.), compliance with this limit is based on Method 5 of 40 CFR Part 60. 
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TABLE 5-1. Biomass-fired boiler particulate matter/PM10 BACT emission limits. 

Limit, 

Facility State lb/mmBtu Permit 

Date 

Capacity, 

mmBtu/hr 

Primary 

Fuel 

Control 

System PM PM10

Yellow Pine Energy Company GA May-09 1,529 Wood FFB 0.01 0.018 

South Point Biomass Generation OH Apr-06 318 Wood FFB 0.012 None 

Mancelona Renewable MI Nov-09 565 Wood / 

Biomass FFB 0.012 0.025 

Northern Michigan University MI Nov-09 210 Wood FFB 0.0125 0.025 

Nacogdoches Power, LLC TX Mar-07 1,374 Wood FFB 0.015 0.032 

Darrington Energy Cogeneration 

Power Plant WA Feb-05 403 Wood / 

Bark ESP None 0.02 

Skagit County Lumber Mill WA Jan-06 430 Wood / 

Bark ESP None 0.02 

Fibrominn Biomass Power Plant MN Feb-05 792 Poultry 

Litter FFB 0.02 Test2

Pub Service of New Hampshire - 

Schiller Station NH Oct-04 720 Wood FFB 0.025 None 

Virginia PWC - Laurention Energy 

Authority MN Aug-05 230 Wood ESP 0.025 0.025 

Hillman Power MI Jul-02 300 Wood / 

TDF ESP 0.026 None 

District Energy St. Paul, Inc. MN Nov-01 550 Wood ESP 0.03 0.03 

S.D. Warren Co. - Skowhegan, Me ME Nov-01 1,300 Wood ESP 0.03 

Boralex Stratton Energy, LP ME 672 Wood ESP 0.03 

Wheelabrator Sherman Energy 

Company ME Apr-99 315 Wood ESP 0.036 

Koda Energy MN Aug-07 308 Wood / 

NG ESP 0.037 0.01 

Stoneman Power Plant WI Jan-09 340 Wood ESP 0.06 0.06 

Northern Sun ND May-06 100 Wood / 

Hulls ESP 0.08 

Meadwestvaco Kentucky, 

Inc/Wickliffe KY Feb-02 631 Wood ESP 0.10 

Footnotes 

1. The first limit is for PM or front half emissions; the second limit is for total PM10 emissions or the combined 

front and backhalf emissions. Note that many permits only specify the front half emissions. 

2. For the Fibrominn biomass-fired boiler, the permit requires the permittee to conduct performance tests for total 

condensable PM emissions and propose a limit based on the test results. 
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5.7 STEP 2. Identify Technically Feasible Control Technologies. 

As noted above, data from the U.S. EPA’s RBLC indicate that the technologies selected as BACT include 

primarily fabric filter baghouses and electrostatic precipitators. Other controls include mechanical 

collectors such as multicyclones, and wet venturi scrubbers. 

5.7.1 Fabric Filter Baghouses. 

A fabric filter baghouse (FFB) separates dry particles from the boiler flue gas by filtering the flue gas 

through fabric filters or “bags”. The components of a FFB include the fabric filters, a tube sheet to 

support the bags, a gas-tight enclosure, a mechanism to clean accumulated PM from the bags, and a 

hopper to collect accumulated ash. Baghouses are compartmentalized to facilitate cleaning and to provide 

for maintenance and repair. When the pressure drop across a compartment increases to a specified limit, 

the accumulated PM is removed by placing that compartment in the cleaning mode. 

PM laden flue gas enters the FFB and passes through the bags. As the flue gas flows through the fabric 

filter, a layer of collected material, called the “filter cake”, builds up on the fabric. In an FFB, the 

primary filtering media is actually the filter cake rather than the fabric itself. The filter cake acts much 

like a fixed-bed reactor, contributing to greater absorption of pollutants, including sulfur dioxide (SO2), 

sulfuric acid mist, mercury and hazardous air pollutants including hydrogen chloride (HCl) and hydrogen 

fluoride (HF). A depiction of the mechanism for particulate removal is shown in Figure 5-3. 

FIGURE 5-3. Depiction of the flue gas flow through the fabric filter baghouse filter cake showing 

the mechanism for particulate collection. 

Dust Laden 

Flue Gas

Cleaned Flue Gas 

to Atmosphere

Bag Fabric Layer of Collected 

Ash or "Filter Cake"

RTP Environmental Associates, Inc.
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FFB have several methods for cleaning, including reverse gas (RGFFB), reverse air with mechanical 

shakers, and pulse jet (PJFFB). In a RGFFB, the fly ash is collected on the inside of the bags. Each 

compartment of a RGFFB is periodically taken out of service for cleaning by circulating clean flue gas 

from the outlet plenum backward through the offline compartment. This dislodges the collected dust, 

which falls into hoppers. In a PJFFB, the fly ash is collected on the outside of the bags. Cleaning is 

normally accomplished on line by directing a pulse of air backward through the bag. The air pulse 

dislodges the fly ash, which falls into hoppers. 

A PJFFB can operate at higher air-to-cloth ratios than a reverse gas system. This means that a PJFFB can 

be smaller and therefore usually has lower capital costs than a RGFFB. However, because the pulse jet 

cleaning method is more aggressive than in the RGFFB, the bags in a RGFFB may have a longer service 

life. 

FFBs have several advantages when used for PM control from coal-fired boilers, including: 

• High particulate matter control efficiencies. 

• Relatively constant outlet grain loading over the entire boiler load range. 

• Simple operation and maintenance. 

The primary disadvantage of fabric filter baghouses is the relatively high pressure drop across the 

baghouse as compared to a dry ESP and the resulting increased fan power requirements. 

5.7.2 Dry Electrostatic Precipitators. 

Electrostatic precipitators (ESP) are a common PM control system for both coal and biomass-fired 

boilers. An ESP uses a large enclosure to slow the gas stream, which allows more time to electrostatically 

charge particulates and collect them in the ESP. An ESP is arranged in a series of fields which consist of 

negatively charged discharge electrodes and positively charged collection plates. The discharge 

electrodes impart a negative charge to particles in the gas stream. The negatively charged particles then 

migrate to the larger positively charged plates. PM collected on the plates is periodically removed by 

rapping the plate. Most of the PM knocked off the plates falls into collection hoppers for removal. A 

portion of the collected PM is re-entrained in the gas stream during rapping. This re-entrained PM is 

normally collected in subsequent sections of the ESP. 

ESP’s may be located either upstream of the air heater (hot-side ESP) or downstream of the air heater 

(cold-side ESP). The location is selected to achieve the best PM resistivity8

 conditions. Most modern 

ESPs are cold-side ESPs. 

 

8

 Gas composition and temperature and particle composition all influence resistivity, which is a measure 

of the ability of a particle to retain an electrostatic charge. The ability to collect particles using 

electrostatic attraction is directly related to particle resistivity. If the particle resistivity is outside the 

design range, particle collection efficiency is reduced. 
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Factors affecting the PM collection efficiency of an ESP include flue gas flow rate through the ESP, total 

plate area, PM resistivity, voltage, and the sectionalization of the ESP. The smaller the collection area of 

the ESP, the narrower the acceptable resistivity range becomes. To optimize particulate resistivity and 

maximize collection efficiency, many ESPs utilize a sulfur trioxide (SO3) injection system to condition 

the ash and reduce particulate resistivity. In addition, modern ESP controls allow the ESP operation to be 

optimized to maximize PM control through overall ESP performance management, power optimization, 

and programmed cleaning cycles. Finally, good sectionalization of the ESP is important to maximize 

ESP performance and reliability. 

5.7.3 Wet Electrostatic Precipitators. 

The principle of operation of a wet ESP is similar to a dry ESP. Particulate matter in the flue gas is 

exposed to an electric field which induces a charge on the particle which is then drawn to an oppositely 

charged collection electrode. However, in a wet ESP, the flue gas is cooled below the dew point and 

consequently particulate matter may be present as either solid or liquid particles. A recent application of 

wet ESPs is downstream of a wet FGD for the control of sulfuric acid mist on large, utility scale boilers 

firing high sulfur eastern coals. In this application, the flue gas temperature is below the sulfuric acid and 

water saturation temperatures as it passes through the wet ESP. As such, water droplets and other 

condensable materials in the flue gas, including sulfuric acid, are charged and collected by the ESP plates. 

Filterable PM not entrained from the FGD system may also be collected in the wet ESP. The collection 

electrodes are either continuously or periodically flushed with water to remove collected materials. 

Although wet ESPs can be effective for removing sulfuric acid mist downstream of a wet FGD when 

firing high sulfur coals, wet ESPs cannot be used as the primary PM collection devices for biomass-fired 

boilers because the PM loading is too great for effective operation. Wet ESPs experience current 

suppression when particulate concentrations in the electrode wash water are too high which would reduce 

or eliminates the PM control effectiveness of the wet ESP. Therefore, a wet ESP must be considered as a 

secondary or “polishing” PM control device for boilers. 

5.7.4 Wet Scrubbers. 

Wet scrubbers are used in many industrial processes to control PM emissions. Wet scrubbers reduce PM 

emissions through several mechanisms, including condensation, inertial impaction of PM with water 

droplets, and reactions of PM and PM precursors with the scrubber reagent. 

5.7.5 Mechanical Collectors. 

Mechanical collectors are not as effective as a FFB or ESP for particulate matter control. Therefore, 

while mechanical collectors are a technically feasible BACT alternative, the performance of mechanical 

collectors is inferior to FFBs and ESPs. 
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5.8 STEP 3. Rank the Technically Feasible Technologies. 

All of the identified PM control technologies, including fabric filter baghouses, dry ESPs, wet ESPs, wet 

scrubbers, and mechanical collectors are technically feasible technologies. However, wet ESPs cannot be 

used as the primary control device. Therefore, wet ESPs are not considered technically feasible in this 

analysis. 

Table 5-2 is a summary of the ranking of the expected performance of the PM control technologies. The 

performance is stated in ranges, since the specific performance is dependent on the boiler firing type and 

fuels fired. In general, fabric filters are expected to have the best performance for the control of both 

filterable and especially condensable PM. 

TABLE 5-2. Ranking of the technically feasible PM control technologies for the biomass-fired 

boiler. 

Expected Performance, lb/mmBtu Rank Control System 

PM PM10

1 Fabric Filter Baghouse 0.015 0.03 

2 Dry ESP 0.02 0.035 

3 Venturi Scrubber 0.05 0.07 

4 Mechanical Collectors 0.15 0.30 

5.9 STEP 4. Evaluate the Most Effective Controls. 

5.9.1 Rank No. 1: Fabric Filter Baghouse. 

Based on the ranking summarized in Table 5-2, a fabric filter baghouse is expected to have the greatest 

potential to reduce both filterable and condensable particulate matter emissions from the biomass-fired 

Boiler B01. Based on this analysis, We Energies proposes to utilize a fabric filter baghouse for this 

boiler. Therefore, further analysis is not necessary. 
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5.10 STEP 5. Proposed Filterable Particulate Matter and PM10 BACT 

Determination. 

Based on this analysis, We Energies has concluded that the use of a fabric filter baghouse is the best 

available control technology (BACT) for particulate matter and PM10 emissions from the biomass fuelsfired CFB boiler. Based on this analysis, We Energies proposes the following limits as BACT for the 

control of particulate matter and PM10 emissions from the biomass-fired, circulating fluidized bed boiler. 

(1) Particulate matter and PM10 emissions from the biomass fuels-fired 

circulating fluidized bed boiler shall be controlled using a fabric filter 

baghouse as the best available control technology. 

(2) Particulate matter and PM10 emissions may not exceed 0.03 pounds per 

million Btu of heat input, excluding periods of startup and shut down. 

(3) Compliance with this emission limit shall be based upon the 

measurement of particulate matter emissions in accordance with U.S. 

EPA Reference Method 5, 5B, or 17, and U.S. EPA Other Method 28, or 

another method approved in writing by the department.
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Chapter 6. PM2.5 Control Technology 

Review. 

Particulate matter emissions that are less than 2.5 micrometers in diameter are known as "fine" particles, 

and are referred to as PM2.5. Various pollutants may contribute to ambient PM2.5 concentrations. Natural 

gas and biomass fuel combustion results in direct emissions of PM2.5, as well as PM2.5 “precursors”. 

PM2.5 precursors may also result in the formation of PM2.5 in the atmosphere. The U.S. EPA has 

identified SO2, NOx, organic compounds (VOCs), and ammonia (NH3) as PM2.5 precursors. These gasphase precursors undergo chemical reactions in the atmosphere to form secondary PM2.5. Direct emissions 

of PM2.5 from combustion include solid or filterable PM2.5, and condensable or back half PM2.5. 

Under the recently promulgated rules to revise the New Source Review (NSR) program in 40 CFR Part 

52 to include PM2.5, the EPA identified the following PM2.5 pollutants, and their significant levels: 

1. 10 ton per year of direct PM2.5 emissions 

2. 40 ton per year of SO2 emissions 

3. 40 ton per year of NOx emissions unless demonstrated not to be a PM2.5 precursor. 

Based on the final rules, VOC and ammonia may not be considered to be PM2.5 precursors unless the 

State demonstrates that these emissions are a significant contributor to the area PM2.5 concentrations. In 

addition, during the PM2.5 SIP development period, the EPA has indicated that NOx emissions will not be 

regulated as a PM2.5 precursor to give States the opportunity to determine whether NOx emissions are a 

significant contributor to the ambient PM2.5 problem (Fed. Reg., Friday, May 16, 2008, page 28343). 

6.1 BACT Baseline. 

There are no state implementation plan emission limits or new source performance standards for direct 

PM2.5 emissions from this biomass-fired boiler. 

Direct PM2.5 emissions from the combustion of biomass fuels include filterable PM2.5, and condensable 

PM2.5. The U.S. EPA’s Compilation of Air Pollutant Emission Factors, AP-42, 5th Edition, Table 1.1-6 

includes cumulative particle size distribution data for coal combustion. According to this table, one-half 

of the filterable PM emissions from coal-fired boilers controlled by fabric filter baghouses may be PM2.5. 

While this boiler will fire biomass fuels, this particle size distribution data for the fabric filter baghouse is 

a reasonable estimate for biomass combustion. For this analysis, all of the condensable PM emissions are 

considered PM2.5. Based on the proposed PM (filterable) and PM10 (filterable plus condensable) BACT 

emission limits of 0.015 and 0.03 lb/mmBtu, respectively, the PM2.5 emission rate would be: 

EPM2.5 = 1⁄2 x (0.015) + (0.03 – 0.015) = 0.0225 lb/mmBtu 
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6.2 STEP 1. Identify All Potential Control Technologies. 

6.2.1 Direct PM2.5 Emissions. 

For PM and PM10, the technologies selected as BACT include primarily fabric filter baghouses and 

electrostatic precipitators. Other controls include mechanical collectors such as multicyclones, and wet 

venturi scrubbers. Note that from the above analysis of direct PM2.5 emissions from this biomass-fired 

boiler, one-third of the direct PM2.5 emissions, or 0.0075 lb/mmBtu, is expected to be filterable PM2.5; the 

remaining portion of direct PM2.5 emissions, or 0.015 lb/mmBtu, is expected to be condensable PM2.5. 

6.2.2 PM2.5 Precursors. 

As noted above, the U.S. EPA has identified SO2, NOx, VOCs, and ammonia (NH3) as PM2.5 precursors. 

Based on the final rules, volatile organic compounds (VOC) and ammonia (NH3) may not be considered 

to be precursors to PM2.5 unless the State demonstrates that these emissions are a significant contributor to 

the area PM2.5 concentrations. This control technology review includes a complete control technology 

review for SO2, NOx, and VOC emissions. Therefore, further analysis of these pollutants as PM2.5

precursors is unnecessary, since BACT controls will be applied to these pollutants. 

6.3 STEP 2. Identify Technically Feasible Control Technologies. 

As noted above, data from the U.S. EPA’s RBLC indicate that the technologies selected as BACT include 

primarily fabric filter baghouses and electrostatic precipitators. Other controls include mechanical 

collectors such as multicyclones, and wet venturi scrubbers. 

6.3.1 Fabric Filter Baghouses. 

Fabric filter baghouse (FFB) were discussed in the PM/PM10 control technology review. Fabric filter 

baghouses are very effective at reducing PM emissions, especially in the fine particle size ranges. Figure 

6-1 shows the cumulative emission factor for PM emissions versus the particle size for several different 

PM control systems for coal combustion9

. Figure 6-1 shows that fabric filter baghouses are very effective 

in reducing PM emissions, especially fine PM or PM2.5. 

As noted in Chapter 5, the primary filtering media in a fabric filter baghouse, especially those using 

woven fabric filters, is actually the filter cake rather than the fabric itself. The filter cake acts much like a 

fixed-bed reactor, contributing to greater absorption of pollutants, including fine particulate matter, sulfur 

dioxide (SO2), sulfuric acid mist, mercury and hazardous air pollutants including hydrogen chloride (HCl) 

and hydrogen fluoride (HF). Since pollutants such as sulfuric acid mist, HCl, and HF directly contribute 

to condensable PM, fabric filter baghouses are also very effective at reducing the condensable portion of 

PM2.5 emissions by controlling these PM2.5 precursors in the baghouse. 

 

9

 Data is from the Air Pollution Engineering Manual, Air & Waste Management Association, coal combustion 

sources with various air pollution control systems. 
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FIGURE 6-1. Cumulative emission factor for PM emissions versus the particle size. 

0.00

0.01

0.10

1.00

10.00

100.00

0.1 1 10 100

Particle Size, um

Cummulative Emission Factor, lb/ton

Multiple Cyclones

Electrostatic 

Precipitator

Fabric Filter 

Baghouse

Filter Media for Fabric Filter Baghouses and PM2.5 Control. 

There is a wide variety of fabric filter material available for fabric filter baghouses. For reverse air 

baghouses, the most common fabric is a simple woven fabric such as woven fiberglass. For pulse jet 

baghouses, the most common fabric is a woven fabric backing called a “scrim” with a felted layer needle 

punched into the scrim. Other fabric materials include Nomex®, Ryton®, Gortex®, and Hyglass®. 

Developments have been made in fabric filter media to improve PM2.5 control. Advanced filter media 

provide enhanced PM2.5 emissions control and may be applicable to this biomass-fired boiler. The U.S. 

EPA implemented the Environmental Technology Verification (ETV) program in 1995 to generate 

independent data on the performance of innovative pollution control technologies. The ETV program 

identified baghouse filtration products as a high priority technology group in 2000. As stated in a 

report10, “New fabrics have been developed that offer the combination of highly effective particulate 

removal and low operational pressure drop. Improving performance of the fabrics can be observed in 

verification test data trends.” Completed verifications of baghouse filtration products are available from 

the U.S. EPA’s ETV program at http://www.epa.gov/nrmrl/std/etv/vt-apc.html. ETV test results indicate 

 

10 The Evolution of Improved Baghouse Filter Media as Observed in the Environmental Technology 

Verification Program, Andrew Trenholm, RTI International, John Mycock, ETS Inc., John McKenna, ETS Inc., 

and Michael Kosusko, U.S. EPA, Presented at the Air & Waste Management Association Annual Conference, June, 

2008, available at: http://epa.gov/etv/pubs/600etv08023.pdf . 
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filter media with direct PM2.5 emission levels as low as 0.000007 gr/dscf, equal to approximately 0.0001 

lb/mmBtu. Note, however, that this is the tested performance for the filter media, not for the entire 

baghouse system. Leaks which occur in even the best state-of-the-art baghouse will increase the outlet 

grain loading, even when using advanced filter media. 

Baghouse filtration product enhancements include felted bags and high efficiency microfiber felts, 

intrinsically coated (IC) bags, membrane bags, and electrostatic fabric filter technology. 

Felted bags are often used in pulse-jet fabric filter baghouses which use higher energy cleaning systems 

than in a reverse air baghouse. Felted filters don’t require the initial filter cake to collect fine particulates 

as compared to woven filters. Felted filters are generally 2 to 3 times thicker than woven filters. This 

thicker overall filter improves fine particle collection, since each individual randomly oriented fiber acts 

as a target for particle capture by impaction and interception. Small particles are collected on the outer 

surface of the filter, rather than depending on the filter cake to achieve fine particle control. Figure 6-2 is 

a depiction of the fabric filter media filtration process for a simple woven fabric as compared to a felted 

fabric media. 

High efficiency microfiber felts are based on the same concept as felted filter media, but use ultra-fine 

fibers to enhance fine particulate matter control. The U.S. EPA’s ETV program tested outlet PM2.5 levels 

as low as 0.0004 gr/dscf (0.00055 lb/mmBtu). 

FIGURE 6-2. Depiction of the fabric filter media filtration process for a simple woven fabric as 

compared to a felted fabric media. 

From the U.S. EPA’s Air Pollution Training Institute (APTI) Course Fabric Filter Operation. 
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Intrinsically coated bags use a fabric made of coated fibers. The coating is typically Teflon® or a 

similar fluoro-polymer material. Intrinsically coated bags improve bag durability and also reduce the pore 

size between fibers, improving direct PM2.5 control. However, this coating also inhibits filter cake 

formation. While this can help reduce the pressure drop across the baghouse, the reduced filter cake 

accumulation may reduce the control effectiveness of the fabric filter baghouse for PM2.5 precursors and 

condensable PM2.5 species by limiting the contact between these precursors and solids in the filter cake 

which would otherwise remove these precursors. 

Membrane bags have a polytetrafluoroethylene (PTFE) coating such as Teflon® applied to the surface 

of the fabric rather than to the individual fibers. Membrane bags have even smaller pore sizes than 

intrinsically coated bags. This smaller pore size may further improve direct PM2.5 control. However, the 

coating over the entire bag further inhibits filter cake formation and may further reduce the control 

effectiveness of the fabric filter baghouse for PM2.5 precursors and condensable PM2.5 species by limiting 

the contact between these precursors and solids in the filter cake. 

High efficiency microfiber felts are based on the same concept as felted filter media, but use ultra-fine 

fibers to enhance fine particulate matter control. The U.S. EPA’s ETV program tested outlet PM2.5 levels 

as low as 0.0004 gr/dscf (0.00055 lb/mmBtu). 

Electrostatic fabric filter baghouses have been developed through a partnership of the U.S. EPA and 

Southern Research Institute. The technology is licensed to General Electric Energy (GE) and is marketed 

as the Max-9TM electrostatic fabric filter baghouse. The Max-9TM is a dust collection technology that 

combines discharge electrodes and fabric filters in the same casing to provide high collection efficiency 

while operating at a 60 to 80% lower system pressure drop. The Max-9 ESFF is an electrostatic 

precipitator/pulse-jet baghouse hybrid, employing high voltage discharge electrodes to charge particulate, 

but with fabric filters instead of collecting plates in the casing. GE Power states that “The Max-9 ESFF 

provides collection efficiencies an order of magnitude higher than those achieved by either the best fabric 

filters or precipitators currently on the market, with demonstrated efficiency of 99.999%.”11

GE states that the ESFFB technology is recommended for use in conjunction with a primary particulate 

control device; i.e., the Max-9 is recommended as a “polishing” control device for PM emissions. The 

U.S. EPA and the Southern Research Institute conducted pilot testing of a slip stream at a major power 

plant in the Southern United States. The pilot plant was configured to allow testing with or without 

discharge electrode energization. With the electrostatic stimulation turned on, collection efficiency 

increased from 99.99% to 99.999%, a full order of magnitude better. Plus, there was an 80% reduction in 

pressure drop, and an 80-90% reduction in sub-micron particle emissions. 

While the Max-9 ESFFB technology shows great promise, this technology has not been demonstrated on 

a full scale facility. Therefore, this technology is not technically feasible for this biomass-fired boiler. 

 

11 As stated at: http://www.gepower.com/prod_serv/products/particulate_matter/en/max9/index.htm. 
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6.3.2 Dry Electrostatic Precipitators. 

Electrostatic precipitators (ESP) are a common PM control system for both coal and biomass-fired 

boilers, and are discussed in the PM/PM10 control technology review. While dry ESPs are a technically 

feasible control technology, a dry ESP is expected to have significantly lower control efficiencies for both 

direct filterable PM2.5 emissions, and also for PM2.5 precursors. 

6.3.3 Wet Electrostatic Precipitators. 

The principle of operation of a wet ESP is similar to a dry ESP. Although wet ESPs can be effective for 

removing sulfuric acid mist downstream of a wet FGD when firing high sulfur coals, wet ESPs cannot be 

used as the primary PM control system for biomass-fired boilers because the PM loading is too great for 

effective operation. Wet ESPs experience current suppression when PM concentrations in the electrode 

wash water are too high which would reduce or eliminates the PM control effectiveness of the wet ESP. 

Therefore, a wet ESP must be considered as a secondary or “polishing” PM control device. 

While wet ESPs cannot operate as the primary control device, wet ESPs have shown promise at reducing 

PM2.5 emissions as a polishing device. A pilot wet ESP was installed at First Energy’s Bruce Mansfield 

Plant in Shippingport, PA. The pilot wet ESP uses a slipstream of flue gas from the outlet of an FGD 

system on an 835 MW unit firing 3% sulfur coal. The plant installed the pilot WESP to test for PM2.5 and 

SO3 mist removal as a potential control technology to reduce visible emissions. The slipstream results 

indicate reductions in PM2.5 emissions from 62% to 96%. These results also showed similar high SO3

mist removal, which may account for mush of the PM2.5 emission reductions. However, these tests were a 

slipstream test, not a fullscale test, and were for a limited duration. 

6.3.4 Wet Scrubbers. 

Wet scrubbers are used in many industrial processes to control PM emissions. Wet scrubbers reduce PM 

emissions through several mechanisms, including condensation, inertial impaction of PM with water 

droplets, and reactions of PM and PM precursors with the scrubber reagent. 

6.3.5 Mechanical Collectors. 

Mechanical collectors are not as effective as a FFB or ESP for PM control, especially for fine PM control. 

Therefore, while mechanical collectors are technically feasible, their performance is inferior to FFBs. 
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6.4 STEP 3. Rank the Technically Feasible Technologies. 

Fabric filter baghouses, dry ESPs, wet ESPs, wet scrubbers, and mechanical collectors are technically 

feasible technologies. While wet ESPs have shown promise at reducing PM2.5 emissions as a polishing 

device, the available data is limited. Since a wet ESP has not been demonstrated on a similar biomassfired boiler, wet ESPs are not considered technically feasible in this analysis. 

Table 6-1 is a summary of the ranking of the expected performance of the PM control technologies. The 

performance is stated in ranges, since the specific performance is dependent on the boiler firing type and 

fuels fired. In general, fabric filters are expected to have the best performance for the control of both 

filterable and especially condensable PM2.5. 

TABLE 6-1. Ranking of the technically feasible PM2.5 control technologies. 

Rank Control System Performance, 

lb/mmBtu Notes 

1 

Fabric Filter Baghouse 

with Felted Bags 

or 

Advanced Filter Media 

0.02 - 0.03 

Felted filters have a thicker filter which improves 

fine particle collection. Small particles are collected 

on the filter, rather than depending on the filter cake 

to achieve fine particle control. However, felted 

filters still allow for a normal filter cake to enhance 

control of PM2.5 precursors. 

Intrinsically coated bags and high efficiency 

microfiber bags may improve filterable PM2.5

control without significantly reducing filter cake 

accumulation and the subsequent control of PM2.5

precursors such as SO2 and sulfuric acid mist. 

Membrane coated bags are expected to achieve very 

high filterable PM2.5 control but may reduce filter 

cake accumulation which may adversely impact 

control of PM2.5 precursors such as SO2 and 

condensable PM2.5 such as sulfuric acid mist. 

2 

Fabric Filter Baghouse 

with Conventional 

Woven Bags 

0.02 – 0.04 

The expected emission range is higher because the 

standard bags will have higher filterable PM2.5

emission rates. However, the conventional bags 

have good filter cake accumulation and good control 

of PM2.5 precursors and condensable PM2.5. 

3 Dry ESP 0.03 - 0.05 Inferior control, with lower filterable and lower 

condensable PM2.5 control. 

4 Venturi Scrubber 0.05 – 0.15 Inferior control. 

5 Mechanical Collectors 0.10 – 0.30 Inferior control. 
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6.5 STEP 4. Evaluate the Most Effective Controls. 

6.5.1 Rank No. 1: Fabric Filter Baghouse with Felted or Advanced Filter Media. 

Based on the ranking summarized in Table 6-1, a fabric filter baghouse with felted filter media or 

advanced filter media bags is expected to have the greatest potential to reduce both filterable and 

condensable PM2.5 emissions from the biomass-fired boiler. Note that there is a lack of data available on 

PM2.5 emissions from biomass combustion, and there is no available information on the PM2.5 emission 

rates for different fabric filter media on a CFB boiler firing biomass fuels. With these statements made, 

the highest level of PM2.5 emission control from this biomass-fired boiler is expected to be achieved using 

felted filter media bags. Based on this analysis, the We Energies proposes to utilize a fabric filter 

baghouse with felted filter media or advanced filter media bags for this boiler. 

6.6 STEP 5. Proposed PM2.5 BACT Determination. 

Based on this analysis, We Energies has concluded that the use of a fabric filter baghouse with felted 

filter media bags is the highest ranked control technology for the control of PM2.5 emissions and 

represents the best available control technology (BACT) for PM2.5 emissions from the biomass fuels-fired 

CFB boiler. Based on this analysis, We Energies proposes the following limits as BACT for the control 

of PM2.5 emissions from this biomass-fired boiler. 

(1) PM2.5 emissions from the biomass-fired Boiler B08 shall be controlled 

using a fabric filter baghouse with felted filter media bags as the best 

available control technology. 

(2) PM2.5 emissions may not exceed 0.023 pounds per million Btu of heat 

input, excluding periods of startup and shut down. 

(3) Compliance with this PM2.5 emission limit shall be based upon the 

measurement of PM2.5 emissions in accordance with U.S. EPA Reference 

Method 201A, and U.S. EPA Other Method 28, or another method approved 

in writing by the department.
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Chapter 7. Sulfur Dioxide (SO2) Control 

Technology Review. 

Sulfur dioxide (SO2) emissions from solid fuel-fired boilers result from the oxidation of sulfur compounds 

in the fuel. During combustion, the majority of the fuel sulfur is emitted as SO2. A small portion of the 

sulfur is further oxidized to sulfur trioxide (SO3). When the flue gas temperature drops below the dew 

point temperature, sulfur trioxide is spontaneously converted to sulfuric acid (H2SO4). Therefore, control 

technologies which control SO2 emissions also reduce sulfuric acid mist emissions to varying degrees. A 

portion of the SO2 and SO3 will react with alkaline products in the ash such as calcium oxide (CaO), 

sodium oxide (Na2O), and potassium oxide (K2O) and water to form calcium sulfate or gypsum (CaSO4 •

2H2O), sodium sulfate (Na2SO4), and potassium sulfate (K2SO4). These reaction products are solids 

which are collected in the fabric filter baghouse as filterable particulate matter. These reactions are 

particularly important for biomass-fired boilers which produce highly alkaline ash. Therefore, ash in the 

boiler and in the filter cake of the fabric filter baghouse will reduce SO2 emissions. 

7.1 BACT Baseline. 

The biomass fuel-fired CFB boiler will be subject to the Standards of Performance for IndustrialCommercial-Institutional Steam Generating Units under 40 CFR Part 60, Subpart Db. This subpart 

applies to steam generating units that commence construction, modification, or reconstruction after June 

19, 1984, and that has a heat input capacity greater than 100 mmBtu/hr. 

Under 40 CFR § 60.42b(k)(1), an affected facility that commenced construction, reconstruction, or 

modification after February 28, 2005, and that combusts coal, oil, natural gas, a mixture of these fuels, or 

a mixture of these fuels with any other fuels may not exceed: 1) An SO2 emission rate of 0.20 lb/mmBtu, 

or 2) 8% of the potential SO2 emission rate (92% reduction) and 1.2 lb/mmBtu. Units firing only very 

low sulfur oil and/or a mixture of gaseous fuels such as natural gas with a potential SO2 emission rate of 

less than 0.32 lb/mmBtu are exempt from the SO2 emissions limit in 40 CFR § 60.42b(k)(1). 

Based on these NSPS limits, the baseline SO2 emission rate is 0.20 lb/mmBtu. 

7.2 STEP 1. Identify Potential Control Technologies. 

Potential sulfur dioxide (SO2) control technologies include pre-combustion controls such as low sulfur 

fuels, and post combustion controls, such as flue gas desulfurization (FGD). The following references 

were used to identify potential SO2 control technologies: “Controlling SO2 Emissions: A Review of 

Technologies (EPA-600/R-00-093, October 2000), the U.S. EPA’s RACT/BACT /LAER Clearinghouse 

(RLBC), the U.S. EPA’s National Coal-Fired Utility Projects Spreadsheet Updated July 2007, and 

numerous air permits issued by states and the U.S. EPA. 
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Table 7-1 is a summary of SO2 BACT emission limits for both new and modified biomass-fired boilers 

contained in the U.S. EPA’s RACT/BACT/LAER Clearinghouse. The technologies selected include low 

sulfur fuels, duct sorbent injection, limestone injection into fluidized bed boilers, and wet venturi 

scrubbers. Emission limits range from 0.014 to 0.80 pounds per million Btu of heat input. Available 

technologies also include wet and dry FGD systems. Note that several facilities in Table 7-1 agreed to 

“synthetic minor” limits limiting emissions below the PSD significant threshold of 40 tons per year. 

TABLE 7-1. Biomass-fired boiler sulfur dioxide (SO2) BACT emission limits. 

Facility State Permit 

Date 

Capacity, 

mmBtu/hr 

Primary 

Fuel 

Control 

System 

Limit, 

lb/mmBtu 

Yellow Pine Energy Company GA May-09 1,529 Wood / 

TDF SDA 0.014 

Hillman Power MI Jul-02 300 Wood / 

TDF None 0.018 

Mancelona Renewable MI Nov-09 565 Biomass None 0.025 

Nacogdoches Power, LLC TX Mar-07 1,374 Wood BFB 

Boiler 0.046 

Northern Michigan University MI Nov-09 210 Wood CFB 

Boiler 0.06 

Pub Service of New Hampshire - 

Schiller Station NH Oct-04 720 Wood CFB Boiler 0.02 

Skagit County Lumber Mill WA Jan-06 430 Wood 0.025 

Boralex Stratton Energy, LP ME 672 Wood 0.053 

South Point Biomass Generation OH Apr-06 318 SDA 0.07 

Fibrominn Biomass Power Plant MN Feb-05 792 Poultry 

Litter SDA 0.07 

Wheelabrator Sherman Energy 

Company ME Apr-99 315 Wood 0.12 

S.D. Warren Co. - Skowhegan, 

Me ME Nov-01 1,300 wet scrubber 0.27 

Northern Sun ND May-06 100 Wood / 

Hulls 0.47 

Meadwestvaco Kentucky, 

Inc/Wickliffe KY Feb-02 631 0.80 

Virginia PWC - Laurention 

Energy Authority MN Aug-05 230 Wood <38 TPY 

Koda Energy MN Aug-07 308 Wood / 

NG <38 TPY 

District Energy St. Paul, Inc. MN Nov-01 550 Wood <39 TPY 

Stoneman Power Plant WI Jan-09 340 Wood n/a 

Footnotes 

1. For the South Point Biomass Generation facility, the BACT limit is 22.13 pounds per hour. For a rated heat 

input capacity of 318 mmBtu per hour, this limit is equal to 0.07 lb/mmBtu. 

2. For the Public Service of New Hampshire - Schiller Station, sorbent injection into the fluidized bed boiler is 

required for coal combustion.
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7.3 STEP 2. Identify Technically Feasible Control Technologies. 

Flue Gas Desulfurization (FGD) technologies are primarily used for large utility and industrial coal-fired 

boilers. FGD systems may be broadly classified as “wet” and “dry” systems. Wet FGD systems are 

characterized by low flue gas outlet temperatures, saturated or wet flue gas conditions, and a wet sludge 

reaction product which is dewatered before reuse or disposal. For most solid fuels and boiler types, the 

flue gas saturation temperature is about 130 o

F. In wet FGD applications, the primary PM control system 

is located upstream of the wet FGD system so that the fly ash and FGD system reaction products are 

collected separately. This is necessary to avoid saturated conditions in the PM control system which 

would plug a fabric filter baghouse or dry ESP. Wet FGD systems are also characterized by relatively 

high water use as compared to dry FGD systems. 

Dry FGD systems are characterized by outlet flue gas temperatures about 20 to 50 °F above the saturation 

point, or about 150 o

F to 180 oF. In dry FGD applications, the PM system is located downstream of the 

dry FGD system so that the fly ash and the FGD reaction product are commingled into a single stream. 

Dry FGD systems also have reduced water use as compared to wet FGD systems. 

7.3.1 Wet Flue Gas Desulfurization. 

Wet FGD is a well demonstrated technology for the control of SO2 emissions from utility scale coal-fired 

boilers. In a wet FGD system, the flue gas is exposed to an alkaline reagent which reacts with SO2 to 

form a solid. There are several alkaline reagents used in wet FGD systems, including water-based slurries 

of lime or limestone, liquors containing dissolved sodium or magnesium salts, or amine based liquors 

including ammonia. A typical modern wet FGD system absorber tower is shown in Figure 7-1. 

Regardless of the wet FGD design, the flue gas leaving the absorber will be saturated with water, and the 

stack will have a visible condensed moisture plume at all times. The conditions downstream of the 

absorber are highly corrosive, requiring highly corrosion-resistant materials for the downstream ductwork 

and stack. This would require that the stack be specially designed with a fiberglass liner. Equipment is 

also needed to manage the condensation that occurs on the downstream ductwork and in the stack. The 

wet FGD reaction products also require dewatering, usually by a combination of hydroclones and vacuum 

filters. Large areas are needed to manage the dewatering and byproduct storage, as well as the substantial 

water treatment facilities required for the FGD systems. These factors contribute to the high capital and 

operating costs of wet FGD systems. 

Advanced Wet FGD Designs. 

The first FGD systems in the U.S. were installed largely in response to the 1971 Clean Air Act. Most of 

these original FGD systems were calcium based wet FGD systems. About half of these early systems 

were lime and the other half limestone. Many of these FGD systems were plagued with operational issues 

including scaling, plugging, and low SO2 removal. These first wet FGD systems utilized spray tower 

absorbers, often without a perforated plate tray, as the method for contacting the flue gas with the reagent. 
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FIGURE 7-1. Typical modern wet flue gas desulfurization system absorber tower. 

FGD systems installed in the 1990’s were 2nd and 3rd generation systems which generally achieved greater 

than 90% SO2 removal with improved reliability. The limestone systems installed during this time were 

mostly forced oxidation systems which demonstrated the ability to achieve similar performance and 

reliability as lime systems. The SO2 removal efficiencies of the 2nd and 3rd generation systems were 

improved primarily by improving gas to liquid contact. These improvements include absorption trays 

with perforated plates and multiple levels of interspatial reagent spray nozzles. 

FGD system suppliers have introduced several new designs to improve the flue gas to FGD liquid reagent 

contact and minimize operating costs. Designs such as the Jet Bubbling Reactor developed by Chiyoda 

and Alstom’s Flowpac systems were developed to improve the gas-to-liquid contact by forcing the flue 

gas to bubble through the liquid reagent using a gas sparger design rather than spraying the alkaline slurry 
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into the gas stream. Mitsubishi developed the Double Contact Flow Scrubber (DCFS) which uses 

‘fountains’ of slurry to contact the flue gas. Babcock Power Environmental Inc. utilizes bidirectional 

sprays and wall rings to maximize contact between the flue gas and liquid reagent. All of these wet FGD 

systems use the limestone forced oxidation (LSFO) process. 

Wet Limestone with Forced Oxidation. 

In recent years, the WFGD market has turned almost completely to the use of wet lime or limestone with 

forced oxidation on utility scale coal-fired boilers because it improves SO2 control, reduces chemical 

scale formation, and produces gypsum, a stable and potentially saleable byproduct. Wet limestone with 

forced oxidation (LSFO) is a modification of the conventional wet limestone FGD process. A 

conventional wet limestone system forms a scrubber product composed mostly of calcium sulfite 

(CaSO3). The LSFO process further oxidizes calcium sulfite to calcium sulfate dihydrate (gypsum, or 

CaSO4·2H2O). The gypsum content of the scrubber sludge is typically 95% on a dry basis, making the 

sludge easier to dewater. Gypsum is a naturally occurring mineral that is used as a raw material in the 

manufacture of plaster, wallboard, Portland cement, agricultural soil conditioners, and other products. 

In the LSFO process, flue gas exits the primary PM pollution control system at approximately 300 o

F and 

enters a spray tower where an alkaline slurry consisting of limestone (calcium carbonate), calcium sulfite, 

and calcium sulfate is contacted with the flue gas. Through a series of reactions, SO2 in the flue gas 

reacts with calcium carbonate to form CaSO3. The flue gas exits the absorption tower through a series of 

chevron mist eliminators to remove entrained moisture droplets. The calcium sulfite remains in the slurry 

which drains into a recirculation tank located at the bottom of the spray tower. By injecting air into the 

slurry using fans or blowers, the calcium sulfite is oxidized to CaSO4·2H2O. A portion of the slurry in the 

recirculation tank is pumped back into the spray tower, and a portion is removed. The removed slurry is 

dewatered and stockpiled for transport offsite. The overall FGD reaction is: 

CaCO3(s) + SO2(g) + 1⁄2O2(g) + 2H2O → CaSO4·2H2O(s) + CO2(g) 

The LSFO process can achieve high levels of control on coal-fired boilers. Recent BACT determinations 

put the level of control at 95 - 97% range. However, the same performance principle for any SO2 control 

system is also true for the LSFO – as the boiler outlet SO2 concentration decreases, the ability to achieve 

high control efficiencies also decreases. 

Technical Feasibility 

WFGD is a well demonstrated technology for the control of SO2 emissions from coal-fired boilers. Wet 

FGD systems have been installed primarily on large utility scale pulverized coal-fired boilers combusting 

higher sulfur coals. However, we are not aware of a CFB boiler equipped with a wet FGD system, nor 

are we aware of a biomass-fired boiler equipped with a wet FGD system. However, as noted above, the 

current wet FGD systems are 3rd generation FGD systems which would integrate many of the advances in 

wet FGD design. While we are not aware of the use of wet FGD on similar biomass-fired boilers, wet 

FGD is a technically feasible control option. 
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7.3.2 Dry Flue Gas Desulfurization. 

Dry FGD is also a well demonstrated technology for the control of SO2 emissions from coal-fired electric 

generating units. Like wet FGD systems, dry FGD systems can be divided into several types. Dry FGD 

systems involve injecting a dry sorbent into the furnace or flue gas duct; the by-product solids are 

collected with the boiler fly ash. In semi-dry FGD systems, the sorbent is introduced as an aqueous slurry 

or a humidified dry powder to improve SO2 control efficiency. The water content is controlled so that the 

reaction by-products are dry solids. While the flue gas temperature in both types remains above the 

adiabatic saturation temperature, the semi-dry systems have lower temperatures and a closer approach to 

the saturation temperature. The primary PM control system for dry FGD applications is often a fabric 

filter baghouse since they can provide higher reagent utilization. 

Dry FGD systems do not have a saturated plume and therefore do not require the same design elements 

related to a saturated and corrosive plume as wet FGD systems. Since the dry FGD reaction products are 

also dry, there is no need for dewatering equipment or wastewater discharge. The reaction product in dry 

FGD systems is primarily calcium sulfite, with smaller amounts of calcium sulfate. Because of the 

calcium sulfite content, the dry FGD byproduct will undergo pozzolanic (cementitious) reactions when 

wetted. This material has limited commercial value and is typically disposed of as waste material. 

Lime Spray Drying Absorber 

One of the most widely used dry FGD technologies is the lime spray dry absorber (LSDA). LSDA is a 

semi-dry FGD technology that is often used on utility scale low sulfur coal-fired boilers. The LSDA 

process employs a spray dryer absorber (SDA) and a downstream PM control device. The SDA 

introduces a lime or limestone slurry and flue gas at the top of an absorber vessel. Rotary atomizers or 

nozzles are used to create a spray of slurry droplets which are dispersed in the flue gas stream. The water 

in the slurry droplets evaporates as the flue gas passes through the absorber, cooling and humidifying the 

flue gas stream and rapidly drying the slurry to a powder. In practice, water is added to control the SDA 

outlet temperature to approximately 155o

F, or an approach temperature approximately 25oF above the 

saturation temperature. SO2 in the flue gas reacts with calcium hydroxide in the reactor or on the fabric 

filter bags to form solid calcium sulfite (CaSO3) and calcium sulfate (CaSO4): 

 2Ca(OH)2 (s) + 2SO2 (g) + 2H2O (g) → 2(CaSO3 • 2H2O) 

 2Ca(OH)2 (s) + 2SO2 (g) + 2H2O (g) +O2 → 2(CaSO4 • 2H2O) 

Fly ash, reaction products, and unreacted lime are captured downstream in the PM control system. A 

portion of the collected material is recycled back to the SDA to improve reagent utilization. 

Advanced Semi-Dry FGD Systems 

Advanced Semi-Dry FGD systems include circulating fluidized bed (CFB) systems, hydrated lime 

injection systems such as Turbosorp, circulating dry scrubbers (CDS), and flash dry absorbers, also called 

novel integrated desulphurization system (NIDS). These systems are often utilized in circulating 

fluidized bed (CFB) boiler applications where excess lime (CaO) produced in the CFB boiler can be used 
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to further reduce SO2 emissions. The ash captured in the baghouse containing excess lime is hydrated to 

form calcium hydroxide (Ca(OH)2). The ash is then reinjected into the flue gas in a vessel upstream of 

the PM control device. 

These advanced semi-dry systems may be contrasted with conventional SDA systems in that the ash is 

humidified but remains a free-flowing solid, as opposed to being hydrated to a slurry as in the SDA 

process. This lower water content eliminates the need for slurry handling, atomization, and a large 

reactor. Reinjecting a dry solid also allows the reagent to disperse rapidly in the flue gas. These systems 

may also be contrasted with conventional SDA systems in that the solids recirculation rate is 30 to 100 

times, compared to 3 – 5 times in a conventional SDA system. These semi-dry FGD systems have 

demonstrated the ability to achieve SO2 emission reductions equivalent to, and in some cases greater than, 

that achieved by conventional dry FGD systems and LSDA. 

Technical Feasibility. 

Dry FGD systems, including lime spray drying absorbers, circulating fluidized bed systems, hydrated 

lime injection systems, and flash dryer absorbers, are all demonstrated for the control of SO2 emissions 

from coal-fired boilers. While the proposed biomass-fired boiler will fire low sulfur fuels, these dry and 

semi-dry FGD systems are never-the-less technically feasible control options. Because of the general 

similarities with all of the dry FGD systems, the LSDA is representative of the dry FGD systems and is 

used to further evaluate dry FGD systems in this analysis. 

7.3.3 Sorbent Injection. 

Sorbent injection systems may be considered as dry FGD systems in which a powdered sorbent is injected 

into the furnace or into downstream ductwork. Several types of sorbent injection are available, including 

furnace sorbent injection, and duct sorbent injection. Dry sorbent injection (DSI) is a dry FGD system. 

In a typical DSI system, water is injected into the duct downstream of the air preheater to cool and 

humidify the flue gas. The sorbents are typically either sodium or calcium-based and are injected either 

in the furnace, or in the downstream ductwork prior to the PM control system. Calcium based sorbents 

include limestone and hydrated quicklime; sodium-based sorbents include sodium bicarbonate, and trona 

(sodium sesquicarbonate or Na2CO3 • NaHCO3 • 2H2O) may be injected into the duct upstream of the PM 

control system. The fly ash, sorbent reaction products, and unused sorbent are collected in the PM control 

system. DSI has typical SO2 removal efficiencies ranging from 25 to 50%, although higher removal 

efficiencies are reported at high molar ratio sorbent injection rates. 

Furnace sorbent injection is also a dry system. Sorbents such as limestone or hydrated lime are injected 

into the boiler furnace. The injection point is selected based on the temperature window that is required 

for the reagent, typically around 1,000 – 1,500°F. Water is injected into the ductwork between the air 

heater and the PM collector for flue gas conditioning to promote additional SO2 removal. The reaction 

product and fly ash are collected in the PM collection system. Furnace sorbent injection systems typically 

achieve SO2 removal efficiencies of 25 to 50%. However, for fluidized bed boilers, furnace sorbent 

injection is capable of removing 90% of the fuel sulfur in high sulfur coal applications. 
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Technical Feasibility. 

Dry sorbent injection into the ductwork is a technically feasible control option for this CFB boiler. 

However, furnace sorbent injection is not a technically feasible control option for this CFB boiler. When 

firing biomass fuels, the injection of additional calcium in the form of limestone may result in excessive 

calcium in the bed. Excessive levels of calcium can cause the solids in the bed to agglomerate and cause 

the bed to collapse. This can cause failure of the boiler to fluidize. 

7.3.4 Emerging Flue Gas Desulfurization Technologies. 

Emerging SO2 control technologies include Enviroscrub (also known as the Pahlman process), ECO 

scrubber, REACT, and the Airborne process. These emerging technologies are not yet demonstrated 

through installation and successful operation on a full scale boiler or are not available or applicable. Of 

these advanced processes, the ECO system process is closest to commercial operation. The ECO process 

has been installed as a slip stream unit on a bituminous coal-fired boiler. The ECO system being offered 

is a redesigned version of the slip stream scrubber taking into account the “lessons learned.” The ECO 

system design has not yet been installed or demonstrated on a full scale on any boiler. 

The REACT technology from Japan consists of three major process steps: absorption, regeneration, and 

byproduct recovery. The absorption process utilizes pelletized activated coke (ATC) and ammonia for 

removal of SO2 and sulfuric acid from the flue gas. The mechanism for the removal of pollutants is very 

different between the REACT and wet FGD processes, although they are both located in the flue gas 

stream downstream of the primary PM control system. The absorption and regeneration processes of the 

REACT technology are dry, and require secondary particulate removal to collect the reaction product. 

Airborne ProcessTM

In October, 2004, the U.S. Department of Energy announced that Peabody Energy’s Mustang Energy 

project will be awarded a $19.7 million Clean Coal Power Initiative grant for demonstrating technology to 

achieve ultra-low emissions at a proposed facility near Grants, New Mexico. The Project is intended to 

demonstrate Airborne’s emission control process. The technology would combine dry sodium 

bicarbonate injection with enhanced wet sodium bicarbonate scrubbing. Because the sodium bicarbonate 

reagent is expensive and the reaction product has limited value, the Airborne ProcessTM is intended to 

regenerate the scrubber reagent. The regeneration process would recover the reagent for reuse and 

convert SO2 and NOx into ammonium sulfate and ammonium nitrate fertilizers. 

Technical Feasibility. 

While several advanced FGD technologies show promise in achieving very low SO2 emission rates, these 

processes are not commercial, nor are they demonstrated in practice. Due to the lack of demonstrated 

performance, these technologies are not technically feasible control options for this biomass-fired boiler. 
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7.3.5 Low Sulfur Fuels and Fuel Cleaning. 

Sulfur dioxide emissions may be controlled by the use of post-combustion FGD systems designed to 

remove SO2 from the flue gas after combustion. Because SO2 emissions occur from the oxidation of fuel 

sulfur, SO2 emissions may also be controlled by limiting the fuel sulfur content. 

Low Sulfur Fuels. 

Biomass is an inherently low sulfur fuel. Tables 7-2 and 7-3 are a summary of wood and wood waste fuel 

data from two different sources. From the U.S. EPA’s document Compilation of Air Pollutant Emission 

Factors, AP-42, 5th Edition, Table 1.6-2, the combustion of wood waste has a typical SO2 emission rate of 

0.025 lb/mmBtu. Tables 7-2 and 7-3 indicate that the potential SO2 combustion concentration or 

uncontrolled SO2 emission rate is substantially higher than the values from AP-42, ranging from 0.13 to 

0.35 lb/mmBtu, with a typical potential SO2 combustion concentration of 0.24 lb/mmBtu. These sulfur in 

fuel values are 5 to 14 times higher than the AP-42 value. The lower actual SO2 emission rate is due to 

the retention of sulfur in the flyash and bottom ash by the highly alkaline ash. 

Fuel Cleaning. 

Fuel cleaning is not technically feasible for biomass fuels. The sulfur in biomass is primarily organic; 

there is no known commercially available technology for removing organic sulfur from biomass fuels. 

TABLE 7-2. Typical proximate and ultimate analyses for several biomass fuels. 

Wood Analyses, dry basis, weight % Pine Bark Oak Bark Spruce Bark 

Proximate Analysis, % 

 Volatile Matter 72.9 76.0 69.6 

 Fixed Carbon 24.2 18.7 26.6 

 Ash 2.9 5.3 3.8 

Ultimate Analysis, % 

 Hydrogen 5.6 5.4 5.7 

 Carbon 53.4 49.7 51.8 

 Sulfur 0.1 0.1 0.1 

 Nitrogen 0.1 0.2 0.2 

 Oxygen 37.9 39.3 38.4 

 Ash 2.9 5.3 3.8 

Heat Content, Btu per pound 9,030 8,370 8,740 

Potential SO2 Combustion Concentration, lb/mmBtu 0.22 0.24 0.23 

Footnotes 

Reproduced from Steam, its generation and use, 41st Edition, The Babcock & Wilcox Company. 
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TABLE 7-3. Wood fuels analyses data and uncontrolled SO2 emission rates. 

Wood Analyses, dry basis, weight % Site 1 Site 2 Site 3 Site 4 Site 6 Site 7 Analysis, Dry Basis  Volatile Matter 79.59 80.53 78.52 68.47 78.53 77.24  Fixed Carbon 15.25 12.09 17.61 15.55 16.33 16.36  Ash 5.16 7.38 3.87 15.99 5.15 6.40  Carbon 50.28 50.55 52.90 45.38 50.11 50.45  Hydrogen 5.92 5.95 5.85 5.17 5.87 5.86  Nitrogen 0.46 0.53 0.51 0.73 0.52 0.62  Sulfur 0.12 0.06 0.08 0.05 0.15 0.10  Ash 5.16 7.38 3.87 15.99 5.15 6.40  Oxygen 38.07 35.54 36.79 32.69 38.20 36.57  Chlorine 0.08 0.03 0.16 0.06 0.03 0.05 Heat Content, Btu per pound 8,238 8,599 8,795 7,543 8,353 8,437 Uncontrolled SO2 Emission Rate, lb/mmBtu 0.291 0.140 0.182 0.133 0.359 0.237 Uncontrolled HCl Emission Rate, lb/mmBtu 0.100 0.036 0.187 0.082 0.037 0.061 

Footnotes 

Data is from the U.S. EPA Report, Wood Products in the Waste Stream - - Characterization and Combustion Emissions, E

600/R-96-119a. 
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7.4 STEP 3. Rank the Technically Feasible Technologies. 

7.4.1 Low Sulfur Biomass Fuels. 

The amount of sulfur in biomass fuels is highly variable, and may depend on the geographic source of the 

fuel, and the nature of the biomass fuel itself. From the above data sources, the potential SO2 combustion 

concentration for biomass fuels, i.e., the theoretical uncontrolled SO2 emission rate based on fuel 

sampling and analysis, ranges from 0.13 to 0.35 lb/mmBtu. However, much of this sulfur is normally 

retained in the boiler fly and bottom ash. Ash mineral analysis data from the U.S. EPA Report, Wood 

Products in the Waste Stream - Characterization and Combustion Emissions, EPA Report EPA-600/R96-119a, Table 7-32 indicates that the evaluated fuels in the report had calcium oxide (CaO) levels of 

15.3%. The fuel had an average ash content of 7.8%, and an average sulfur content of 0.094%, on a dry 

basis. From these values, the fuel had a CaO level of 1.19 lb CaO/100 lb dry fuel, or 0.0213 moles of 

calcium per 100 lb dry fuel. The fuel also had a sulfur content of 0.094%, equal to 0.00294 moles of 

sulfur per 100 lb dry fuel. Therefore, the effective calcium to sulfur ratio in the boiler when firing this 

typical biomass fuel is more than seven to one (7:1). 

In the CFB boiler, calcium oxide reacts with SO2 to form calcium sulfate (CaSO4). Calcium sulfate is 

removed from the CFB bed and in the fabric filter baghouse as a solid. In CFB boilers firing coal, 

calcium to sulfur ratios of 1.8 to 2.5 may be necessary to achieve greater than 90% removal on high sulfur 

fuels12. However, as the fuel sulfur content decreases, higher Ca:S molar ratios are necessary to achieve 

similar reduction efficiencies. Never-the-less, the very high effective Ca:S ratios when combusting 

biomass fuels is expected to result in a high retention of sulfur in the ash. 

In January, 2010, a preliminary database of emission test data, continuous emission monitoring system 

(CEMS) data, and fuel analysis data for boilers and process heaters at major sources of HAP was made 

available at http://www2.ergweb.com/projects/combustion/combustiontesting.html. This data includes 

standardized emission data from both the U.S. EPA’s Phase I survey Information Collection Request 

(ICR No. 2286.01) and the Phase II test plan (ICR No. 2286.03). SO2 stack test data for biomass 

combustion indicates SO2 concentrations in the flue gas ranging from 0.1 to 51 part per million at 3% 

excess O2. These concentrations are equivalent to SO2 emission rates of 0.0002 – 0.10 lb/mmBtu. Other 

data indicates higher SO2 concentrations for biogas/natural gas combustion and blends of industrial 

sludge/natural gas/wood/bark combustion of up to 102 ppm at 3% excess O2, equal to 0.19 lb/mmBtu. 

The available data from the U.S. EPA and other databases indicates a wide range of potential SO2

emission rates from biomass fuels combustion. Based on the available data, the combustion of biomass 

fuels in the circulating fluidized bed boiler is expected to result in an “uncontrolled” SO2 emission rate of 

0.09 lb/mmBtu, equal to an SO2 concentration of 48 parts per million at 3% excess oxygen. 

 

12 From STEAM, its generation and use, 41st Edition, the Babcock & Wilcox Company, Barberton, Ohio, Chapter 

17, Fluidized Bed Combustion, page 17-13, available at www.babcock.com; and Combustion and Gasification in 

Fluidized Beds, 2006, Prabir Basu, CRC Press, ISBN 0849333962, page 154. 
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7.4.2 Wet Flue Gas Desulfurization. 

Modern wet FGD designs can achieve 95 - 99% SO2 removal on an initial performance guarantee and 

maximum short term basis when firing high sulfur coals. However, it is the conclusion of the U.S. EPA 

and other agency decisions that it is not technically feasible to achieve this high control level day after 

day, year after year. Further, because these biomass-fired boilers are expected to have a very low 

“uncontrolled” SO2 emission rate of 0.09 lb/mmBtu, a 90% reduction would be equal to an SO2 emission 

rate of only 0.01 lb/mmBtu, equal to about 5 ppm at 5% O2. For this analysis, a wet FGD system is 

expected to reduce SO2 emissions to a level of 0.02 lb/mmBtu, or 10 ppm at 5% O2. 

7.4.3 Dry Flue Gas Desulfurization. 

Modern dry FGD designs can achieve 90 - 95% SO2 removal on an initial performance guarantee and 

maximum short term basis, again, when firing coal. For this analysis, a state-of-the-art dry FGD system 

is expected to achieve a long term SO2 emission rate of 0.03 lb/mmBtu. 

7.4.4 Dry Sorbent Injection. 

According to the U.S. EPA, dry sorbent injection systems have typical SO2 removal efficiencies ranging 

from 25% to 50+%13. According to the Institute of Clean Air Companies, dry injection systems typically 

have removal efficiencies ranging from 50 - 70%14. Higher removal efficiencies have been reported by 

one air pollution control system vendor for trona injection15. For this analysis, dry sorbent injection is 

expected to achieve an SO2 emission rate of 0.05 lb/mmBtu, equal to a 45% reduction from the biomass 

fuel uncontrolled SO2 emission rate of 0.09 lb/mmBtu. 

7.4.5 Ranking of the Technically Feasible Control Options. 

Table 7-4 is a summary of the ranking of the technically feasible SO2 control technologies based on the 

above analysis of available technologies. 

TABLE 7-4. Ranking of the technically feasible SO2 control technologies. 

Rank Control System Expected Performance, lb/mmBtu 

1 Wet FGD 0.02 

2 Dry FGD 0.03 

3 Sorbent Injection 0.05 

4 Low Sulfur Biomass Fuels 0.09 

 

13 From the U.S. EPA’s Compilation of Air Pollutant Emission Factors, AP-42, Table 1.1-1. 

14 Available at http://www.icac.com/i4a/pages/index.cfm?pageid=3401. 

15 Refer to several papers presented by Solvair, available at http://www.solvair.us. 
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7.5 STEP 4. Evaluate the Most Effective Controls. 

7.5.1 Rank No. 1: Wet Flue Gas Desulfurization. 

Environmental and Energy Impacts. 

The most effective SO2 control option is the use of a wet FGD system in combination with firing biomass 

fuels. Based on the above analysis, the wet FGD system could reduce potential SO2 emissions from the 

biomass-fired boiler to 0.02 lb/mmBtu, and 62 tons per year. However, a wet FGD system would 

consume large amounts of water and result in a new wastewater discharge stream. A wet FGD system 

would also produce a distinct visual plume. A wet FGD system would produce a new gypsum byproduct 

stream. While the gypsum byproduct has some potential for reuse, this byproduct may also require 

disposal. 

A wet FGD system would also require substantial auxiliary electric power requirements. In a wet FGD 

system, auxiliary electric power is required to operate slurry pumps, sludge dewatering, and for the 

induced draft fan requirements to overcome the wet FGD system pressure drop. 

Economic Feasibility. 

Table 7-5 includes a summary of the sulfur dioxide control technology costs. A detailed cost analysis for 

the SO2 control technology options is included in Attachment 2. A wet FGD system is expected to have a 

total capital cost of $53 million, annual O&M costs of $3.7 million, and a total annual cost of $9.5 

million. From Table 7-5, the wet FGD system would reduce actual SO2 emissions by 216 tons per year as 

compared to the uncontrolled biomass fuels emission rate and an annual capacity factor of 88%. This 

results in an average cost effectiveness for the wet FGD system of $43,800 per ton of SO2 controlled. 

In addition, the use of a wet FGD system would have an increased incremental cost of $2.1 million per 

year as compared to the use of dry FGD. The wet FGD system would reduce SO2 emissions by 31 tons 

per year as compared to the use of a dry FGD system. This would result in an incremental cost 

effectiveness of wet FGD, as compared to dry FGD, of $66,500 per ton of SO2 controlled. 

Conclusion. 

While a wet FGD SO2 control system is technically feasible for the proposed biomass-fired boiler, the use 

of the wet FGD system would have significant energy, environmental, and economic impacts. The use of 

a wet FGD system would consume large amounts of water and result in a new wastewater discharge 

stream. The wet FGD system would also produce a distinct visual plume, and would produce a new 

byproduct stream which may require disposal. A wet FGD system would also require substantial 

auxiliary electric power requirements. Finally, the use of a wet FGD system would have an average cost 

effectiveness of $43,800 per ton of SO2 removed. This cost is not economically feasible. 

Based on this analysis, wet FGD does not represent the best available control technology for this biomass 

fuel-fired boiler. 
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TABLE 7-5. Cost effectiveness of the SO2 control technology options for the biomass-fired boiler. 

Parameter Wet FGD Dry FGD Sorbent 

Injection 

Low Sulfur 

Biomass 

Fuels 

Control Efficiency 78% 67% 45% 0% 

Controlled Emission Rate, lb/mmBtu 0.02 0.03 0.05 0.09 

Total Boiler Heat Input, mmBtu 800 800 800 800 

Capacity Factor, % 88% 88% 88% 88% 

Actual Emissions, tons per year 62 93 153 278 

Total Capital Requirement, $ $52,642,000 $39,963,000 $3,295,000 $0 

Capital Recovery Factor (CRF) 0.1098 0.1098 0.1098 0.1098 

Annual Capital Cost, $/yr $5,780,000 $4,388,000 $362,000 n/a 

Annual O&M Cost, $/yr $3,683,000 $3,025,000 $881,000 n/a 

Total Annual Cost, $/yr $9,463,000 $7,413,000 $1,243,000 $0 

Average Annual Cost, $/yr $9,463,000 $7,413,000 $1,243,000 

Average SO2 Reduction, tons per year 216 185 125 

Average Cost per Ton Reduced, $ per ton $43,840 $40,070 $9,950 

Incremental Annual Cost, $/yr $2,050,000 $6,170,000 

Incremental SO2 Reduction, tons per year 31 60 

Incremental Cost per Ton Reduced, $ per ton $66,500 $102,600 

 Footnotes 

1. "Annual Capital Cost" or capital recovery cost is calculated by multiplying the capital recovery factor (CRF) by 

the Total Capital Requirement as detailed in the U.S. EPA's EPA Air Pollution Control Cost Manual - Sixth Edition 

(EPA 452/B-02-001): 

where: 

 i = annual interest rate = 7.0% 

 n = project life, years = 15 

5. The total annual cost is the sum of the annual capital costs and annual O&M costs. 

6. "Average SO2 Reduction" is the emissions of the uncontrolled boiler minus the emissions of the control option. 

7. "Average Cost per Ton Reduced" is the Average Annual Cost of the control option divided by the Average PM 

reduction of the control option: 

Control option annual cost Average Cost Effectiveness ($ per ton removed) = Baseline emission rate – Control option emissions rate 

8. "Incremental Annual Cost" is the Total Annual Cost of the control option minus the Total Annual Cost of the 

next most effective control option. 

9. "Incremental Reduction" is the Potential Emission Rate of the next most effective control option minus the 

Potential Emission Rate of the control option. 

10. "Incremental Cost per Ton Reduced" is the Incremental Annual Cost of the control option divided by the 

Incremental PM reduction of the control option: 

Control option annual cost – Next control option annual cost Incremental Cost ($ per ton removed) = Next control option emission rate – Control option emissions rate 

[ ] (1 ) 1

(1 )

+ −

+ = n

n

i

i i CRF
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7.5.2 Rank No. 2: Dry Flue Gas Desulfurization. 

Environmental and Energy Impacts. 

The next most effective SO2 control option is the use of a dry FGD system in combination with firing 

biomass fuels. Based on the above analysis, a dry FGD system could reduce potential SO2 emissions 

from the biomass-fired boiler to 0.03 lb/mmBtu, and 93 tons per year. However, a dry FGD system 

would also consume large amounts of water – although less than that of a wet FGD system. A dry FGD 

system would increase ash generation rates and would impact the flyash properties which may reduce the 

flyash value for reuse and result in increased ash disposal requirements. 

As with wet FGD systems, a dry FGD system would also require additional auxiliary electric power 

requirements to operate injection pumps and for the induced draft fan requirements to overcome the dry 

FGD system pressure drop. 

Economic Feasibility. 

Table 7-5 includes a summary of the SO2 control technology costs. A dry FGD system is expected to 

have a total capital cost of $40 million, annual O&M costs of $3.0 million, and a total annual cost of $7.4 

million. From Table 7-5, a dry FGD system would reduce actual SO2 emissions by 185 tons per year as 

compared to the uncontrolled biomass fuels emission rate and an annual capacity factor of 88%. This 

results in an average cost effectiveness for a dry FGD system of $40,070 per ton of SO2 controlled. 

In addition, the use of a dry FGD system would have an increased incremental cost of $6.2 million per 

year as compared to the use of sorbent injection. The dry FGD system would reduce SO2 emissions by 60 

tons per year as compared to the use of a sorbent injection system. This would result in an incremental 

cost effectiveness of dry FGD, as compared to sorbent injection, of $102,600 per ton of SO2 controlled. 

Conclusion. 

While a dry FGD SO2 control system is technically feasible for the proposed biomass-fired boiler, the use 

of a dry FGD system would have significant energy, environmental, and economic impacts. The use of a 

dry FGD system would also consume large amounts of water - although less than that of a wet FGD 

system, and its use may adversely impact the flyash properties and reduce its value for reuse. A dry FGD 

system would also require substantial auxiliary electric power requirements. Finally, the use of a dry 

FGD system would have an average cost effectiveness of $40,070 per ton of SO2 removed. This cost is 

not economically feasible. 

Based on this analysis, dry FGD does not represent the best available control technology for this biomass 

fuel-fired boiler. 
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7.5.3 Rank No. 3: Sorbent Injection. 

Environmental and Energy Impacts. 

The next most effective SO2 control option is the use of a dry sorbent injection system in combination 

with firing biomass fuels. Based on the above analysis, a dry sorbent injection system could reduce 

potential SO2 emissions from the biomass-fired boiler to 0.05 lb/mmBtu, and 153 tons per year. 

However, like the dry FGD system, a dry sorbent injection system would increase ash generation rates 

and may adversely impact the flyash properties which may reduce its value for reuse and increase ash 

disposal requirements. 

As with wet and dry FGD systems, a dry sorbent injection system would also require additional auxiliary 

electric power requirements to operate injection pumps and for the induced draft fan requirements to 

overcome the additional fabric filter baghouse pressure drop due to the sorbent injection. 

Economic Feasibility. 

Table 7-5 includes a summary of the SO2 control technology costs. A dry sorbent injection system is 

expected to have a total capital cost of $3.3 million, annual O&M costs of $880,000, and a total annual 

cost of $1.2 million. From Table 7-5, a dry sorbent injection system would reduce actual SO2 emissions 

by 125 tons per year as compared to the uncontrolled biomass fuels emission rate and an annual capacity 

factor of 88%. This results in an average cost effectiveness for a dry FGD system of $9,950 per ton of 

SO2 controlled. 

Conclusion. 

While a dry sorbent injection SO2 control system is technically feasible for this proposed biomass-fired 

boiler, the use of a dry sorbent injection system would have significant energy, environmental, and 

economic impacts. Like the use of a dry FGD system, the use of a dry sorbent injection may adversely 

impact the flyash properties and reduce its value for reuse. A dry sorbent injection system would also 

require substantial auxiliary electric power requirements. Finally, the use of a dry sorbent injection 

system would have an average cost effectiveness of $9,950 per ton of SO2 removed. This cost is not 

economically feasible. 

Based on this analysis, dry sorbent injection does not represent the best available control technology for 

this biomass fuel-fired boiler. 

7.5.4 Rank No. 4: Low Sulfur Biomass Fuels. 

The use of low sulfur biomass fuels in a circulating fluidized bed boiler is expected to have SO2 emissions 

of 0.09 lb/mmBtu, and 350 tons per year. Based on this analysis, the use of low sulfur biomass fuels in a 

circulating fluidized bed boiler represents the best available control technology for this biomass fuelsfired boiler. 
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7.6 STEP 5. Proposed Sulfur Dioxide BACT Determination. 

Based on this analysis, We Energies has concluded that the use of low sulfur biomass fuels and natural 

gas in a circulating fluidized bed boiler represents BACT for SO2 emissions for the biomass fuels-fired 

CFB boiler. Based on this analysis, We Energies proposes the following limits as BACT for the control 

of SO2 emissions from this biomass fuels-fired boiler. 

(1) Sulfur dioxide (SO2) emissions from the biomass fuels-fired boiler shall be controlled 

using a circulating fluidized bed boiler in combination with the use biomass fuels and 

natural gas as the best available control technology. 

(a) Only natural gas and biomass fuels may be combusted in the boiler. 

(b) “Biomass fuels” means a resource that derives energy from wood or plant material or 

residue, clean solid wood waste and crops grown for use as a resource. Fuel sources may 

include the following and other qualifying clean sources: 

• logging residue 

• discarded woody material from primary manufacturing facilities such as paper mills, 

sawmills, or chip mills 

• on-site pulp & paper wastewater treatment plant residue 

• leftover woody material from secondary manufacturers such as door, window, 

cabinet manufacturers 

• woody biomass from municipality wood waste, tree services, and construction 

companies 

• clean solid wood waste from discarded wood packaging such as pallets/crating and 

from construction and demolition activities 

• woody biomass plantations, energy crops and agricultural residues 

“Biomass fuels” excludes edible portions of food crops, refuse derived fuel, treated 

wood, municipal solid waste, sewerage sludge, and animal waste.

(2) SO2 emissions may not exceed 0.09 pounds per million Btu of heat input, averaged 

over any consecutive 30-day period. 

(3) SO2 emissions from the biomass-fired boiler shall be continuously monitored and 

recorded using a continuous emissions monitoring system meeting the requirements 

of 40 CFR Part 75. 

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Chapter 8. Organic Compound (VOC) 

Control Technology Review. 

As with CO emissions, volatile organic compounds (VOC) are emitted from biomass-fired boilers as a 

result of incomplete combustion. CO and VOC emissions from the combustion of biomass fuels are 

normally expected to be somewhat elevated as compared to the combustion of natural gas, fuel oil, and 

coal because of the high moisture content and relatively low heating value of most biomass fuels. 

Incomplete combustion can also result in emissions of particulate matter, CO, and organic hazardous air 

pollutants, and it reduces boiler efficiency. Because fuel costs represent the highest single operating cost 

for these boilers, large industrial boilers are designed to achieve the highest combustion efficiencies 

practicable. VOC emissions can be reduced by operating the boiler with higher flame temperatures, 

higher excess oxygen levels, and longer furnace residence times. Unfortunately, techniques for reducing 

VOC emissions can increase NOx emissions. Consequently, as with CO emissions, achieving low VOC 

and NOx emission rates is a balancing act in boiler design and operation. 

8.1 BACT Baseline. 

There are no specific state implementation plan (SIP) requirements or new source performance standards 

for VOC emissions from biomass or fossil fuel-fired boilers. Therefore, baseline emissions are simply the 

uncontrolled emissions from the boiler. 

8.2 STEP 1. Identify All Available Control Technologies. 

Table 8-1 is a summary of VOC BACT emission limits for both new biomass-fired boilers contained in 

the U.S. EPA’s RACT/BACT/LAER Clearinghouse, and in other permits issued in the United States. 

Emission limits range from 0.005 to 0.50 pounds per million Btu. 

Except for one facility, the only technology selected for all permitted biomass-fired boilers is good 

combustion practices. For the South Point Biomass Generation facility (Ohio, 2006), the facility was 

required to install an oxidation catalyst. However, this facility has not been constructed. 
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TABLE 8-1. Biomass-fired boiler VOC emission limits representing BACT. 

Facility State Permit 

Date 

Capacity, 

mmBtu/hr Primary Fuel Limit, lb/mmBtu 

Public Service of NH - Schiller Station NH Oct-04 720 Biomass 0.005 

S.D. Warren Co. ME Nov-01 1,300 Wood Waste 0.007 

Nacogdoches Power, LLC TX Mar-07 1,374 Wood 0.013 

Northern Michigan University MI Nov-09 210 Wood/Biomass 0.017 

South Point Biomass Generation OH Apr-06 318 Wood 0.013 

Skagit County Lumber Mill WA Jan-06 430 Bark/Waste Wood 0.019 

Yellow Pine Energy Company GA May-09 1,529 Wood 0.02 

Wheelabrator Sherman Energy Co. ME Apr-99 315 Wood 0.030 

Inland Paperboard and Packaging, Inc. GA Oct-04 856 Bark 0.050 

Clewiston Sugar Mill FL Nov-03 936 Bagasse 0.050 

Del Tin Fiber LLC AR Feb-03 291 Wood Waste 0.073 

Deridder Paper Mill LA Nov-03 454 Bark 0.096 

U.S. Sugar Clewiston Mill FL Nov-00 633 Bagasse 0.500 

U.S. Sugar Corporation FL Nov-99 633 Bagasse 0.500 

8.3 STEP 2. Identify Technically Feasible Control Technologies. 

Available control technologies for the control of VOC emissions include good combustion practices, 

oxidation catalysts, and thermal oxidation. 

8.3.1 Oxidation Catalysts. 

Oxidation catalysts are used to reduce CO emissions - and to a lesser extent VOC emissions - from 

natural gas or oil-fired combustion turbines, with typical VOC reductions of 50% or less. However, 

oxidation catalysts have limited demonstration on biomass-fired boilers, and we are not aware of any 

demonstration or commercial operation of oxidation catalysts on a fluidized bed boiler. Boilers have 

several characteristics that make the use of oxidation catalysts technically infeasible, including catalyst 

fouling and poisoning by the wood fly ash, and low excess oxygen levels in the flue gas. 

Oxidation catalysts are generally noble metal catalysts which are susceptible to poisoning from sulfur and 

calcium bearing compounds. These catalysts may experience rapid deactivation and fouling in biomassfired boiler flue gas streams with high particulate loading. To be effective, the oxidation catalyst must be 

placed in a location with gas temperatures of at least 600 o

F. This location would be near the boiler 

economizer outlets, a location with high ash loading and low excess oxygen levels. 

A research effort to assess catalyst deactivation mechanisms was presented at the 2008 Advanced 

Combustion Engineering Research Center conference reported that SCR catalyst poisoning is the 

predominant deactivation mechanism resulting from biomass combustion. Note that oxidation catalysts 
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and SCR catalysts have similar poisoning mechanisms. The study ranks the order of poisoning of the 

alkali-metals and alkaline-earth metals from having the most effect to lesser effect as potassium, followed 

by sodium, followed by calcium, and states that the “effects are proportional to basicity of the exhaust 

gas.” 16 The study includes Figure 3-2 (refer to the CO control technology section) showing the difference 

in of coal versus biomass ash composition. 

Figure 3-2 shows that the relative proportion of potassium is much greater in the biomass ash than in the 

coal ash. Because of the presence of these base compounds and the low acid gas constituents such as 

sulfur dioxide (SO2), biomass flue gas tends to be basic while especially high sulfur coal combustion flue 

gas tends to be acidic. This exacerbates the catalyst deactivation and is the primary reason that oxidation 

catalyst and SCR systems located in a high dust environment are not applicable to biomass combustors. 

This problem is worsened by the CFB boiler design which has an extremely high dust loading. Erosion, 

plugging, and blinding are major potential problems in fluidized bed boiler applications due to the very 

high particulate loading in the boiler. 

To reduce the fouling and catalyst poisoning problems, the oxidation catalyst can be located downstream 

of the particulate matter control device. However, this “tail gas” oxidation catalyst control configuration 

does not eliminate fouling and deactivation, since the exhaust gas stream remains highly alkaline. 

To reduce the ash fouling and catalyst poisoning problems, the oxidation catalyst can be located 

downstream of the particulate matter control device. However, this “tail gas” oxidation catalyst control 

configuration has another problem; the lack of sufficient excess oxygen to effectively reduce VOC 

emissions. Oxidation catalysts operate according to the following reaction for propane as an example: 

 C3H8 + 5O2 → 3CO2 + 4H2O 

Typical excess oxygen (O2) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in biomassfired boilers. These low excess O2 levels will limit the effectiveness of the oxidation catalyst. 

Because of these serious technical problems and the fact that oxidation catalysts have not been 

demonstrated on similar circulating fluidized bed biomass boilers, we have concluded that oxidation 

catalysts are not a technically feasible CO control technology for these biomass-fired boilers. 

8.3.2 Thermal Oxidation 

Thermal oxidation has never been required nor used on a biomass-fired boiler, and its theoretical ability 

to reduce VOC emissions from these boilers is questionable. Thermal oxidation would involve injecting 

additional air into the flue gas and heating the oxygen enriched mixture to approximately 1,500 o

F to 

oxidize VOC to carbon dioxide and water. However, since the combustion of the reheat fuel would itself 

result in VOC emissions, there is no evidence that thermal oxidation would result in any CO emission 

reductions. Since thermal oxidation has never been demonstrated on a biomass-fired boiler, and because 

 

16 Guo, X., et. al. Poisoning/Deactivation Study of V2O5/TiO2 SCR Catalysts, ACERC Annual Conference, 

February 2008. 
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there is no evidence that it could reduce VOC emissions, thermal oxidation is not a technically feasible 

VOC control technology for coal-fired boilers. 

8.3.3 Good Combustion Practices 

Good combustion practices or combustion controls generally include the following components: 

1. Good air/fuel mixing in the combustion zone. 

2. High temperatures and low oxygen levels in the primary combustion zone. 

3. Overall excess oxygen levels high enough to complete combustion while maximizing 

boiler thermal efficiency. 

4. Sufficient residence time to complete combustion. 

In biomass-fired boilers, good combustion practices is the only technically feasible VOC control 

technology. Combustion efficiency is related to the three “T’s” of combustion: Time, Temperature, and 

Turbulence. These components of combustion efficiency are designed into utility boilers to maximize 

fuel efficiency and reduce the highest single operating cost of a utility boiler: FUEL. A fourth critical 

parameter is the level of oxygen in the boiler, referred to as the excess air or excess oxygen level. 

Therefore, combustion control is accomplished primarily through boiler design as it relates to time, 

temperature, and turbulence, and through boiler operation as it relates to excess oxygen levels. 

Combustion design for modern boilers is intended to simultaneously minimize formation of VOC and 

NOx emissions. This is a difficult task, since emissions of NOx and emissions of CO and VOC are 

inversely related. That is, measures used to reduce NOx emissions often lead to increases in VOC 

emissions. Therefore, the boiler design to minimize VOC emissions is interrelated with the boiler design 

to minimize NOx formation. 

8.4 STEP 3. Rank the Technically Feasible Control Technologies. 

Based on the above analysis, the only technically feasible VOC control technology for biomass-fired 

boilers is good combustion practices. 

8.5 STEP 4. Evaluate the Most Effective Controls. 

From Table 8-1, recent BACT determinations have VOC limits ranging from 0.005 to 0.5 lb/mmBtu. 

Fluidized bed boilers are efficient boilers, and are generally expected to achieve low VOC emission rates. 

However, boiler startup, shutdown, and load changes can causes VOC emissions to increase because of 

unstable combustion conditions. Like CO emissions, VOC emissions are also sensitive to boiler 

operating conditions. Changes in operating conditions, such as rapid changes in load, can have a 

significant, though temporary, impact on emissions. This condition is further exasperated during boiler 

startup because the boiler itself is relatively cool, and the low air flow rates make it difficult to obtain 

good air/fuel mixing. For these reasons, VOC emissions can “spike” when transient conditions occur 

during boiler startup and shut down 
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Based on the above analysis, we have concluded that good combustion practices can achieve a VOC 

emission rate of 0.017 pounds per million Btu based on a 30-day average, excluding periods of startup 

and shutdown. Further, we have concluded that these boilers can achieve a VOC emission rate of 0.017 

pounds per million Btu based on a 12-month average, including periods of startup and shutdown. 

8.6 STEP 5. Proposed VOC BACT Determination. 

Based on this analysis, We Energies has concluded that the use of good combustion practices is the best 

available control technology (BACT) for VOC emissions from the biomass-fired boiler. Based on this 

analysis, We Energies proposes the following limits as BACT for the control of VOC emissions from the 

biomass-fired, circulating fluidized bed boiler. 

(1) Volatile organic compound (VOC) emissions from the biomass-fired 

boiler shall be controlled using good combustion practices as the best 

available control technology. 

(2) Volatile organic compound (VOC) emissions may not exceed 0.017 

pounds per million Btu of heat input, excluding periods of boiler 

startup and shut down, averaged over any consecutive 30-day period. 

(3) Volatile organic compound (VOC) emissions may not exceed 0.017 

pounds per million Btu of heat input, for all periods, including periods 

of boiler startup and shut down, averaged over any consecutive 

12-month period. 

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Chapter 9. Fluorides (as HF) Control 

Technology Review. 

Fluorine (F) is a trace element in biomass fuels. When these fuels are burned, fluorine may be emitted as 

hydrogen fluoride or hydrofluoric acid (HF), or as fluorine compounds, such as sodium fluoride (NaF) 

and calcium fluoride (CaF2). Fluoride compounds such as sodium and calcium fluoride are solids at the 

flue gas temperatures entering the particulate matter control systems, and will therefore be collected as 

solids. On the other hand, hydrogen fluoride is a colorless liquid at temperatures less than 66 o

F. At 

temperatures above 66 o

F, hydrofluoric acid is a gas. Hydrofluoric acid is soluble in water and is a strong 

acid, it readily combines with the alkaline ash of biomass fuels. 

9.1 BACT Baseline. 

There are no specific NSPS or SIP emission limitations for fluoride emissions from biomass-fired boilers. 

Therefore, the BACT baseline for fluoride emissions is the uncontrolled emission rate. 

9.2 STEP 1. Identify All Potential Control Technologies 

Based on the permits and information available, We Energies did not identify any wood-fired boiler with 

a hydrogen fluoride (HF) emission limit. There is a limited amount of information available on fluoride 

levels in biomass fuels. According to NCASI Technical Bulletin No. 0837, Emissions of Sulfuric, 

Hydrochloric, and Hydrofluoric Acids from Combination Bark Boilers, HF emissions ranged from 

0.00023 to 0.0011 lb/mmBtu for the coal/bark boilers and from 0.000016 to 0.000074 lb/mmBtu for the 

oil/bark boilers. 

According to the U.S. EPA’s MACT database emission factors from the U.S. EPA memorandum from 

Christy Burlew and Roy Oommen, to Jim Eddinger, U.S. Environmental Protection Agency, OAQPS 

(C439-01), dated October, 2002, Development of Average Emission Factors and Baseline Emission 

Estimates for the Industrial, Commercial, and Institutional Boilers and Process Heaters National 

Emission Standard for Hazardous Air Pollutants, the emission factor for HF emissions from wood-fired 

boilers is 0.0081 lb/mmBtu. The U.S. EPA’s AP-42, Compilation of Air Pollutant Emission Factors, 5th

Edition, Wood Residue Combustion, does not list an emission factor for HF emissions. In Switzerland, 

the combustion requirements for wood limit HF emissions to 2 mg/m3

, equal to 0.0011 lb/mmBtu. 

In January, 2010, a preliminary database of emission test data, continuous emission monitoring system 

(CEMS) data, and fuel analysis data for boilers and process heaters at major sources of HAP was made 

available at http://www2.ergweb.com/projects/combustion/combustiontesting.html. This data includes 

standardized emission data from both the U.S. EPA’s Phase I survey Information Collection Request 

(ICR No. 2286.01) and the Phase II test plan (ICR No. 2286.03). The hydrogen fluoride stack test data for 
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biomass combustion is summarized in Table 9-1. Emission rates ranged from less than 0.000003 to 

0.0012 lb/mmBtu, a range of 3 orders of magnitude. Many of the emission test results indicated HF 

emissions below the detection limit of the test. 

TABLE 9-1. Biomass-fired boiler hydrogen fluoride (HF) emission test results. 

Facility ID NonDetect? 

Standardized 

Value, 

lb/mmBtu 

Fuel 

AR Potlatch Forest Warren < 0.000003 Hog Fuel 

MS Bowater South ND 0.000010 Industrial Sludge/Natural Gas/Wood: Bark 

OR Flakeboard Eugene 0.000016 Natural Gas/Wood: Unadulterated Lumber 

MT Plum Creek BDL 0.000017 Wood: Bark/Wood: Plywood, Particleboard 

AL Meadwestvaco Cottonton ND 0.000018 Industrial Sludge/Natural Gas/Wood: Bark 

MT Smurfit Stone BDL 0.000029 Biomass/Hydropulper Refuse/Industrial Sludge 

/Natural Gas 

AL Meadwestvaco Cottonton ND 0.000031 Industrial Sludge/Natural Gas/Wood: Bark 

OR Flakeboard Eugene 0.000039 Natural Gas/Wood: Unadulterated Lumber 

GA GP Madison Ply ND 0.000040 Wood: Bark 

ID Potlatch 0.000043 Hog Fuel 

MS Weyerhaeuser Bruce 0.000050 Hog Fuel 

AL Meadwestvaco Cottonton ND 0.000051 Industrial Sludge/Natural Gas/Wood: Bark 

SC Marlboro Paper ND 0.000070 Industrial Sludge/Wood: Bark/Natural Gas/Wood: 

Plywood, Particleboard (containing glues or resins) 

GA Temple Inland Rome 0.000072 Wood: Bark 

OR Flakeboard Eugene 0.000074 Natural Gas/Wood: Unadulterated Lumber 

TN Bowater Newsprint ND 0.000075 Biomass/Tire Derived Fuel (TDF)/Wood: Bark 

AR Anthony Forest Product ND 0.000083 Wood: Bark/Wood: Unadulterated Lumber/Wood 

PA Proctor Gamble Mehoopany ND 0.000085 Natural Gas/Paper and Paper Residues 

ND Cargill West Fargo BDL 0.000089 Biomass 

OR Rosboro Springfield 0.000100 Hog Fuel 

KY NewPage-Wickliffe ND 0.000128 Natural Gas/Tire Derived Fuel (TDF)/Wood: Bark 

AR Weyerhaeuser Dierks Mill ND 0.000200 Hog Fuel 

TN Domtar 2384 0.000200 Hog Fuel/Industrial Sludge 

WA Grays Harbor Paper 0.000200 Hog Fuel 

OR Weyerhaeuser Co. 

Warrenton Lumber Mill ND 0.000259 Hog Fuel 

WA Weyerhaeuser Raymond ND 0.000290 Hog Fuel 

ME Boralex Stratton 0.000294 Wood: Bark/Wood: Unadulterated Timber 

OR Georgia Pacific Wauna BDL 0.000341 Hog Fuel/Industrial Sludge/Natural Gas 

WA Kimberly Clark Everett 0.000360 Hog Fuel/Natural Gas 

WA Boise Paper Wallula 0.001005 Hog Fuel/Natural Gas/Noncondensable Gas 

WA Grays Harbor Paper 0.001100 Hog Fuel 

OR SP Newsprint 0.001200 Biomass/Industrial Sludge/Natural Gas 
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9.3 STEP 2. Identify Technically Feasible Control Technologies. 

As noted above, fluoride emissions may be emitted as solids, such as sodium fluoride, or as the acid gas 

hydrogen fluoride. Therefore, fluoride emissions may be controlled using particulate matter control 

systems, and also acid gas control systems. Technologies that may control fluoride emissions include 

fabric filter baghouses, electrostatic precipitators, wet or dry FGD systems, and sorbent injection. 

9.3.1 Flue Gas Desulfurization Systems. 

Wet and dry flue gas desulfurization systems are effective fluoride control systems. From the EPRI 

report, Emission Factors Handbook: Guidelines for Estimating Trace Substance Emissions from Fossil 

fuel Steam Electric Plants, Final Report, April, 2002, the expected HF control efficiency for all coal-fired 

FGD systems is 94%. There is limited additional information available on HF removal in FGD systems, 

especially for biomass combustion. There is very little information on FGD systems for biomass 

combustion, since there are essentially no biomass-fired boilers equipped with FGD systems. 

9.3.2 Sorbent Injection. 

Sorbent injection such as the injection of hydrated lime may also reduce emissions of HF. The injection 

of lime into the flue gas upstream of a fabric filter baghouse or electrostatic precipitator is well 

demonstrated to reduce H2SO4 emissions. However, the continuous reduction of HF via hydrated lime 

injection from biomass combustion is not well understood or demonstrated in practice. Further, because 

biomass combustion already results in high levels of calcium oxide (CaO) and potassium oxide (K2O) in 

the ash, so that the additional injection of sorbent may not achieve substantial emission reductions. 

9.4 STEP 3. Rank The Technically Feasible Control Technologies. 

9.4.1 Biomass Fuels. 

There has been a very limited amount of information available on fluoride levels in biomass fuels. 

According to NCASI Technical Bulletin No. 0837, Emissions of Sulfuric, Hydrochloric, and Hydrofluoric 

Acids from Combination Bark Boilers, HF emissions ranged from 0.00023 to 0.0011 lb/mmBtu for the 

coal/bark boilers and from 0.000016 to 0.000074 lb/mmBtu for the oil/bark boilers. 

According to the U.S. EPA’s MACT database emission factors from the U.S. EPA memorandum from 

Christy Burlew and Roy Oommen, to Jim Eddinger, U.S. Environmental Protection Agency, OAQPS 

(C439-01), dated October, 2002, Development of Average Emission Factors and Baseline Emission 

Estimates for the Industrial, Commercial, and Institutional Boilers and Process Heaters National 

Emission Standard for Hazardous Air Pollutants, the emission factor for HF emissions from wood-fueled 

boilers is 0.0081 lb/mmBtu. The U.S. EPA’s AP-42, Compilation of Air Pollutant Emission Factors, 5th

Edition, Wood Residue Combustion, does not list an emission factor for HF emissions. In Switzerland, 

the combustion requirements for wood limit HF emissions to 2 mg/m3

, equal to 0.0011 lb/mmBtu. 
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In January, 2010, a preliminary database of emission test data, continuous emission monitoring system 

(CEMS) data, and fuel analysis data for boilers and process heaters at major sources of HAP was made 

available at http://www2.ergweb.com/projects/combustion/combustiontesting.html. This data includes 

standardized emission data from both the U.S. EPA’s Phase I survey Information Collection Request 

(ICR No. 2286.01) and the Phase II test plan (ICR No. 2286.03). The database included both fuel 

sampling and analysis data for HF, as well as emission test data for HF from biomass-fueled boilers. The 

HF fuel sampling and analysis data included over 350 samples for biomass fuels (with descriptions 

including wood, bark, plywood, particleboard, hog fuel, and biomass). The HF fuel sampling and 

analysis data ranged from 1.1 x 10-6 lb/mmBtu to 0.033 lb/mmBtu. The database also included HF 

emission test data using U.S. EPA Reference Method 26. The HF emission test data included 34 tests on 

biomass-fueled boilers, with emission rates ranging from 0.000003 lb/mmBtu to 0.0012 lb/mmBtu. 

Nineteen (19) of the emission test results indicated HF emissions below the detection limit of the test. 

This ICR data is plotted in Figure 9-1 as probability distributions for each data set. The 90% probability 

for the HF emission rate, based on fuel sampling and analysis, is 0.006 lb/mmBtu, while the 90% 

probability distribution for the HF emission rate, based on emission testing, is 0.0007 lb/mmBtu. This 

data suggests that the actual HF emissions are reduced by almost 90% as compared to the uncontrolled, 

fuel input or potential combustion concentration for HF. 

FIGURE 9-1. Hydrogen fluoride (HF) fuel sampling and analysis and emission test data for 

biomass combustion from the U.S. EPA’s industrial boiler ICR. 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0.00001 0.00010 0.00100 0.01000 0.10000

HF Emission Rate, lb/million Btu

Probability Density

HF Emission Test Data

HF Fuel Sampling Data

90% Probability, 

0.0007 

90% Probability, 

0.006 lb/mmBtu
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This outcome seems logical because of the high levels of calcium and potassium in typical biomass fuels. 

Typical biomass fuels have a CaO level of 1.19 lb CaO/100 lb dry fuel, or 0.0213 moles of calcium per 

100 lb dry fuel. From the TCR fuel sampling database, the biomass fuels have a typical fluorine content 

of well below 100 mg per kg, or 0.01%. A fluorine content of 0.01% is equal to 0.0005 moles of fluorine 

per 100 lb dry fuel. Therefore, the effective calcium to fluorine ratio in the boiler when firing this typical 

biomass fuel is more than forty to one (40:1). This high level of reactive CaO would be expected to react 

with HF in the flue gas to form calcium fluoride. 

Based on the available data, we have concluded that HF emissions from this biomass-fueled boiler is 

expected to be less than 0.001 lb/mmBtu. 

9.4.2 Flue Gas Desulfurization. 

As noted above, the EPRI report, Emission Factors Handbook: Guidelines for Estimating Trace 

Substance Emissions from Fossil fuel Steam Electric Plants, indicates an HF control efficiency for all 

coal-fired FGD systems of 94%. However, there is limited information available on HF removal in FGD 

systems, especially for biomass combustion. Because of the high level of calcium and potassium in the 

biomass ash, further reduction from FGD systems cannot be assured. For this analysis, wet and dry FGD 

systems are expected to reduce HF emissions to 0.0005 lb/mmBtu, equal to a flue gas concentration of 0.8 

ppm at 5% excess oxygen. 

9.4.3 Sorbent Injection. 

As with the wet and dry FGD options, because of the high level of calcium and potassium in the biomass 

ash, further reduction from sorbent injection systems cannot be assured. For this analysis, dry sorbent 

injection is also expected to reduce HF emissions to 0.0005 lb/mmBtu, equal to a flue gas concentration 

of 0.8 ppm at 5% excess oxygen.. 

9.4.4 Ranking of the Technically Feasible Control Options. 

Table 9-2 is a summary of the ranking of the technically feasible HF control technologies based on the 

above analysis of available technologies. 

TABLE 9-2. Ranking of the technically feasible HF control technologies. 

Rank Control System Expected Performance, lb/mmBtu 

1 Wet or Dry FGD 0.0005 

2 Sorbent Injection 0.0005 

3 Low Sulfur Biomass Fuels 0.001 
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9.5 STEP 4. Evaluate the Most Effective Controls. 

9.5.1 Rank No. 1: Wet FGD, Dry FGD, or Dry Sorbent Injection. 

Environmental and Energy Impacts. 

The most effective fluorides control option is the use of either a wet or dry FGD system, or dry sorbent 

injection, in combination with firing biomass fuels. Based on the above analysis, these control systems 

could reduce potential HF emissions from the biomass-fired boiler to 0.001 lb/mmBtu, and 3.3 tons per 

year. However, wet and dry FGD systems would consume large amounts of water. A wet FGD system 

would also produce a distinct visual plume and a new gypsum byproduct stream. In addition, all of these 

post combustion systems would require additional auxiliary electric power requirements. 

Economic Feasibility. 

Table 9-3 includes a summary of the hydrogen fluorides control technology costs. From Table 9-3, the 

use of dry sorbent injection, the lowest cost option, would reduce actual HF emissions by 1.5 tons per 

year as compared to the uncontrolled biomass fuels emission rate and an annual capacity factor of 88%. 

A dry sorbent injection system is expected to have a total capital cost of $3.3 million, annual O&M costs 

of $880,000, and a total annual cost of $1.2 million. This results in an average cost effectiveness for the 

dry sorbent injection system of $806,000 per ton of HF controlled. 

Conclusion. 

While the use of wet FGD, dry FGD, or sorbent injection control systems are technically feasible for the 

proposed biomass-fired boiler, the use of these post combustion control systems would have significant 

energy, environmental, and economic impacts. However, wet and dry FGD systems would consume large 

amounts of water. A wet FGD system would also produce a distinct visual plume and a new gypsum 

byproduct stream. In addition, all of these post combustion systems would require additional auxiliary 

electric power requirements. 

The use of dry sorbent injection, the lowest cost option, would reduce actual HF emissions by 1.5 tons per 

year and a total annual cost of $1.2 million. This results in an average cost effectiveness for the dry 

sorbent injection system of $806,000 per ton of HF controlled. This cost is not economically feasible. 

Based on this analysis, the use of wet FGD, dry FGD, or dry sorbent injection does not represent the best 

available control technology for the control of HF emissions from this biomass fuels-fired boiler. 

 
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TABLE 9-3. Cost effectiveness of the HF control technology options for the biomass-fired boiler. 

Parameter Wet FGD Dry FGD Sorbent 

Injection 

Low Sulfur 

Biomass 

Fuels 

Control Efficiency 50% 50% 50% 0% 

Controlled Emission Rate, lb/mmBtu 0.0005 0.0005 0.0005 0.001 

Total Boiler Heat Input, mmBtu 800 800 800 800 

Capacity Factor, % 88% 88% 88% 88% 

Actual Emissions, tons per year 1.5 1.5 1.5 3.1 

Total Capital Requirement, $ $52,642,000 $39,963,000 $3,295,000 $0 

Capital Recovery Factor (CRF) 0.1098 0.1098 0.1098 0.1098 

Annual Capital Cost, $/yr $5,780,000 $4,388,000 $362,000 n/a 

Annual O&M Cost, $/yr $3,683,000 $3,025,000 $881,000 n/a 

Total Annual Cost, $/yr $9,463,000 $7,413,000 $1,243,000 $0 

Average Annual Cost, $/yr $9,463,000 $7,413,000 $1,243,000 

Average HF Reduction, tons per year 1.5 1.5 1.5 

Average Cost per Ton Reduced, $ per ton $6,137,800 $4,808,100 $806,200 

Incremental Annual Cost, $/yr $2,050,000 $6,170,000 

Incremental HF Reduction, tons per year 0 0 

Incremental Cost per Ton Reduced, $ per ton n/a n/a 

 Footnotes 

1. "Annual Capital Cost" or capital recovery cost is calculated by multiplying the capital recovery factor (CRF) by 

the Total Capital Requirement as detailed in the U.S. EPA's EPA Air Pollution Control Cost Manual - Sixth Edition 

(EPA 452/B-02-001): 

where: 

 i = annual interest rate = 7.0% 

 n = project life, years = 15 

5. The total annual cost is the sum of the annual capital costs and annual O&M costs. 

6. "Average Reduction" is the emissions of the uncontrolled boiler minus the emissions of the control option. 

7. "Average Cost per Ton Reduced" is the Average Annual Cost of the control option divided by the Average PM 

reduction of the control option: 

Control option annual cost Average Cost Effectiveness ($ per ton removed) = Baseline emission rate – Control option emissions rate 

8. "Incremental Annual Cost" is the Total Annual Cost of the control option minus the Total Annual Cost of the 

next most effective control option. 

9. "Incremental Reduction" is the Potential Emission Rate of the next most effective control option minus the 

Potential Emission Rate of the control option. 

10. "Incremental Cost per Ton Reduced" is the Incremental Annual Cost of the control option divided by the 

Incremental PM reduction of the control option: 

Control option annual cost – Next control option annual cost Incremental Cost ($ per ton removed) = Next control option emission rate – Control option emissions rate 

[ ] (1 ) 1

(1 )

+ −

+ = n

n

i

i i CRF
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9.6 STEP 5. Proposed Fluorides BACT Determination 

Based on this analysis, We Energies has concluded that the combustion of low fluorine containing 

biomass fuels is the best available control technology (BACT) for HF emissions from the biomass-fired 

boiler. Based on this analysis, We Energies proposes the following limits as BACT for the control of HF 

emissions from the biomass-fired, circulating fluidized bed boiler. 

(1) Hydrogen fluoride (HF) emissions from the biomass-fired boiler shall be controlled 

using biomass fuels and natural gas as the best available control technology. 

(a) Only natural gas and biomass fuels may be combusted in the boiler. 

(b) “Biomass fuels” means a resource that derives energy from wood or plant material or 

residue, clean solid wood waste and crops grown for use as a resource. Fuel sources may 

include the following and other qualifying clean sources: 

• logging residue 

• discarded woody material from primary manufacturing facilities such as paper mills, 

sawmills, or chip mills 

• on-site pulp & paper wastewater treatment plant residue 

• leftover woody material from secondary manufacturers such as door, window, 

cabinet manufacturers 

• woody biomass from municipality wood waste, tree services, and construction 

companies 

• clean solid wood waste from discarded wood packaging such as pallets/crating and 

from construction and demolition activities 

• woody biomass plantations, energy crops and agricultural residues 

“Biomass fuels” excludes edible portions of food crops, refuse derived fuel, treated 

wood, municipal solid waste, sewerage sludge, and animal waste.
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Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

Attachment 1. 

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction 

(SCR) system. 

Attachment 1.

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) system.

Page 1 and 2 of 8

Selective Catalytic Reduction (SCR) Control Technology Parameters1

.

Variable Description Value

Qb Boiler Size (mmBtu/hr)2 800

NOxin NOx inlet (lb/mmBtu) 0.15

NOxin NOx outlet (lb/mmBtu)4 0.06

Plant wide capacity factor5 88%

S Sulfur content of fuel (weight fraction)6 0.01

T Gas temperature (°F)7 650

NSCR Number of reactor chambers8 1

Variable Description Units Reference9 Value 

q fuel Volumetric flow rate for fuel ft3

/min-MMBtu/hr Table 2.4 516

q flue gas Flue gas flow rate10 acfm Calculated Value 323,789

ASR Actual Stoichiometric ratio (ASR) 2.11 1.05

Slip Theoretical ammonia slip11 ppm by volume Page 2-37 10.00

ηadj Efficiency adjustment factor 2.20 1.13

NOxadj NOx adjustment factor 2.21 0.90

Slipadj Ammonia slip adjustment factor 2.22 0.72

Sadj Sulfur in fuel adjustment factor 2.23 0.96

Tadj Temperature adjustment factor 2.24 1.15

NSCR Number of reactor chambers8 1.00

Volcatalyst Volume of catalyst ft3 2.19 1816

Acatalyst Catalyst cross sectional area ft2 2.25 337

ASCR Reactor cross sectional area ft2 2.26 388

l Length and width of reactor ft 2.27 19.7

h'layer Nominal catalyst height ft Page 2-38 3.1

nlayer Number of catalyst layers 2.28 2.0

hlayer Height of each catalyst layer ft 2.29 3.7

nempty Estimated # of empty catalyst layers Page 2-53 1.0

ntotal Total # of catalyst layers 2.30 3.0

C1 Page 2-39 7.0

C2 Page 2-39 9.0

hSCR Height of SCR reactor ft 2.31 41.1

Mreagent Molecular weight of ammonia g/mole Page 2-39 17.0

MNOx Molecular weight of NO2 g/mole Page 2-39 46.0

SRT Ratio of moles of NH3 per mole of reagent injected Page 1-24 1.0

mreagent Reagent mass flow rate12 lb/hr 2.32 37.3

Csol % concentration of aqueous reagent solution13 Page 2-40 0.19

Constants for hSCR equation-based on standard 

industry practice 

SCR Equation Inputs

SCR Parameter Estimates 

We Energies 50 MW Renewable Fuels-Fired Facility

Renewable Fuels-Fired Boiler Control Technology Review: Attachment 1.

RTP Environmental Associates, Inc.

3/4/2010
Attachment 1.

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) system.

Page 1 and 2 of 8

Selective Catalytic Reduction (SCR) Control Technology Parameters1

.

Variable Description Value

Qb Boiler Size (mmBtu/hr)2 800

NOxin NOx inlet (lb/mmBtu) 0.15

NOxin NOx outlet (lb/mmBtu)4 0.06

Plant wide capacity factor5 88%

S Sulfur content of fuel (weight fraction)6 0.01

T Gas temperature (°F)7 650

NSCR Number of reactor chambers8 1

Variable Description Units Reference9 Value 

SCR Equation Inputs

SCR Parameter Estimates 

msol Mass flow rate of aqueous ammonia solution lb/hr 2.33 196

ρsol Density of aqueous ammonia solution lb/ft3 Page 2-40 56

υsol Specific volume of aqueous ammonia solution gal/ft3 Page 2-40 7.48

qsol Solution volume gph 2.34 26.2

t Operating days14 days Page 2-54 14

Ammonia Tank Volume gal 2.35 8814

CFPlant Boiler capacity factor 2.7 0.88

qreagent Assuming same as qsol 23.08

top Total Operating Time hours/yr 1.22a 7708.8

ΔPduct Pressure drop (used mid-range value) inches H2O Page 2-46 2.5

ΔPcatalyst Pressure drop (used mid-range value) inches H2O Page 2-46 0.875

Power Electrical power consumption kW 2.48 224.12

Costelect Electrical power costs15 $/kWh 2.49 0.066

Footnotes

1

Calculations based on the EPA Air Pollution Control Cost Manual (CCM), 6th Edition, 2002, EPA/452/B-02-001. 

2

Gas temperature is assumed to be at 600 F before entering the SCR. 

3

It is assumed that NSCR is equal to nSCR based on example on page 2-53.

4

Equation number or page number as listed in CCM under SCR section. 

5

The ammonia slip must be between 2-5 ppm for the CCM equation to be valid. 

We Energies 50 MW Renewable Fuels-Fired Facility

Renewable Fuels-Fired Boiler Control Technology Review: Attachment 1.

RTP Environmental Associates, Inc.

3/4/2010
Attachment 1.

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) system.

Page 3 of 8

We Energies - 50MW Renewable Fuels-Fired Plant

Item Value

Operating Schedule

Plant Capacity Factor 88%

Total Operating Hours per Year 7,709 

 Shifts per day 3

 Hours per day 24

 Days per week 7

Boiler and SCR Parameters

Total Flue Gas Flowrate, acfm 323,789

SCR Operating Temperature, o

F (after reheat) 650

Uncontrolled NOx Emission Rate, lb/mmBtu 0.15

Total Heat Input Capacity 800

Total NOx Emissions at Plant Capacity Factor 463

SCR Control Efficiency, % 60

Electricity Cost, $/kWh 0.070

Operating Labor Cost, $ per hour $50

Maintenance Labor Cost, $ per hour $50

Economic and Financing Parameters

Economic Life, years 15

Interest Rate, % 7.0

We Energies 50 MW Renewable Fuels-Fired Facility

Renewable Fuels-Fired Boiler Control Technology Review: Attachment 1.

RTP Environmental Associates, Inc.

3/4/2010
Attachment 1.

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) system.

Page 4 of 8

Selective Catalytic Reduction (SCR) Equipment Costs1

Direct Cost Calculation

Variable Description Value 

f(hSCR) Adjustment for SCR reactor height, $ per mmBtu per hour 63.49 $ 

f(NH3 rate) Adjustment for ammonia flow rate, $ per mmBtu per hour (28.13) $ 

f(new) Adjustment for a new boiler, $ per mmBtu per hour - $ 

f(bypass) Adjustment for installing SCR bypass, $ per mmBtu per hour - $ 

CCinitial Initial catalyst cost, $/ft3 $ 240

f(Volcatalyst) Capital cost for initial charge of catalyst 1998 $ 435,861 $ 

DC Direct Capital Cost, 1998 $ 5,016,000 $ 

A Direct Capital Cost, 2009 $ 6,601,948 $ 

Total SCR Equipment Costs $ 6,602,000

Footnotes

1

Calculations based on the EPA Air Pollution Control Cost Manual (CCM), 6th Edition, 2002, EPA/452/B-02-001. 

2

Taken from example on page 2-50 of SCR section of CCM. 

3

CCM values are in 1998 dollars. Final cost values have been scaled to 2009 dollars using the consumer price index. 

4

The allowance for funds used during construction is based on 50% of construction work in progress.

We Energies 50 MW Renewable Fuels-Fired Facility

Renewable Fuels-Fired Boiler Control Technology Review: Attachment 1.

RTP Environmental Associates, Inc.

3/4/2010
Attachment 1.

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) system.

Page 5 of 8

Total Capital Requirements

Value Basis

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $6,602,000 See Page 2 of 8

 b.) Instrumentation $660,200 0.10 x A

 c.) Sales taxes

 d.) Freight $330,100 0.05 x A

 Total Purchased equipment cost, (PEC) $7,592,300 B

2.) Direct installation costs

 a.) Foundations and supports $379,600 0.10 x B

 b.) Pilings $379,600 0.10 x B

 c.) Handling and erection $1,518,500 0.20 x B

 d.) Electrical $75,900 0.01 x B

 e.) Piping $75,900 0.01 x B

 f.) Insulation for ductwork & painting $75,900 0.01 x B

 g.) Stack modification $151,800 0.02 x B

 Total direct installation cost $3,036,920 0.40 x B

3.) Site preparation (including demolition)

4.) Buildings

 Total Direct Cost, DC $10,629,200 1.30B + SP + Bldg.

Indirect Costs (installation)

5.) Engineering $759,200 0.10 x B

6.) Construction and field expenses $379,600 0.05 x B

7.) Contractor fees $759,200 0.10 x B

8.) Start-up $151,800 0.02 x B

9.) Performance test $75,900 0.01 x B

10.) Contingencies $1,518,500 0.2 x B

 Total Indirect Cost, IC $3,644,200 0.35 x B + Other

Total Capital Investment (TCI) = DC + IC $14,273,400 1.61B + SP + Bldg. + Other

We Energies 50 MW Renewable Fuels-Fired Facility

Renewable Fuels-Fired Boiler Control Technology Review: Attachment 1.

RTP Environmental Associates, Inc.

3/4/2010
Attachment 1.

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) system.

Page 6 of 8

Flue Gas Reheat Costs

Description Value

Total Flue Gas Flowrate1, scfm 323,789

Stack Temperature, o

F1 315

SCR Temperature, o

F 600

Flue Gas Reheat Temperature Rise, o

F 285

Density of flue gas at standard conditions2

, lb/ft3 0.0779

Mass flow rate of Flue Gas, lb/hour 1,512,985 

Heat Capacity of Flue Gas, Cp3

, Btu/lb-oF 0.24

Heat Recovery, % 95%

Required heat Input, mmBtu per hour, Q 5.17 

Reheat Requirements, mmBtu per year 39,888 

Heating Value of Natural Gas, mmBtu/106

 scf 1,050

Natural Gas Requirement, scf/year 37,989,034

Natural Gas Cost, $/1,000 scf 5.00 $ 

Total Reheat Natural Gas Cost, $ per year 189,945 $ 

Reheat Natural Gas NOx Emission Rate, lb/mmBtu 0.05

Reheat NOx Emissions, ton per year 1.00 

Footnotes

1

Based on the estimated flue gas flow for the boiler at full load.

2

Density of flue gas is based on a flue gas molecular weight of 29.57 lb/lb-mole.

3

The specific heat capacity (Cp) for combustion products is from 

http://www.engineeringtoolbox.com/spesific-heat-capacity-gases-d_159.html

We Energies 50 MW Renewable Fuels-Fired Facility

Renewable Fuels-Fired Boiler Control Technology Review: Attachment 1.

RTP Environmental Associates, Inc.

3/4/2010
Attachment 1.

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) system.

Page 7 and 8 of 8

Total Annual Costs

Value Basis Source

1) Electricity

Total Power Requirement, kW 75 Additional ID fan requirements. Estimate

Electric Power Cost ($/kWh) 0.070

 Cost ($/yr) $40,471

2) Operating Costs 

Operating Labor Requirement (hr/shift) 1 1 hour per shift Estimate

 Unit Cost, $ per hour $50.00 Estimate

 Labor Cost, $ per year $54,600

3) Ammonia Reagent Costs

 Ammonia Reagent Cost, $ per pound $0.81 Based on $1.30/gallon for 19% ammonia.

 Ammonia Input requirement, lb/hr 55.2 Based on 1.2 moles NH3 per mole of NOx.

 Annual Ammonia Requirement, lb/year 425,526

 Total Ammonia Costs ($/year) $346,606

4) Natural Gas Reheat Costs

Heat Input Requirement, mmBtu per hour 5.2 See Reheat Calculations

Total Cost $189,945

Total Operating Costs (1 + 2 + 3 +4) $631,623

5) Supervisory Labor

 Cost, $ per year $8,190 15% Operating Labor OAQPS

6) Maintenance

 Maintenance Labor Requirement, hr/year 161 1/2 hour per day Estimate

 Catalyst Replacement Labor Req., hr per year 200 800 hours every 2 years Estimate

 Unit Cost, $ per hour $50.00 Estimate

 Labor Cost, $ per year $18,030

 Material Cost, $ per year $18,030 100% of Maintenance Labor OAQPS

 Total Annual Cost ($/yr) $36,060

We Energies 50 MW Renewable Fuels-Fired Facility

Renewable Fuels-Fired Boiler Control Technology Review: Attachment 1.

RTP Environmental Associates, Inc.

3/4/2010
Attachment 1.

Cost estimates for a Tail Gas or Regenerative Selective Catalytic Reduction (SCR) system.

Page 7 and 8 of 8

Total Annual Costs

Value Basis Source

7) Catalyst Replacement

 Catalyst Cost $435,861 Catalyst cost: $400/ft3

 and 579 ft3 requirement

 Sales Tax

 Catalyst Life, years 4 n Estimate

 Interest Rate, % 7.0 i

 Capital Recovery Factor (CRF) 0.30 Ammortization of Catalyst OAQPS

 Annual Cost, $ per year $128,680

8) Indirect Annual Costs

 Overhead $59,310 60% of O&M Costs OAQPS

 Administration $285,470 2% of Total Capital Investment OAQPS

 Property Tax 1% of Total Capital Investment OAQPS

 Insurance $142,730 1% of Total Capital Investment OAQPS

 Capital Recovery Factor (CRF) 0.1098 OAQPS

 Capital Recovery $1,567,143

Total Indirect Cost, $ per year $2,054,653

Total Annualized Cost, $ per year $2,859,200

Footnotes

1. The annual cost of the total capital requirement is given by the capital recovery factor (CRF):

where: 

i = annual interest rate 7.0%

n = project life, years 15 [ ] (1 ) 1

(1 )

+ −

+ = n

n

i

i i CRF

We Energies 50 MW Renewable Fuels-Fired Facility

Renewable Fuels-Fired Boiler Control Technology Review: Attachment 1.

RTP Environmental Associates, Inc.

3/4/2010
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. March, 2010

Attachment 2. 

Cost estimates for wet and dry FGD systems from the U.S. EPA’s CUECost 

Air Pollution Control Systems Economics Spreadsheets, and cost estimates for 

sorbent injection. 

We Energies' 50 MW Renewable Fuels-Fired Facility

Control Technology Review

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s CUECost Air 

Pollution Control Systems Economics Spreadsheets.

INPUTS

Description Units Input 1 Input 2

General Plant Technical Inputs

Location - State Abbrev. WI WI

MW Equivalent of Flue Gas to Control System MW 50 50

Net Plant Heat Rate Btu/kWhr 15,000 15,000

Plant Capacity Factor % 88% 88%

Total Air Downstream of Economizer % 120% 120%

Air Heater Leakage % 12% 12%

Air Heater Outlet Gas Temperature °F 320 320

Inlet Air Temperature °F 45 45

Ambient Absolute Pressure In. of Hg 29.4 29.4

Pressure After Air Heater In. of H2O -12 -12

Moisture in Air lb/lb dry air 0.013 0.013

Ash Split:

 Fly Ash % 60% 90%

 Bottom Ash % 40% 10%

Seismic Zone Integer 1 1

Retrofit Factor Integer 1 1

 (1.0 = new, 1.3 = medium, 1.6 = difficult)

Select Coal (Pine Bark Used) Integer 8 8

Is Selected Coal a Powder River Basin Coal? Yes / No No No

Economic Inputs

Cost Basis -Year Dollars Year 2009 2009

Sevice Life (levelization period) Years 15 15

Inflation Rate % 3% 3%

After Tax Discount Rate (current $'s) % 9% 9%

AFDC Rate (current $'s) % 11% 11%

First-year Carrying Charge (current $'s) % 22% 22%

Levelized Carrying Charge (current $'s) % 17% 17%

First-year Carrying Charge (constant $'s) % 16% 16%

Levelized Carrying Charge (constant $'s) % 12% 12%

Sales Tax % 5.5% 5.5%

Escalation Rates:

 Consumables (O&M) % 3% 3%

 Capital Costs:

 Is Chem. Eng. Cost Index available? Yes / No Yes Yes

 If "Yes" input cost basis CE Plant Index. Integer 575.4 575.4

 If "No" input escalation rate. % 3% 3%

Construction Labor Rate $/hr $35 $35

Prime Contractor's Markup % 3% 3%

Operating Labor Rate $/hr $30 $30

Power Cost Mills/kWh 40 40

Steam Cost $/1000 lbs 3.5 3.5
We Energies' 50 MW Renewable Fuels-Fired Facility

Control Technology Review

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s CUECost Air 

Pollution Control Systems Economics Spreadsheets.

Limestone Forced Oxidation (Wet FGD or LSFO) Inputs

SO2 Removal Required % 92% 92%

L/G Ratio gal / 1000 acf 125 125

Design Scrubber with Dibasic Acid Addition? (1 = yes, 2 Integer 2 1

Adiabatic Saturation Temperature °F 127 127

Reagent Feed Ratio Factor 1.05 1.05

 (Mole CaCO3 / Mole SO2 removed)

Scrubber Slurry Solids Concentration Wt. % 15% 15%

Stacking, Landfill, Wallboard (1 = stacking, 2 = lanfill, 3 Integer 1 1

Number of Absorbers Integer 1 1

 (Max. Capacity = 700 MW per absorber)

Absorber Material (1 = alloy, 2 = RLCS) Integer 1 1

Absorber Pressure Drop in. H2O 6 6

Reheat Required ? Integer 2 1

 (1 = yes, 2 = no)

Amount of Reheat °F 0 25

Reagent Bulk Storage Days 60 60

Reagent Cost (delivered) $/ton $15 $15

Landfill Disposal Cost $/ton $30 $30

Stacking Disposal Cost $/ton $6 $6

Credit for Gypsum Byproduct $/ton $2 $2

Maintenance Factors by Area (% of Installed Cost)

 Reagent Feed % 5% 5%

 SO2 Removal % 5% 5%

 Flue Gas Handling % 5% 5%

 Waste / Byproduct % 5% 5%

 Support Equipment % 5% 5%

Contingency by Area (% of Installed Cost)

 Reagent Feed % 20% 20%

 SO2 Removal % 20% 20%

 Flue Gas Handling % 20% 20%

 Waste / Byproduct % 20% 20%

 Support Equipment % 20% 20%

General Facilities by Area (% of Installed Cost)

 Reagent Feed % 10% 10%

 SO2 Removal % 10% 10%

 Flue Gas Handling % 10% 10%

 Waste / Byproduct % 10% 10%

 Support Equipment % 10% 10%

Engineering Fees by Area (% of Installed Cost)

 Reagent Feed % 10% 10%

 SO2 Removal % 10% 10%

 Flue Gas Handling % 10% 10%

 Waste / Byproduct % 10% 10%

 Support Equipment % 10% 10%
We Energies' 50 MW Renewable Fuels-Fired Facility

Control Technology Review

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s CUECost Air 

Pollution Control Systems Economics Spreadsheets.

Lime Spray Dryer (Dry FGD or LSD) Inputs

SO2 Removal Required % 90% 90%

Adiabatic Saturation Temperature °F 127 127

Flue Gas Approach to Saturation °F 20 20

Spray Dryer Outlet Temperature °F 147 147

Reagent Feed Ratio Factor 0.92 0.92

 (Mole CaO / Mole Inlet SO2)

Recycle Rate Factor 30 30

 (lb recycle / lb lime feed)

Recycle Slurry Solids Concentration Wt. % 35% 35%

Number of Absorbers Integer 2 2

 (Max. Capacity = 300 MW per spray dryer)

Absorber Material Integer 1 1

 (1 = alloy, 2 = RLCS)

Spray Dryer Pressure Drop in. H2O 5 5

Reagent Bulk Storage Days 60 60

Reagent Cost (delivered) $/ton $65 $65

Dry Waste Disposal Cost $/ton $30 $30

Maintenance Factors by Area (% of Installed Cost)

 Reagent Feed % 5% 5%

 SO2 Removal % 5% 5%

 Flue Gas Handling % 5% 5%

 Waste / Byproduct % 5% 5%

 Support Equipment % 5% 5%

Contingency by Area (% of Installed Cost)

 Reagent Feed % 20% 20%

 SO2 Removal % 20% 20%

 Flue Gas Handling % 20% 20%

 Waste / Byproduct % 20% 20%

 Support Equipment % 20% 20%

General Facilities by Area (% of Installed Cost)

 Reagent Feed % 10% 10%

 SO2 Removal % 10% 10%

 Flue Gas Handling % 10% 10%

 Waste / Byproduct % 10% 10%

 Support Equipment % 10% 10%

Engineering Fees by Area (% of Installed Cost)

 Reagent Feed % 10% 10%

 SO2 Removal % 10% 10%

 Flue Gas Handling % 10% 10%

 Waste / Byproduct % 10% 10%

 Support Equipment % 10% 10%
We Energies' 50 MW Renewable Fuels-Fired Facility

Control Technology Review

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s CUECost Air 

Pollution Control Systems Economics Spreadsheets.

SUMMARY OF COSTS

Description Units Input 1 Input 2

SO2 Control Costs LSFO LSD

Total Capital Requirement (TCR) $ $52,642,028 $39,963,389

$/kW $1,053 $799

First Year Costs

 Fixed O&M $ $3,348,178 $2,555,287

$/kW-Yr 66.96 51.11

 Variable O&M $ $334,443 $469,375

$/kW-Yr 6.69 9.39
We Energies' 50 MW Renewable Fuels-Fired Facility

Control Technology Review

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

APC Technology Choices

INPUTS

Description Units Range Input 1

General Plant Technical Inputs

Location - State Abbrev. All States WI

MW Equivalent of Flue Gas to Control System MW 100-2000 50

Net Plant Heat Rate (w/o APC) Btu/kWhr 15,000

Plant Capacity Factor % 40-90% 88%

Percent Excess Air in Boiler % 120%

Air Heater Inleakage % 12%

Air Heater Outlet Gas Temperature °F 320

Inlet Air Temperature °F 45

Ambient Absolute Pressure In. of Hg 29.4

Pressure After Air Heater In. of H2O -12

Moisture in Air lb/lb dry air 0.013

Ash Split:

 Fly Ash % 60%

 Bottom Ash % 40%

Seismic Zone Integer 1-5 1

Retrofit Factor Integer 1.0-3.0 1.0

 (1.0 = new, 1.3 = medium, 1.6 = difficult)

Select Coal (Fuel) Integer 1-8 8

Is Selected Coal a Powder River Basin Coal? Yes / No See Column K No

Coals Available in Library

Coal 1, Wyoming PRB: 8,227 Btu, 0.37%

Coal 2, Armstrong, PA: 13,100 Btu, 2.6%

Coal 3, Jefferson, OH: 11,922 Btu, 3.43%

Coal 4, Logan, WV: 12,058 Btu, 0.89% S

Coal 5, No. 6 Illinois: 10,100 Btu, 4% S, 1

Coal 6, Rosebud, MT: 8,789 Btu, 0.56% S

Coal 7, Lignite, ND: 7,500 Btu, 0.94% S, 

Coal 8, Biomass: 5,679 Btu, 0.065% S, 1.

Economic Inputs

Cost Basis -Year Dollars Year 2009

Sevice Life (levelization period) Years 30

Inflation Rate % 3.00%

After Tax Discount Rate (current $'s) % 9.20%

AFDC Rate (current $'s) % 10.80%

First-year Carrying Charge (current $'s) % 22.30%

Levelized Carrying Charge (current $'s) % 16.90%

First-year Carrying Charge (constant $'s) % 15.70%

Levelized Carrying Charge (constant $'s) % 11.70%

Sales Tax % 5.5%

Escalation Rates:

 Consumables (O&M) % 3%

 Capital Costs:

NOTE: A difficult retrofit factor was used because this tailgas SCR system would control both the existing Boiler 4 and the 
We Energies' 50 MW Renewable Fuels-Fired Facility

Control Technology Review

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

INPUTS

Description Units Range Input 1

 Is Chem. Eng. Cost Index available? Yes / No Yes

 If "Yes" input cost basis CE Plant Index. Integer 575.4

 If "No" input escalation rate. % 3%

Construction Labor Rate $/hr $35

Prime Contractor's Markup % 3%

Operating Labor Rate $/hr $30

Power Cost Mills/kWh 40

Steam Cost $/1000 lbs 3.5

Limestone Forced Oxidation (LSFO) Inputs

SO2 Removal Required % 90-98% 92%

L/G Ratio gal / 1000 acf 95-160 125

Design Scrubber with Dibasic Acid Addition? Integer 1 or 2 2

 (1 = yes, 2 = no)

Adiabatic Saturation Temperature °F 100-170 127

Reagent Feed Ratio Factor 1.0-2.0 1.05

 (Mole CaCO3 / Mole SO2 removed)

Scrubber Slurry Solids Concentration Wt. % 15%

Stacking, Landfill, Wallboard Integer 1,2,3 1

 (1 = stacking, 2 = landfill, 3 = wallboard)

Number of Absorbers Integer 1-6 1

 (Max. Capacity = 700 MW per absorber)

Absorber Material Integer 1 or 2 1

 (1 = alloy, 2 = RLCS)

Absorber Pressure Drop in. H2O 6

Reheat Required ? Integer 1 or 2 2

 (1 = yes, 2 = no)

Amount of Reheat °F 0-50 25

Reagent Bulk Storage Days 60

Reagent Cost (delivered) $/ton $15

Landfill Disposal Cost $/ton $30

Stacking Disposal Cost $/ton $6

Credit for Gypsum Byproduct $/ton $2

Maintenance Factors by Area (% of Installed Cost)

 Reagent Feed % 5%

 SO2 Removal % 5%

 Flue Gas Handling % 5%

 Waste / Byproduct % 5%

 Support Equipment % 5%

Contingency by Area (% of Installed Cost)

 Reagent Feed % 20%

 SO2 Removal % 20%

 Flue Gas Handling % 20%

 Waste / Byproduct % 20%

 Support Equipment % 20%

General Facilities by Area (% of Installed Cost)

 Reagent Feed % 10%
We Energies' 50 MW Renewable Fuels-Fired Facility

Control Technology Review

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

INPUTS

Description Units Range Input 1

 SO2 Removal % 10%

 Flue Gas Handling % 10%

 Waste / Byproduct % 10%

 Support Equipment % 10%

Engineering Fees by Area (% of Installed Cost)

 Reagent Feed % 10%

 SO2 Removal % 10%

 Flue Gas Handling % 10%

 Waste / Byproduct % 10%

 Support Equipment % 10%

Lime Spray Dryer (LSD) Inputs

SO2 Removal Required % 90-95% 90%

Adiabatic Saturation Temperature °F 100-170 127

Flue Gas Approach to Saturation °F 10.-50 20

Spray Dryer Outlet Temperature °F 110-220 147

Reagent Feed Ratio Factor Calc. Based on %S 0.92

 (Mole CaO / Mole Inlet SO2)

Recycle Rate Factor Calculated 30

 (lb recycle / lb lime feed)

Recycle Slurry Solids Concentration Wt. % 10-50 35%

Number of Absorbers Integer 1-7 2

 (Max. Capacity = 300 MW per spray dryer)

Absorber Material Integer 1 or 2 1

 (1 = alloy, 2 = RLCS)

Spray Dryer Pressure Drop in. H2O 5

Reagent Bulk Storage Days 60

Reagent Cost (delivered) $/ton $65

Dry Waste Disposal Cost $/ton $30

Maintenance Factors by Area (% of Installed Cost)

 Reagent Feed % 5%

 SO2 Removal % 5%

 Flue Gas Handling % 5%

 Waste / Byproduct % 5%

 Support Equipment % 5%

Contingency by Area (% of Installed Cost)

 Reagent Feed % 20%

 SO2 Removal % 20%

 Flue Gas Handling % 20%

 Waste / Byproduct % 20%

 Support Equipment % 20%

General Facilities by Area (% of Installed Cost)

 Reagent Feed % 10%

 SO2 Removal % 10%

 Flue Gas Handling % 10%

 Waste / Byproduct % 10%

 Support Equipment % 10%
We Energies' 50 MW Renewable Fuels-Fired Facility

Control Technology Review

Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Wet Limestone Forced Oxidation (LSFO) Material Balance Case1

Flue Gas, Downstream of ID Fans

 Temperature °F 315

 Pressure in. H2O 10

 Flow Rate SCFM 198,301

 Flow Rate ACFM 293,441

 CO2 lb/hr 167,122

 N2 lb/hr 576,106

 SO2 lb/hr 172

 O2 lb/hr 47,567

 HCl lb/hr 0

 Other Gases lb/hr 87

 H2O lb/hr 98,944

 Fly Ash lb/hr 11

 Total (gas only) lb/hr 889,998

Flue Gas, to Absorber

 Temperature °F 315

 Pressure in. H2O 10

 Flow Rate SCFM 198,301

 Flow Rate ACFM 293,441

 CO2 lb/hr 167,122

 N2 lb/hr 576,106

 SO2 lb/hr 172

 O2 lb/hr 47,567

 HCl lb/hr 0

 Other Gases lb/hr 87

 H2O lb/hr 98,944

 Fly Ash lb/hr 11

 Total (gas only) lb/hr 889,998

Flue Gas, from Absorbers (total)

 Temperature °F 127

 Pressure in. H2O 4

 Flow Rate SCFM 190,072

 Flow Rate ACFM 216,196

 CO2 lb/hr 167,230

 N2 lb/hr 576,628

 SO2 lb/hr 14

 O2 lb/hr 47,685

 HCl lb/hr 0

 Other Gases lb/hr 87

 H2O lb/hr 75,092

 Fly Ash lb/hr 11

 Total (gas only) lb/hr 866,737

 Heat Capacities
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

 O2 Btu/lbmol°F 7.203

 CO2 Btu/lbmol°F 9.263

 N2 Btu/lbmol°F 6.990

 H2O Btu/lbmol°F 8.048

 NO Btu/lbmol°F 7.151

 SO2 Btu/lbmol°F 9.771

 HCl Btu/lbmol°F 6.951

 O2 Btu/lb°F 0.225

 CO2 Btu/lb°F 0.210

 N2 Btu/lb°F 0.249

 H2O Btu/lb°F 0.447

 NO Btu/lb°F 0.238

 SO2 Btu/lb°F 0.153

 HCl Btu/lb°F 0.191

 Reheated Gas Temperature: °C 52.8

K 325.8

 FGD Outlet Temperature: °C 52.8

K 325.8

 Total Btu/hr Btu/hr 0

Hot Reheat Air

 Temperature °F 440

 Pressure in. H2O 1

 Flow Rate SCFM 0

 Flow Rate ACFM 0

 N2 lb/hr 0

 O2 lb/hr 0

 H2O lb/hr 0

 Total lb/hr 0

 Heat Capacities of Hot Reheat Air

 O2 Btu/lbmol°F 7.322

 N2 Btu/lbmol°F 7.104

 H2O Btu/lbmol°F 8.316

 O2 Btu/lb°F 0.229

 N2 Btu/lb°F 0.254

 H2O Btu/lb°F 0.462

 Heated Temperature: °C 226.7

K 499.7

 FGD Outlet Temperature: °C 52.8

K 325.8

 Heat Capacities of Inlet Reheat Air

 O2 Btu/lbmol°F 7.291

 N2 Btu/lbmol°F 7.074

 H2O Btu/lbmol°F 8.246

 O2 Btu/lb°F 0.228

 N2 Btu/lb°F 0.252

 H2O Btu/lb°F 0.458

 Heated Temperature: °C 226.7
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

K 499.7

 Inlet Air Temperature: °C 7.2

K 280.2

 Required Heat Btu/hr 0

Oxidation Air (total)

 Temperature °F 60

 Pressure in. H2O 0

 Flow Rate SCFM 152

 Flow Rate ACFM 155

 N2 lb/hr 523

 O2 lb/hr 158

 H2O lb/hr 9

 Total (gas only) lb/hr 689

Limestone to Ball Mill

 Temperature °F 45

 Wt.% Solids wt. % 100%

 Inerts lb/hr 13

 CaCO3 lb/hr 259

 Total lb/hr 272

Limestone Slurry to Limestone Slurry Tank

 Temperature °F 90

 Flow Rate GPM 1.0

 Wt.% Solids wt. % 40%

 Inerts lb/hr 13

 CaCO3 lb/hr 259

 H2O lb/hr 407

 Total lb/hr 679

Limestone Slurry to Reaction Mix Tank (total)

 Temperature °F 68

 Flow Rate GPM 2.3

 Wt.% Solids wt. % 20%

 Inerts lb/hr 13

 CaCO3 lb/hr 259

 H2O lb/hr 1,086

 Total lb/hr 1,358

Slurry to Absorber

 Temperature °F 126

 Flow Rate GPM 26,694

 Wt.% Solids wt. % 15%

 CaSO3*1/2H2O lb/hr 0

 CaSO4*2H2O lb/hr 2,175,508

 Inerts lb/hr 65,491
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

 CaCl2 lb/hr 0

 CaCO3 lb/hr 63,235

 H2O lb/hr 13,057,321

 Total lb/hr 15,361,554

Slurry from Rxn Tank to Thickener

 Temperature °F 126

 Flow Rate GPM 5.2

 Wt.% Solids wt. % 15%

 CaSO3*1/2H2O lb/hr 0

 CaSO4*2H2O lb/hr 424

 Inerts lb/hr 13

 CaCl2 lb/hr 0

 CaCO3 lb/hr 12

 H2O lb/hr 2,545

 Total lb/hr 2,994
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Wet Limestone Forced Oxidation Equipment Capital Costs Case1

Cost Basis (Year) 2009

Sizing Criteria

Reagent Feed System $ kpph Reag. $10,584,021

 Ball Mill & Hydroclone System $ TPH Reag. $2,755,315

 DBA Acid Tank (pump, heater, agitator) $ gpm DBA $0

SO2 Removal System $ kpph SO2 $2,834,389

 Absorber Tower $ kACFM $8,397,987

 Spray Pumps $ slurry gpm $583,546

Flue Gas Handling System $ * $3,061,861

 ID Fans $ ACFM $963,037

Waste / Byproduct Handling System $ kpph SO2 $120,132

 Thickener System $ TPH solids $172,898

Support Equipment $ MW $1,890,418

 Chimney $ ACFM $4,213,622

TOTAL $ $35,577,227

* Based on flue gas flow and reheat temperature.

Capital Costs with Retrofit Factors

Reagent Feed System $ $10,584,021

 Ball Mill & Hydroclone System $ $2,755,315

 DBA Acid Tank (pump, heater, agitator) $ $0

SO2 Removal System $ $2,834,389

 Absorber Tower $ $8,397,987

 Spray Pumps $ $583,546

Flue Gas Handling System $ $3,061,861

 ID Fans $ $963,037

Waste / Byproduct Handling System $ $120,132

 Thickener System $ $172,898

Support Equipment $ $1,890,418

 Chimney $ $4,213,622

TOTAL $ $35,577,227

General Facilities

Reagent Feed System $ $1,058,402

 Ball Mill & Hydroclone System $ $275,532

 DBA Acid Tank (pump, heater, agitator) $ $0

SO2 Removal System $ $283,439

 Absorber Tower $ $839,799

 Spray Pumps $ $58,355

Flue Gas Handling System $ $306,186
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

 ID Fans $ $96,304

Waste / Byproduct Handling System $ $12,013

 Thickener System $ $17,290

Support Equipment $ $189,042

 Chimney $ $421,362

TOTAL $ $3,557,723

Engineering Fees

Reagent Feed System $ $1,058,402

 Ball Mill & Hydroclone System $ $275,532

 DBA Acid Tank (pump, heater, agitator) $ $0

SO2 Removal System $ $283,439

 Absorber Tower $ $839,799

 Spray Pumps $ $58,355

Flue Gas Handling System $ $306,186

 ID Fans $ $96,304

Waste / Byproduct Handling System $ $12,013

 Thickener System $ $17,290

Support Equipment $ $189,042

 Chimney $ $421,362

TOTAL $ $3,557,723

Contingency

Reagent Feed System $ $2,116,804

 Ball Mill & Hydroclone System $ $551,063

 DBA Acid Tank (pump, heater, agitator) $ $0

SO2 Removal System $ $566,878

 Absorber Tower $ $1,679,597

 Spray Pumps $ $116,709

Flue Gas Handling System $ $612,372

 ID Fans $ $192,607

Waste / Byproduct Handling System $ $24,026

 Thickener System $ $34,580

Support Equipment $ $378,084

 Chimney $ $842,724

TOTAL $ $7,115,445

Total Plant Cost (TPC) $ $49,808,118

Total Plant Cost (TPC) w/ Prime Contractor's Markup $ $51,302,361

Total Cash Expended (TCE) $ $51,302,361

Allow. for Funds During Constr. (AFDC) $ $0
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Total Plant Investment (TPI) $ $51,302,361

 Preproduction Costs $ $1,336,733

 Inventory Capital $ $2,933

Total Capital Requirement (TCR) $ $52,642,028

$/kW $1,053

Maintenance Cost by Area Case1

TPC w/o Retrofit Factor

Reagent Feed System $ $15,240,990

 Ball Mill & Hydroclone System $ $3,967,654

 DBA Acid Tank (pump, heater, agitator) $ $0

SO2 Removal System $ $4,081,520

 Absorber Tower $ $12,093,102

 Spray Pumps $ $840,307

Flue Gas Handling System $ $4,409,080

 ID Fans $ $1,386,774

Waste / Byproduct Handling System $ $172,990

 Thickener System $ $248,973

Support Equipment $ $2,722,203

 Chimney $ $6,067,615

TOTAL $ $51,231,207

First Year Maintenance Costs

Reagent Feed System $ $762,049

 Ball Mill & Hydroclone System $ $198,383

 DBA Acid Tank (pump, heater, agitator) $ $0

SO2 Removal System $ $204,076

 Absorber Tower $ $604,655

 Spray Pumps $ $42,015

Flue Gas Handling System $ $220,454

 ID Fans $ $69,339

Waste / Byproduct Handling System $ $8,649

 Thickener System $ $12,449

Support Equipment $ $136,110

 Chimney $ $303,381

TOTAL $ $2,561,560

LSFO O&M Data and Costs Case1
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Cost Basis (Year) 2009

Parameters

 Reagent Required lbs/hr 272

lbs/MMBtu 0.362

 DBA Required lbs/hr 0.0

 Percent SO2 Removal % 92%

 FGD Sludge to Disposal lbs/hr, dry 449

 Steam to FGD System lbs/hr 0

 Total FGD Power Consumption kW 1,000

 FGD Byproduct lbs/hr 0

Fixed O&M Costs

 Number of Operators 6

 (40 hrs/week)

 Operating Labor Cost ** $/yr $368,639

 Maint. Labor & Matls. Cost $/yr $2,561,560

 Admin. & Support Labor $/yr $417,979

 TOTAL $/yr $3,348,178

Variable Operating Costs **

 Reagent Costs $/yr $15,704

 DBA Costs $/yr $0

 Disposal Costs $/yr $10,387

 Credit for Byproduct $/yr $0

 Steam Costs $/yr $0

 Power Costs $/yr $308,352

 TOTAL $/yr $334,443

** These costs assume inputs are in current dollars (no escalation included).
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Lime Spray Dryer (LSD or Dry FGD) Material Balance - Prel Case 2

Flue Gas, Downstream of Air Heater

 Temperature °F 320

 Pressure in. H2O -12

 Flow Rate SCFM 198,301

 Flow Rate ACFM 312,068

 CO2 lb/hr 167,122

 N2 lb/hr 576,106

 SO2 lb/hr 172

 O2 lb/hr 47,567

 HCl lb/hr 0

 Other Gases lb/hr 87

 H2O lb/hr 98,944

 Fly Ash lb/hr 2,447

 Total (gas only) lb/hr 889,998

Flue Gas, to Spray Dryer

 Temperature °F 320

 Pressure in. H2O -12

 Flow Rate SCFM 99,151

 Flow Rate ACFM 156,034

 CO2 lb/hr 83,561

 N2 lb/hr 288,053

 SO2 lb/hr 86

 O2 lb/hr 23,783

 HCl lb/hr 0

 Other Gases lb/hr 44

 H2O lb/hr 49,472

 Fly Ash lb/hr 1,223

 Total (gas only) lb/hr 444,999

Flue Gas, from Spray Dryers (total)

 Temperature °F 147

 Pressure in. H2O -17

 Flow Rate SCFM 221,629

 Flow Rate ACFM 274,963

 CO2 lb/hr 167,122

 N2 lb/hr 576,106

 SO2 lb/hr 48

 O2 lb/hr 47,559

 HCl lb/hr 0

 Other Gases lb/hr 87

 H2O lb/hr 165,387

 Fly Ash lb/hr 6,548

 Total (gas only) lb/hr 956,309
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Flue Gas Downstream of Particulate Control Device

 Temperature °F 147

 Pressure in. H2O -23

 Flow Rate SCFM 221,579

 Flow Rate ACFM 279,272

 CO2 lb/hr 167,122

 N2 lb/hr 576,106

 SO2 lb/hr 17

 O2 lb/hr 47,557

 HCl lb/hr 0

 Other Gases lb/hr 87

 H2O lb/hr 165,254

 Fly Ash lb/hr 11

 Total (gas only) lb/hr 956,143

Flue Gas Downstream of ID Fans

 Temperature °F 152

 Pressure in. H2O 1

 Flow Rate SCFM 221,579

 Flow Rate ACFM 264,732

 CO2 lb/hr 167,122

 N2 lb/hr 576,106

 SO2 lb/hr 17

 O2 lb/hr 47,557

 HCl lb/hr 0

 Other Gases lb/hr 87

 H2O lb/hr 165,254

 Fly Ash lb/hr 11

 Total (gas only) lb/hr 956,143

Lime to Ball Mill

 Temperature °F 60

 Wt.% Solids wt. % 100%

 Inerts lb/hr 15

 CaO lb/hr 138

 Total lb/hr 153

Water to Ball Mill

 Temperature °F 60

 Flow Rate GPM 1

 Wt.% Solids wt. % 0%

 H2O lb/hr 505

 Total lb/hr 505

Lime Slurry to Head Tanks (Total)

 Temperature °F 110

 Flow Rate GPM 1

 Wt.% Solids wt. % 30%

 Ca(OH)2 lb/hr 182

 Inerts lb/hr 15

 H2O lb/hr 461

 Total lb/hr 658
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Lime Slurry from Head Tank

 Temperature °F 110

 Flow Rate GPM 10

 Wt.% Solids wt. % 35%

 CaSO3*1/2H2O lb/hr 185

 CaSO4*2H2O lb/hr 82

 Flyash / Inerts lb/hr 1,987

 Ca(OH)2 lb/hr 96

 CaCl2 lb/hr 70

 H2O lb/hr 4,413

 Total lb/hr 6,833

Lime Slurry to Atomizer

 Temperature °F 104

 Flow Rate GPM 67

 Wt.% Solids wt. % 7%

 CaSO3*1/2H2O lb/hr 185

 CaSO4*2H2O lb/hr 82

 Flyash / Inerts lb/hr 1,987

 Ca(OH)2 lb/hr 96

 CaCl2 lb/hr 70

 H2O lb/hr 33,234

 Total lb/hr 35,655

Solids from Spray Dryers (Total)

 Temperature °F 150

 Wt.% Solids wt. % 98%

 CaSO3*1/2H2O lb/hr 56

 CaSO4*2H2O lb/hr 25

 Flyash / Inerts lb/hr 642

 Ca(OH)2 lb/hr 5

 CaCl2 lb/hr 0

 H2O lb/hr 15

 Total lb/hr 742

Baghouse/ESP Solids to Recycle

 Particulate Removal Efficiency % 99.83%

 Temperature °F 150

 Wt.% Solids wt. % 98%

 CaSO3*1/2H2O lb/hr 315

 CaSO4*2H2O lb/hr 140

 Flyash / Inerts lb/hr 3,317

 Ca(OH)2 lb/hr 5

 CaCl2 lb/hr 140

 H2O lb/hr 77

 Total lb/hr 3,854
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Recycle Solids to Slurry Tank

 Temperature °F 150

 Wt.% Solids wt. % 98%

 CaSO3*1/2H2O lb/hr 370

 CaSO4*2H2O lb/hr 165

 Flyash / Inerts lb/hr 3,960

 Ca(OH)2 lb/hr 10

 CaCl2 lb/hr 140

 H2O lb/hr 92

 Total lb/hr 4,736

Blowdown Water to Recycle Solids Tank

 Temperature °F 60

 Flow Rate GPM 17

 Wt.% Solids wt. % 0%

 H2O lb/hr 8,273

 Total lb/hr 8,273

Recycle Slurry to Head Tanks (Total)

 Temperature °F 110

 Flow Rate GPM 19

 Wt.% Solids wt. % 35%

 CaSO3*1/2H2O lb/hr 370

 CaSO4*2H2O lb/hr 165

 Flyash / Inerts lb/hr 3,960

 Ca(OH)2 lb/hr 10

 CaCl2 lb/hr 140

 H2O lb/hr 8,365

 Total lb/hr 13,009

Dry Solids

 Temperature °F 100

 Wt.% Solids wt. % 98%

 CaSO3*1/2H2O lb/hr 232

 CaSO4*2H2O lb/hr 103

 Flyash / Inerts lb/hr 2,452

 Ca(OH)2 lb/hr 4

 CaCl2 lb/hr 0

 H2O lb/hr 57

 Total lb/hr 2,848

Solids to Landfill

 Temperature °F 100

 Wt.% Solids wt. % 80%

 CaSO3*1/2H2O lb/hr 232

 CaSO4*2H2O lb/hr 103

 Flyash / Inerts lb/hr 2,452

 Ca(OH)2 lb/hr 4

 CaCl2 lb/hr 0

 H2O lb/hr 698

 Total lb/hr 3,489
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

Lime Spray Dryer (LSD) Equipment Capital Costs Case 2

Cost Basis (Year) 2009

Sizing Criteria

Reagent Feed System $ * $5,729,193

SO2 Removal System $ Wt. % S $2,470,418

 Spray Dryers $ kACFM $8,658,475

Flue Gas Handling System $ kACFM $1,829,117

 ID Fans $ ACFM $720,271

Waste / Byproduct Handling System $ kpph SO2 $1,522,152

Support Equipment $ MW $2,205,055

 Chimney $ ACFM $3,855,901

TOTAL $ $26,990,583

* Based on lbs/hr of lime feed and GPM of lime slurry.

Capital Costs with Retrofit Factors

Reagent Feed System $ $5,729,193

SO2 Removal System $ $2,470,418

 Spray Dryers $ $8,658,475

Flue Gas Handling System $ $1,829,117

 ID Fans $ $720,271

Waste / Byproduct Handling System $ $1,522,152

Support Equipment $ $2,205,055

 Chimney $ $3,855,901

TOTAL $ $26,990,583

General Facilities

Reagent Feed System $ $572,919

SO2 Removal System $ $247,042

 Spray Dryers $ $865,848

Flue Gas Handling System $ $182,912

 ID Fans $ $72,027

Waste / Byproduct Handling System $ $152,215

Support Equipment $ $220,506

 Chimney $ $385,590

TOTAL $ $2,699,058

Engineering Fees

Reagent Feed System $ $572,919

SO2 Removal System $ $247,042

 Spray Dryers $ $865,848

Flue Gas Handling System $ $182,912
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

 ID Fans $ $72,027

Waste / Byproduct Handling System $ $152,215

Support Equipment $ $220,506

 Chimney $ $385,590

TOTAL $ $2,699,058

Contingency

Reagent Feed System $ $1,145,839

SO2 Removal System $ $494,084

 Spray Dryers $ $1,731,695

Flue Gas Handling System $ $365,823

 ID Fans $ $144,054

Waste / Byproduct Handling System $ $304,430

Support Equipment $ $441,011

 Chimney $ $771,180

TOTAL $ $5,398,117

Total Plant Cost (TPC) $ $37,786,817

Total Plant Cost (TPC) w/ Prime Contractor's Markup $ $38,920,421

Total Cash Expended (TCE) $ $38,920,421

Allow. for Funds During Constr. (AFDC) $ $0

Total Plant Investment (TPI) $ $38,920,421

 Preproduction Costs $ $1,035,797

 Inventory Capital $ $7,170

Total Capital Requirement (TCR) $ $39,963,389

$/kW $799

Maintenance Cost by Area Case 2

TPC w/o Retrofit Factor

Reagent Feed System $ $8,250,039

SO2 Removal System $ $3,557,403

 Spray Dryers $ $12,468,204

Flue Gas Handling System $ $2,633,928

 ID Fans $ $1,037,190

Waste / Byproduct Handling System $ $2,191,899

Support Equipment $ $3,175,280

 Chimney $ $5,552,498
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s 

CUECost Air Pollution Control Systems Economics Spreadsheets.

TOTAL $ $38,866,440

First Year Maintenance Costs

Reagent Feed System $ $412,502

SO2 Removal System $ $177,870

 Spray Dryers $ $623,410

Flue Gas Handling System $ $131,696

 ID Fans $ $51,859

Waste / Byproduct Handling System $ $109,595

Support Equipment $ $158,764

 Chimney $ $277,625

TOTAL $ $1,943,322

LSD O&M Data and Costs Case 2

Cost Basis (Year) 2009

Parameters

 Reagent Required lbs/hr 153

lbs/MMBtu 0.204

 Percent SO2 Removal % 90%

 FGD Solids - dry lbs/hr 2,792

 - wetted lbs/hr 3,489

 Fresh Water to FGD gpm 1

 Blowdown Water to FGD gpm 75

 Total FGD Power Consumption kW 350

Fixed O&M Costs

 Number of Operators 5

 (40 hrs/week)

 Operating Labor Cost ** $/yr $291,358

 Maint. Labor & Matls. Cost $/yr $1,943,322

 Admin. & Support Labor $/yr $320,606

 TOTAL $/yr $2,555,287

Variable Operating Costs **

 Reagent Costs $/yr $38,382

 Disposal Costs $/yr $322,790

 Credit for Byproduct $/yr $0

 Steam Costs $/yr $0

 Fresh Water Costs $/yr $280

 Power Costs $/yr $107,923

 TOTAL $/yr $469,375
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s CUECost Air 

Pollution Control Systems Economics Spreadsheets.

Cost estimates for a dry sorbent injection system (2 pages).

Facility Input Data

Item

Economic Life, years 15

Interest Rate (%) 7

Source(s) Controlled

Total Uncontrolled SO2 Emissions 278

Site Specific Electricity Cost ($/kWh) 0.07

Site Specific Operating Labor Cost ($/hr) $50

Site Specific Maint. Labor Cost ($/hr) $50

Capital Costs

Value

Direct Costs

1.) Purchased Equipment Cost

 a.) Equipment cost + auxiliaries $1,500,000

 b.) Instrumentation $150,000

 c.) Sales taxes

 d.) Freight $75,000

 Total Purchased equipment cost, (PEC) $1,725,000

2.) Direct installation costs

 a.) Foundations and supports $138,000

 b.) Handling and erection $241,500

 c.) Electrical $69,000

 d.) Piping $34,500

 e.) Insulation for ductwork $17,300

 f.) Painting $17,300

 Total direct installation cost $517,600

3.) Total site preparation including demolition $517,600

4.) Buildings NA

 Total Direct Cost, DC $2,760,200

Indirect Costs (installation)

5.) Engineering $172,500

6.) Construction and field expenses $86,300

7.) Contractor fees $172,500

8.) Start-up $34,500

9.) Performance test $17,300

10.) Contingencies $51,800

 Total Indirect Cost, IC $534,900

Total Capital Investment (TCI) = DC + IC $3,295,000

0.10 x B

0.03 x B

0.31B + Other

1.61B + SP + Bldg. + Other

0.05 x B

0.10 x B

0.02 x B

0.01 x B

0.02 x B

As Required, Bldg.

1.30B + SP + Bldg.

0.05 x A

Larry Sorrels, OAQPS Memo. Feb. 2, 

B = 1.22 x A

0.01 x B

0.01 x B

0.30 x B

0.08 x B

0.14 x B

0.04 x B

EPA-452/F-03-034

0.10 x A

0.07 x A

Basis

Value

Biomass-Fired Boiler
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Attachment 2. Cost estimates for wet and dry FGD systems from the U.S. EPA’s CUECost Air 

Pollution Control Systems Economics Spreadsheets.

Cost estimates for a dry sorbent injection system (2 pages).

Annual Costs

Item Value Basis Source

1) Electricity

Fan Power Requirement (kW) 100 

Pumping (kW) 50 

Electric Power Cost ($/kWh) 0.07 Local Utility Price Utility

 Cost ($/yr) $36,792

2) Operating Costs 

Operating Labor Requirement (hr/shift) 4.0 Estimate

 Unit Cost ($/hr) $50 Facility Data Estimate

 Labor Cost ($/yr) $218,400

Sodium Bicarbonate Cost

Unit Cost ($/ton) $497 FMC Corp. Bulk Chemical Cost

Sodium Bicarbonate Cost ($/yr) $241,370

Disposal Costs ($/ton) $40

 Tons Disposal required (tons/year) 347

 Disposal Costs ($/year) $13,876

Total Operating Costs $510,438 Vendor 

3) Supervisory Labor

 Cost ($/yr) $32,760 15% Operating Labor OAQPS

4) Maintenance

 Labor Cost ($/yr) $27,600 1% of installed cost Estimate

 Material Cost ($/yr) $27,600 100% of Maint. Labor OAQPS

 Total Cost ($/yr) $55,200

5) Indirect Annual Costs

 Overhead $183,820 60% of O&M Costs OAQPS

 Administration $65,900 2% of TCI OAQPS

 Property Tax 1% of TCI OAQPS

 Insurance $32,950 1% of TCI OAQPS

 Capital Recovery $361,770

Total Indirect ($/yr) $644,440

Total Annualized Cost ($/yr) $1,242,800
Prevention of Significant Deterioration 

Air Pollution Control Construction Permit Application 

Appendix B. 

Control Technology Review for the 

Natural Gas-Fired Boilers. 

50 MW Biomass-Fired Cogeneration Facility to be 

Located at the Domtar – Rothschild Mill.

March, 2010 

Prepared for: 

We Energies 

231 W. Michigan St. 

Milwaukee, WI 53203 

Prepared By: 

 

RTP ENVIRONMENTAL ASSOCIATES INC.® 

903 Superior Avenue, Suite 6 

Tomah, WI 54660 

We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

- 2 -

Executive Summary 

This document is a Control Technology Review for two new natural gas-fired package boilers, designated 

as Boilers B02 and B03, at the We Energies’ 50 MW Biomass Fuels Plant in Rothschild. This control 

technology review is required for major new sources under the Prevention of Significant Deterioration 

(PSD) program under NR 405.08, Wis. Adm. Code. 

The proposed boilers will be package boilers designed to provide up to 125,000 pounds per hour of steam. 

To deliver this steaming capacity, each boiler will have a maximum design heat input capacity of 175 

million Btu per hour. The only boiler fuel will be natural gas. Each boiler will be equipped with ultralow NOx burners and flue gas recirculation to control emissions of CO, NOx, PM/PM10, PM2.5, and VOCs. 

Table ES-1 summarizes the proposed emission limits which represent the best available control 

technology (BACT) for these new package boilers, and the potential emissions for each boiler. The 

proposed BACT conditions are summarized in Table ES-2. 

TABLE ES-1. Proposed emission limits representing BACT for each package boiler B02 and B03. 

POLLUTANT PROPOSED LIMIT, 

lb/mmBtu 

POTENTIAL TO EMIT, 

ton/year 

Carbon Monoxide CO 0.06 32.6 

Nitrogen Oxides NOx 0.02 10.9 

Particulate Matter PM/PM10 0.0076 4.1 

PM < 2.5 microns PM2.5 0.0076 4.1 

Sulfur Dioxide SO2 0.0006 0.3 

Organic Compounds VOC 0.006 3.3 

Fluorides (as HF) HF n/a 0.3 
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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TABLE ES-2. Proposed control technologies and emission limits representing BACT for the 

natural gas-fired Boilers B02 and B03. 

Pollutant Proposed Control Technology and Emission Limits 

Carbon Monoxide 

(CO) 

(1) CO emissions shall be controlled using good combustion practices as BACT. 

(2) CO emissions may not exceed 0.06 lb/mmBtu, based on a 30-day rolling 

average. 

Nitrogen Oxides 

(NOx) 

(1) NOx emissions shall be controlled using Ultra Low NOx Burners and Flue Gas 

Recirculation in combination with good combustion practices as BACT. 

(2) NOx emissions may not exceed 0.02 lb/mmBtu, based on a 30-day rolling 

average. 

Particulate Matter 

(PM) and PM10

(1) PM and PM10 emissions shall be controlled using natural gas as fuel and good 

combustion practices as BACT. 

(2) PM and PM10 emissions may not exceed 0.0076 lb/mmBtu. 

PM2.5

(1) PM2.5 emissions shall be controlled using natural gas as fuel and good 

combustion practices as BACT.. 

(2) PM2.5 emissions may not exceed 0.0076 lb/mmBtu. 

Sulfur Dioxide 

(SO2) 

(1) SO2 emissions shall be controlled using natural gas as fuel as BACT. 

(2) SO2 emissions may not exceed 0.0006 lb/mmBtu. 

Organic 

Compounds (VOC) 

(1) VOC emissions shall be controlled using good combustion practices as BACT. 

(2) VOC emissions may not exceed 0.006 pounds per million Btu of heat input. 

Fluorides (as HF) (1) Fluoride (as HF) emissions shall be controlled using natural gas as fuel as 

BACT. 
We Energies - Air Pollution Control Construction Permit Application for a 

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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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Table of Contents 

Chapter 1. Introduction and Source Description................................................8

Chapter 2. Control Technology Review Methodology......................................10

2.1 Best Available Control Technology Definition. ............................................................................ 10

2.2 Top Down BACT Methodology. ................................................................................................... 11

2.3 New Versus Modified Facilities. ................................................................................................... 11

2.4 Identifying Potential Control Technologies................................................................................... 12

2.5 Technical Feasibility...................................................................................................................... 12

2.6 Economic Feasibility. .................................................................................................................... 13

2.6.1 Average Cost Effectiveness. ............................................................................................. 13

2.6.2 Incremental Cost Effectiveness......................................................................................... 14

2.6.3 Agency Decisions on Cost Effectiveness. ........................................................................ 14

Chapter 3. Carbon Monoxide (CO) Control Technology Review. ..................19

3.1 BACT Baseline. ............................................................................................................................. 19

3.2 STEP 1. Identify All Available Control Technologies. ................................................................ 19

3.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 21

3.3.1 Oxidation Catalysts........................................................................................................... 21

3.3.2 Thermal Oxidation............................................................................................................ 21

3.3.3 Good Combustion Practices.............................................................................................. 21

3.4 STEP 3. Rank the Technically Feasible Control Technologies. ................................................... 22

3.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 22

3.5.1 Rank No. 1: Oxidation Catalyst and Good Combustion Practices. ................................. 22

3.5.2 Rank No. 2: Good Combustion Practices. ....................................................................... 25

3.6 STEP 5. Proposed CO BACT Determination. .............................................................................. 25

Chapter 4. Nitrogen Oxides (NOx) Control Technology Review. ....................26

4.1 BACT Baseline. ............................................................................................................................. 26

4.2 STEP 1. Identify All Potential Control Strategies. ....................................................................... 27

4.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 29

4.3.1 Low NOX Burners and Overfire Air. ................................................................................ 29

4.3.2 Overfire Air (Staged Combustion).................................................................................... 30

4.3.3 Flue Gas Recirculation...................................................................................................... 30

4.3.4 Oxygen-Enhanced Combustion. ....................................................................................... 31

4.3.5 Natural Gas or Coal Reburning......................................................................................... 31

4.3.6 Selective Catalytic Reduction........................................................................................... 31

4.3.7 Selective Non-Catalytic Reduction................................................................................... 32
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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4.3.8 Catalytic Absorption/Oxidation (SCONOxTM)................................................................. 32

4.3.9 Emerging Control Technologies....................................................................................... 33

4.3.10 Summary of the Technically Feasible Controls................................................................ 33

4.4 STEP 3. Rank the Technically Feasible Control Technologies. ................................................... 34

4.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 34

4.5.1 Rank No. 1: Selective Catalytic Reduction...................................................................... 34

4.5.2 Rank No. 2: Package Boiler with Ultra Low NOx Burners.............................................. 36

4.6 STEP 5. Proposed Nitrogen Oxide BACT Determination............................................................ 36

Chapter 5. Particulate Matter and PM10 Control Technology Review...........37

5.1 BACT Baseline. ............................................................................................................................. 37

5.2 STEP 1. Identify Potential Control Technologies......................................................................... 37

5.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 39

5.3.1 Fabric Filter Baghouses. ................................................................................................... 39

5.3.2 Dry Electrostatic Precipitators. ......................................................................................... 40

5.3.3 Wet Electrostatic Precipitators.......................................................................................... 41

5.3.4 Wet Scrubbers................................................................................................................... 41

5.3.5 Mechanical Collectors. ..................................................................................................... 41

5.4 STEP 3. Rank the Technically Feasible Technologies. ................................................................. 42

5.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 42

5.6 STEP 5. Proposed Particulate Matter BACT Determination........................................................ 42

Chapter 6. PM2.5 Control Technology Review...................................................43

6.1 BACT Baseline. ............................................................................................................................. 43

6.2 STEP 1. Identify All Potential Control Technologies................................................................... 44

6.2.1 Direct PM2.5 Emissions. .................................................................................................... 44

6.2.2 PM2.5 Precursors................................................................................................................ 44

6.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 44

6.3.1 Fabric Filter Baghouses. ................................................................................................... 44

6.3.2 Dry Electrostatic Precipitators. ......................................................................................... 48

6.3.3 Wet Electrostatic Precipitators.......................................................................................... 48

6.3.4 Wet Scrubbers................................................................................................................... 48

6.3.5 Mechanical Collectors. ..................................................................................................... 48

6.4 STEP 3. Rank the Technically Feasible Technologies. ................................................................. 48

6.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 49

6.6 STEP 5. Proposed PM2.5 BACT Determination............................................................................ 49

Chapter 7. Sulfur Dioxide (SO2) Control Technology Review.........................50

7.1 BACT Baseline. ............................................................................................................................. 50
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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7.2 STEP 1. Identify Potential Control Technologies......................................................................... 50

7.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 52

7.3.1 Low Sulfur Fuels and Fuel Cleaning. ............................................................................... 52

7.3.2 Flue Gas Desulfurization. ................................................................................................. 52

7.4 STEP 3. Rank the Technically Feasible Technologies. ................................................................. 58

7.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 58

7.6 STEP 5. Proposed Sulfur Dioxide BACT Determination............................................................. 58

Chapter 8. Volatile Organic Compound (VOC) Control Technology Review.59

8.1 BACT Baseline. ............................................................................................................................. 59

8.2 STEP 1. Identify All Available Control Technologies. ................................................................ 59

8.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 61

8.3.1 Oxidation Catalysts........................................................................................................... 61

8.3.2 Thermal Oxidation............................................................................................................ 61

8.3.3 Good Combustion Practices.............................................................................................. 61

8.4 STEP 3. Rank the Technically Feasible Control Technologies. ................................................... 62

8.5 STEP 4. Evaluate the Most Effective Controls............................................................................. 62

8.5.1 Rank No. 1: Oxidation Catalyst and Good Combustion Practices. ................................. 62

8.5.2 Rank No. 2: Good Combustion Practices. ....................................................................... 64

8.6 STEP 5. Proposed VOC BACT Determination. ........................................................................... 64

Chapter 9. Fluorides Control Technology Review............................................65

9.1 BACT Baseline. ............................................................................................................................. 65

9.2 STEP 1. Identify All Potential Control Technologies................................................................... 65

9.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 66

9.3.1 Flue Gas Desulfurization Systems. ................................................................................... 66

9.3.2 Sorbent Injection............................................................................................................... 66

9.4 STEP 3. Rank The Technically Feasible Control Technologies................................................... 66

STEP 4. Evaluate the Most Effective Controls.......................................................................................... 66

STEP 5. Proposed Fluorides BACT Determination................................................................................... 67
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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Tables 

TABLE 1-1. Potential air emissions for each 125,000 lb/hr auxiliary package Boiler B02 and B03.........9

TABLE 2-1. Summary of recent BACT economic analyses in which the control technology was rejected 

as not cost effective for BACT.............................................................................................15

TABLE 3-1. Natural gas-fired boiler carbon monoxide (CO) emission limits representing BACT from 

the U.S. EPA's RBLC database............................................................................................20

TABLE 3-2. Oxidation catalyst control system costs for each natural gas-fired boiler. ...........................23

TABLE 4-1. Natural gas-fired boiler nitrogen oxides (NOx) emission limits representing BACT from the 

U.S. EPA's RBLC database..................................................................................................28

TABLE 4-2. Summary of the technical feasibility of retrofit NOx control technologies. ..........................33

TABLE 4-3. Ranking of the technically feasible NOx control technologies............................................34

TABLE 4-4. Estimated SCR NOx control system costs for each natural gas-fired boiler. ........................35

TABLE 5-1. Natural gas-fired boiler particulate matter emission limits representing BACT from the U.S. 

EPA's RBLC database..........................................................................................................38

TABLE 7-1. Natural gas-fired boiler SO2 emission limits representing BACT from the U.S. EPA's RBLC 

database................................................................................................................................51

TABLE 8-1. Natural gas-fired boiler VOC emission limits representing BACT from the U.S. EPA's 

RBLC database. ...................................................................................................................60

TABLE 8-2. Oxidation catalyst control system costs for each natural gas-fired boiler. ...........................63

TABLE 9-1. Natural gas and distillate fuel oil-fired boiler hydrogen fluoride (HF) test results................65

 
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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Chapter 1. Introduction and Source Description. 

This document is a Control Technology Review for two new natural gas-fired package boilers, designated 

as Boilers B02 and B03, at the We Energies’ 50 MW Biomass Fuels Plant in Rothschild. This control 

technology review is required for major new sources under the Prevention of Significant Deterioration 

(PSD) program under NR 405.08, Wis. Adm. Code. 

The proposed boilers will be package boilers designed to provide up to 125,000 pounds per hour of steam. 

To deliver this steam capacity, each boiler will have a maximum design heat input capacity of 175 million 

Btu per hour. The only boiler fuel will be natural gas. Each boiler will be equipped with ultra-low NOx

burners and flue gas recirculation to control emissions of CO, NOx, PM, PM10, PM2.5, and VOCs. A 

typical large industrial package boiler is shown in Figure 1-1. Potential emissions for each boiler, based 

on this control technology review, are summarized in Table 1-1. 

FIGURE 1-1. Large FM type water tube package boiler (The Babcock & Wilcox Company). 
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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TABLE 1-1. Potential air emissions for each 125,000 lb/hr auxiliary package Boiler B02 and B03. 

UNCONTROLLED 

EMISSION FACTOR 

MAXIMUM 

HEAT 

INPUT 

POTENTIAL 

POLLUTANT TO EMIT 

lb/mmft3 lb/mmBtu mmBtu/hr lb/hr tons/yr

Carbon Monoxide CO 63.0 0.06 175 10.50 32.6

Nitrogen Oxides NOx 21.0 0.02 175 3.50 10.9

Particulate Matter PM/PM10 7.6 0.0076 175 1.33 4.1

Particulate Matter PM2.5 7.6 0.0076 175 1.33 4.1

Sulfur Dioxide SO2 0.60 0.0006 175 0.11 0.3

Organic Compounds OC 5.5 0.006 175 1.05 3.3

Lead Pb 0.00050 0.0000005 175 0.000083 0.00026

Mercury Hg 0.00026 0.0000002 175 0.000043 0.00013

Fluorides (as HF) HF 0.0 0.00062 175 0.11 0.34

Sulfuric Acid Mist H2SO4 0.006 0.000006 175 0.0011 0.0033

Footnotes 

1. For natural gas combustion, the CO and NOx emission rates are based on concentrations of 75 and 9 ppm at a 

flue gas excess oxygen content of 5%. Potential emissions are based on CO and NOx emission rates of 0.06 and 

0.02 lb/mmBtu, respectively. 

E = KChF(20.9) where, E = Emission Rate, lb/mmBtu 

 20.9 - %O2 F = F-Factor, dscf/mmBtu 

 

Natural Gas Combustion K Ch, ppm F, dscf/mmBtu %O2 E, lb/mmBtu

Carbon Monoxide CO 7.59E-08 75 8,710 5.0 0.058 

Nitrogen Oxides NOx 1.19E-07 9 8,710 5.0 0.012 

2. The emission factors for uncontrolled PM, PM10, PM2.5, SO2, VOC, lead, and mercury emissions are from the 

U.S. EPA’s AP-42, Compilation of Air Pollutant Emission Factors, 5th Edition, section 1.4, Natural Gas 

Combustion. All PM10 emissions are assumed to be PM2.5. 

3. Sulfuric acid mist emissions for natural gas combustion are based on 1% conversion of SO2 to SO3. 

6. Potential emissions are based on limiting the fuel use to: 

Natural Gas: HI = 1,085,000 mmBtu, 12-month average 6,200 hour/yr 
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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Chapter 2. Control Technology Review 

Methodology. 

2.1 Best Available Control Technology Definition. 

The Clean Air Act and the Prevention of Significant Deterioration (PSD) rules in the Code of Federal 

regulations, 40 CFR 52.21(b)(12) define “best available control technology” (BACT) as: 

 “...an emission limitation based on the maximum degree of reduction for each pollutant subject to 

regulation under this Act which would be emitted from any proposed major stationary source or major 

modification which the administrator on a case-by-case basis, taking into account energy, environmental, 

and economic impacts and other costs, determines is achievable for such source or modification through 

application of production processes and available methods, systems, and techniques, including fuel 

cleaning or treatment of innovative fuel combustion techniques for control of each such pollutant. In no 

event shall application of BACT result in emissions of any pollutant which would exceed the emissions 

allowed by any applicable standard under 40 CFR Parts 60 and 61.” 

In Wisconsin, BACT is defined as: 

...means an emissions limitation, including a visible emissions standard, based on the maximum degree 

of reduction for each air contaminant subject to regulation under the Act which would be emitted from 

any proposed major stationary source or major modification which the department, on a case-by-case 

basis, taking into account energy, environmental, and economic impacts, and other costs, determines is 

achievable for such source or modification through application of production processes or available 

methods, systems, and techniques, including clean fuels, fuel cleaning or treatment or innovative fuel 

combination techniques for control of the air contaminant. In no event may application of best available 

control technology result in emissions of any air contaminant which would exceed the emissions allowed 

by any applicable standard under chs. NR 440 and 445 to 449 and under sections 111 and 112 of the Act 

(42 USC 7411 and 7412). Emissions from any source utilizing clean fuels or any other means to comply 

with this subsection may not be allowed to increase above the levels that would have been required under 

this subsection as it existed prior to enactment of the 1990 clean air Act amendments on November 15, 

1990. If the department determines that technological or economic limitations on the application of 

measurement methodology to a particular emissions unit would make the imposition of an emissions 

standard infeasible, a design, equipment, work practice, operational standard or combination thereof, may 

be prescribed instead to satisfy the requirement for the application of best available control technology. 

The standard shall, to the degree possible, set forth the emissions reduction achievable by implementation 

of such design, equipment, work practice or operation, and shall provide for compliance by means which 

achieve equivalent results. (NR 405.02(7), Wis. Adm. Code) 

The BACT requirement applies for a given pollutant to each individual new or modified emission unit 

when the project, on a facility-wide basis, has a significant net emissions increase for that pollutant. 

Individual BACT determinations are performed on a unit-by-unit, pollutant-by-pollutant basis. This 

BACT analysis considers potential controls for SO2, NOx, PM/PM10, CO, VOC, and sulfuric acid mist.
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

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2.2 Top Down BACT Methodology. 

The U.S. EPA recommends a “top-down” approach in conducting a BACT analysis. This method 

evaluates progressively less stringent control technologies until a level of control considered BACT is 

reached, based on the environmental, energy, and economic impacts. The top-down method was used in 

this analysis. The five steps of a top-down BACT analysis are: 

1. Identify all available control technologies with practical potential for application to the emission 

unit and regulated pollutant under evaluation; 

2. Eliminate all technically infeasible control technologies; 

3. Rank remaining control technologies by effectiveness and tabulate a control hierarchy; 

4. Evaluate most effective controls and document results; and 

5. Select BACT, which will be the most effective practical option not rejected, based on economic, 

environmental, and/or energy impacts. 

The impact analysis of any BACT review includes an evaluation of environmental, energy, technical, and 

economic impacts. The net environmental impact associated with a control alternative may be considered 

if dispersion modeling analyses are performed. The energy impact analysis estimates the direct energy 

impacts of the control alternatives in units of energy consumption. If possible, the energy requirements 

for each control option are assessed in terms of total annual energy consumption. The most important 

issue of the BACT review is generally the economic impact. The economic impact of a control option is 

assessed in terms of cost effectiveness and ultimately, whether the option is economically reasonable. The 

economic impacts are reviewed on a cost per ton controlled basis, as directed by the U.S. EPA’s Office of 

Air Quality Planning and Standards (OAQPS) Cost Control Manual, Fifth Edition. 

The EPA has consistently interpreted the statutory and regulatory BACT definitions as containing two 

core requirements, which EPA believes must be met by any BACT determination, irrespective of whether 

it is conducted in a “top-down” manner. First, the BACT analysis must include consideration of the most 

stringent available technologies: i.e., those that provide the “maximum degree of emissions reduction.” 

Second, any decision to require a lesser degree of emissions reduction must be justified by an objective 

analysis of “energy, environmental, and economic impacts” contained in the record. 

2.3 New Versus Modified Facilities. 

There can be significant differences in the technical and economic feasibility of retrofitting controls on 

existing boilers, versus the use of these same controls on new boilers. In addition, a given control may 

not be able to achieve the same level of control when retrofitted onto existing units as the same control 

can achieve on new units. For example, the use of low NOx burners on existing boilers often cannot 

achieve the same NOx, CO, and VOC emission rates as the use of low NOx burners on a new boiler which 

has been designed to optimize the low NOx burner design. This can in turn affect the ultimate NOx

emission rates which can be achieved by post combustion controls such as selective catalytic reduction. 
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Retrofitting controls on existing boilers can also have significantly different costs as compared to the use 

of these same technologies on new units. Retrofitting controls on existing boilers can have numerous 

issues, including site constraints and room for the new controls, demolition requirements for existing 

controls, and down time during construction and interconnection of the new systems. 

2.4 Identifying Potential Control Technologies. 

As stated in the U.S. EPA’s October 1990 New Source Review Workshop Manual, the first step in a "topdown" analysis is to identify, for the emissions unit in question, all "available" control options. Available 

control options are those air pollution control technologies or techniques with a practical potential for 

application to the emissions unit and the regulated pollutant being evaluated. Air pollution control 

technologies and techniques include the application of production process or available methods, systems, 

and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control 

of the affected pollutant, including technologies employed outside of the United States. In some 

circumstances, inherently lower-polluting processes are appropriate for consideration as available control 

alternatives. The control alternatives should include not only existing controls for the source category in 

question, but also (through technology transfer) controls applied to similar source categories and gas 

streams, and innovative control technologies. Technologies required under lowest achievable emission 

rate (LAER) determinations are available for BACT purposes and must also be included as control 

alternatives and usually represent the top alternative. In Step 1, applicants should identify all control 

options with potential application to the emissions unit under review. 

2.5 Technical Feasibility. 

Step 2 of the BACT analysis involves the evaluation of all of the identified available control technologies 

from Step 1 to determine their technical feasibility. A control technology is technically feasible if it has 

been previously installed and operated successfully at a similar emission source, or there is technical 

agreement that the technology can be applied to the emission source. Technical infeasibility is 

demonstrated through clear physical, chemical, or other engineering principles that demonstrate that 

technical difficulties preclude the successful use of the control option. 

The technology must be commercially available for it to be considered as a candidate for BACT. EPA’s 

New Source Review Workshop Manual, page B.12 states, “Technologies which have not yet been applied 

to (or permitted for) full scale operations need not be considered available; an applicant should be able to 

purchase or construct a process or control device that has already been demonstrated in practice.” 

In general, if a control technology has been "demonstrated" successfully for the type of emission source 

under review, then it would normally be considered technically feasible. For an undemonstrated 

technology, “availability” and “applicability” determine technical feasibility. Page B.17 of the New 

Source Review Workshop Manual states: 

Two key concepts are important in determining whether an undemonstrated 

technology is feasible: "availability" and "applicability." As explained 

in more detail below, a technology is considered "available" if it can be 
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obtained by the applicant through commercial channels or is otherwise 

available within the common sense meaning of the term. An available 

technology is "applicable" if it can reasonably be installed and operated 

on the source type under consideration. A technology that is available 

and applicable is technically feasible. Availability in this context is 

further explained using the following process commonly used for bringing 

a control technology concept to reality as a commercial product: 

• concept stage; 

• research and patenting; 

• bench scale or laboratory testing; 

• pilot scale testing; 

• licensing and commercial demonstration; and 

• commercial sales. 

 

Applicability involves not only commercial availability (as evidenced by past or expected near-term 

deployment on the same or similar type of emission source), but also involves consideration of the 

physical and chemical characteristics of the gas stream to be controlled. A control method applicable to 

one emission source may not be applicable to a similar source depending on differences in physical and 

chemical gas stream characteristics. 

2.6 Economic Feasibility. 

Economic feasibility is normally evaluated according to the average and incremental cost effectiveness. 

From the U.S. EPA’s New Source Review Manual, page B.31, average cost effectiveness is the dollars 

per ton of pollutant reduced. The incremental cost effectiveness is the cost per ton reduced from the 

technology being evaluated as compared to the next lower technology. The EPA NSR Review Manual 

states that, “where a control technology has been successfully applied to similar sources in a source 

category, an applicant should concentrate on documenting significant cost differences, if any, between the 

application of the control technology on those sources and the particular source under review”. 

2.6.1 Average Cost Effectiveness. 

In the EPA’s New Source Review Manual, page B.37, average cost effectiveness is calculated as: 

Average Cost Effectiveness Control option annualized cost 

($ per ton removed) = Baseline emission rate – Control option emissions rate 

The average cost effectiveness is based on the overall reduction in the air pollutant from the baseline 

emission rate. In the draft Workshop Manual, the EPA states that the baseline emission rate represents 

uncontrolled emissions for the source. However, the manual also states that when calculating the cost 

effectiveness of adding controls to inherently lower emitting processes, baseline emissions may be 

assumed to be the emissions from the lower emitting process itself. 
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2.6.2 Incremental Cost Effectiveness. 

In addition to determining the average cost effectiveness of a control option, the U.S. EPA’s New Source 

Review Manual states that the incremental cost effectiveness between dominant control options should 

also be calculated. The incremental cost effectiveness compares the costs and emissions performance 

level of a control option to those of the next most stringent control option: 

Incremental Cost ($ per Control option annualized cost – Next control option annualized cost 

incremental ton removed) = Next control option emission rate – Control option emissions rate 

2.6.3 Agency Decisions on Cost Effectiveness. 

Numerous permitting authorities have made decisions regarding the economic feasibility of air pollution 

controls for coal-fired electric utility boilers which represent BACT. Table 2-1 is a summary of recent 

BACT economic analyses by various review agencies in which the control technology was rejected as not 

cost effective for BACT. The determinations in Table 2-1 include decisions for PM, PM10, NOx, and SO2

emissions for biomass-fired boilers, pulverized coal-fired boilers, circulating fluidized bed boilers, and 

gas turbines. While cost effectiveness is determined on a case-by-case basis, the following information 

on comparative economic costs of BACT options gives some perspective on the costs that similar sources 

have typically not been expected to bear as BACT. 
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TABLE 2-1. Summary of recent BACT economic analyses in which the control technology was rejected as not cost 

Cost Effectiveness of 

Rejected Technology, 

Facility State $ per ton controlled Boiler Type Pollutant Control Technology Rejected Average Incremental 

Control 

Technolo

Selected 

1 DTE Energy – Stoneman Power Plant WI Stoker NOx SCR $9,217 SNCR 2 We Energies – Concord Generating Station WI Gas Turb NOx SCR 8,236 - Good Combusti3 Longleaf Energy Associates GA PC SO2 Wet FGD - $8,964 Dry FGD 4 Rocky Mountain Power Hardin MT PC SO2 Wet FGD $1,395 $23,855 Dry FGD 

5 Intermountain Power 3 UT PC PM / PM10 Baghouse w/ Teflon Bags $31 $14,000 Baghouse 

Ryton Ba

NOx SCR at 0.04 $2,004 $10,303 SCR at 0.

6 

Basin Electric – Dry Fork Station WY PC SO2 Wet FGD $1,595 $15,299 Dry FGD 

7 Black Hills Power & Light – WYGEN2 WY PC NOx SCR at 0.06 $4,156 $7,742 SCR at 0.8 Black Hills Power & Light – WYGEN3 WY PC PM / PM10 Baghouse w/ Teflon Bags $134 $14,609 Baghouse 

Fiberglass B

9 

Deseret Power Cooperative – Bonanza UT CFB SO2 Wet FGD $418 $10,540 Dry FGD 

Wet FGD - $27,365 

10 

Southern Montana Electric Coop- Highwood MT CFB SO2 Dry FGD - $7,939 Ash Reinjec

11 Montana-Dakota Utilities Gascoyne Station ND CFB NOx SCR $7,545 $14,339 SNCR 12 Red Trail Energy Ethanol Plant ND CFB SO2 Wet FGD $1,041 $10,252 Dry FGD 13 River Hill Power Company PA CFB SO2 Wet FGD - >$5,000 Dry FGD 14 Cargill – Blair Ethanol Plant NE CFB SO2 Dry FGD - $5,900 No Post Con

NOx SNCR - $5,600 SNCR 

15 ADM – Columbus Ethanol Plant NE CFB SO2 Ca Inj. - $6,700 16 Lakefield Junction Station MN CT CO Ox. Catalyst 3,400 - No Post Con
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1. In a PSD permit for the conversion of two coal-fired boilers to wood combustion, the Department 

concluded that the use of regenerative selective catalytic reduction with an average NOx control cost 

of $9,217 per ton was not economically feasible. 

2. In a PSD permit for 320 MW of simple cycle combustion turbine capacity, the Department concluded 

that the use of selective catalytic reduction with an average NOx control cost of $8,236 per ton was 

not economically feasible. 

3. In a PSD permit issued by the State of Georgia in 2006 for a new pulverized coal-fired utility boiler at 

Longleaf Energy Associates, Georgia determined that the incremental cost effectiveness of $8,964/ton 

for wet FGD compared to dry FGD for SO2 control was not cost effective. The average cost 

effectiveness of the selected BACT option, dry FGD, was $724/ton. Georgia’s PD is available online 

at: http://www.air.dnr.state.ga.us/airpermit/psd/dockets/longleaf/permitdocs/0990030pd.pdf. 

4. In a PSD permit issued by the State of Montana in 2005 for a new pulverized coal fired utility boiler 

at Rocky Mountain Power’s Hardin project, Montana concluded that an incremental cost 

effectiveness of $23,855/ton for a wet FGD system as compared to a dry FGD system was excessive 

for BACT. The average cost effectiveness of the wet FGD option was $1,395/ton. The average cost 

effectiveness of the selected BACT option, dry FGD, was $918/ton. (Ref: Montana’s Permit 

Analysis for Hardin project, Permit #3185-02, pages 15 and 17, dated May 16, 2005.) 

5. In a PSD permit issued by the State of Utah in 2004 for a new pulverized coal-fired electric utility 

boiler at Intermountain Power’s Unit 3, Utah concluded that an incremental cost effectiveness of 

$14,000/ton to $16,350/ton, comparing different types of baghouse fabric filter bags (Ryton-type bags 

versus specialty coated bags) for PM/PM10 control, was excessive for BACT. The average cost 

effectiveness of the selected BACT option for PM10 control (a baghouse with Ryton-type bags) was 

$31/ton. (Ref: Utah’s Modified Source Plan Review for IPP3 project, March 22, 2004, available 

online at: http://www.airquality.utah.gov/Permits/PmtPowerPlants.htm.) 

6. In a PSD permit issued by the State of Wyoming in 2007 for a new pulverized coal-fired electric 

utility boiler at Basin Electric’s Dry Fork Station, Wyoming concluded that an incremental cost 

effectiveness of $23,755/ton for NOx control, comparing SCR at 0.043 lb/mmBtu to SCR at 0.040 

lb/mmBtu, was excessive for BACT. The average cost effectiveness for SCR at 0.040 lb/mmBtu was 

$2,004/ton; the average cost effectiveness for SCR at 0.043 lb/mmBtu was $1,751/ton. Although 

Wyoming stated that an incremental cost effectiveness of $10,303/ton was reasonable for SCR at 

0.043 lb/mmBtu, for other reasons described by Wyoming the selected NOx control was SCR at 0.05 

lb/mmBtu, with an incremental and average cost effectiveness of $3,512/ton and $1,511/ton, 

respectively. 

Wyoming also concluded that an incremental cost effectiveness of $15,299/ton for SO2 control, 

comparing a dry FGD system at 0.073 lb/mmBtu to a wet FGD at 0.054 lb/mmBtu, was excessive for 

BACT. The average cost effectiveness of the eliminated wet FGD option at 0.054 lb/mmBtu was 

$1,595/ton. Although Wyoming determined that an incremental cost effectiveness of $9,296/ton was 

reasonable for a dry FGD at 0.043 lb/mmBtu, for other reasons described by Wyoming the selected 

BACT option for SO2 control was a dry FGD system at 0.08 lb/mmBtu, with an average cost 

effectiveness of $1,159/ton. (Ref: Wyoming’s Analysis for the Dry Fork project, NSR-AP-3546, 

February 5, 2007.) 

7. In a PSD permit issued by the State of Wyoming in 2002 for a new pulverized coal-fired electric 

utility boiler at Black Hills Power & Light’s WYGEN2 project, Wyoming concluded that an 

incremental cost effectiveness of $7,742/ton, comparing low-NOx burners plus SCR at 0.06 lb/mmBtu 

to low-NOx burners plus SCR at 0.08 lb/mmBtu, for NOx control was reasonable for BACT. 

However, for other reasons described by Wyoming, the selected BACT option was low-NOx burners 
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plus SCR at 0.07 lb/mmBtu, with an average cost effectiveness between $4,067/ton and $4,156/ton. 

(Ref: Wyoming’s Permit Application Analysis for the WYGEN2 project, NSR-AP-92, April 24, 

2002.) 

8. In a PSD permit issued by the State of Wyoming in 2006 for a new pulverized coal-fired electric 

utility boiler at Black Hills Power & Light’s WYGEN3 project, Wyoming indicated that an 

incremental cost effectiveness of $14,609/ton, comparing a baghouse with fiberglass or 

polyphenylene sulfide filter bags, listed as capable of achieving 0.012 lb/MmBtu, to a baghouse with 

specialty filter bags such as Teflon, listed as capable of achieving 0.011 to 0.010 lb/MmBtu, for 

PM/PM10 control, was excessive for BACT. The average cost effectiveness of the selected BACT 

option, a baghouse with fiberglass or polyphenylene sulfide filter bags, was $130/ton; the average 

cost effectiveness of the eliminated option, a baghouse with specialty filter bags, was $134/ton. (Ref: 

Wyoming’s Permit Application Analysis for the WYGEN3 project, NSR-AP-3934, October 9, 2006.) 

9. In a PSD permit issued by the U.S. EPA Region 8 in August, 2007 for a circulating fluidized bed 

(CFB) boiler at the Deseret Power Cooperative’s Bonanza Power Plant, the EPA concluded that an 

incremental cost of $10,540 per ton of SO2 removed to install a wet FGD system rather than a dry 

FGD system was too high to justify the expenditure. The average cost effectiveness for the wet FGD 

system was $418 per ton of SO2 controlled; the average cost effectiveness for the dry FGD system 

selected as BACT was $397/ton of SO2 controlled. Further, the EPA concluded that the costs for 

alternative sources of coal in lieu of waste coal of $20,241 per ton of SO2 controlled was also 

excessive as BACT. 

10. In a PSD permit issued by the State of Montana in May, 2007 for a CFB boiler at Southern Montana 

Electric Cooperative’s Highwood Generating Station, Montana concluded that a cost of $27,365/ton 

of SO2 control, for a combination of limestone injection, low-sulfur coal and wet FGD was excessive 

for BACT. Montana also concluded that a cost of $7,939/ton of SO2 controlled, for a combination of 

limestone injection, low-sulfur coal and dry FGD, was excessive for BACT. The selected SO2 BACT 

option was a combination of limestone injection, low-sulfur coal, and hydrated ash reinjection with a 

cost effectiveness of $4,054/ton. (Ref: Montana’s “Permit Analysis” for Air Quality Permit #3423-00, 

May 30, 2007, from the Montana Department of Environmental Quality.) 

11. In a PSD permit issued by the State of North Dakota in early 2005 for a CFB boiler at MontanaDakota Utilities Gascoyne Generating Station, North Dakota concluded that an incremental cost 

effectiveness of $14,339/ton, comparing SCR at 0.04 lb/mmBtu to SNCR at 0.09 lb/mmBtu, for NOx

control, was excessive for BACT. The average cost effectiveness of SCR was $7,545/ton. The 

average and incremental cost effectiveness of the selected BACT option, SNCR, was $2,926/ton. 

(Ref: North Dakota’s Permit Analysis, March 2005, North Dakota Department of Health, 

Environmental Health Section.) 

12. In a PSD permit issued by the State of North Dakota in 2004 for a CFB boiler at the Red Trail 

Energy’s Richardton, ethanol plant, North Dakota determined that an incremental cost effectiveness 

of $10,252/ton, comparing wet FGD plus limestone injection to dry FGD plus limestone injection, for 

SO2 control was not cost effective. The average cost effectiveness of wet FGD plus limestone 

injection was $1,041/ton; the average cost effectiveness of dry FGD plus limestone injection was 

$527/ton. North Dakota rejected wet FGD and determined that BACT is dry FGD plus limestone 

injection. (Ref: North Dakota’s Analysis for Red Trail Energy project, May 2004, North Dakota 

Department of Health, Environmental Health Section, Air Quality Division.) 

13. In a PSD permit issued by the State of Pennsylvania in 2005 for a CFB boiler at the River Hill Power 

Company, Pennsylvania concluded that all SO2 BACT options involving wet FGD systems were 

economically infeasible at an incremental dollar per ton value greater than $5,000 per ton of SO2
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removed. Pennsylvania concluded that the use of dry FGD was economically feasible for the control 

of SO2 at an incremental cost of $1,511 per ton of SO2 removed. Pennsylvania also concluded that an 

incremental cost effectiveness of $15,975/ton, comparing the use of the waste coal to the nearest 

alternative source of coal with lower sulfur content, was excessive as BACT for SO2 emissions. (Ref: 

Pennsylvania’s “Plan Approval Review Memo, Application #17-00055A,” May 2, 2005.) 

14. In a PSD permit issued by the State of Nebraska in 2006 for a CFB boiler at Cargill’s Blair ethanol 

production plant, Nebraska indicated that an incremental cost effectiveness of $5,900/ton, comparing 

limestone injection alone to limestone injection plus dry FGD for SO2 control, was excessive for 

BACT. (Ref: Nebraska permit CP06-0008, Sept. 8, 2006, available at 

http://www.epa.gov/region07/programs/artd/air/nsr/archives/2006/finalpermits/cargill_blair_final_psd

_permit.pdf.) 

15. In a PSD permit issued by the State of Nebraska in 2006 for a CFB boiler at ADM’s Columbus corn 

milling and ethanol production plant, Nebraska indicated that incremental cost effectiveness of 

$5,600/ton for NOx control (comparing SNCR at 0.07 lb/mmBtu to SNCR at below 0.07), and an 

incremental cost effectiveness of $6,700/ton for SO2/H2SO4/HF control (comparing limestone 

injection to “additional” limestone injection), were excessive for BACT. Nebraska listed incremental 

cost-effectiveness of $2,174 for the selected BACT option for NOx control (SNCR at 0.07 lb/mmBtu). 

(Ref: Nebraska permit CPM02-0006, August 4, 2006, available online at: 

http://www.epa.gov/region07/programs/artd/air/nsr/archives/2006/finalpermits/adm_columbus_final_

psd_permit.pdf.) 

16. In 2001, the Minnesota Pollution Control Agency considered the requirement to put oxidation 

catalysts on six 92 MW simple cycle combustion turbines at the Lakefield Junction Station, Trimont, 

MN. The following is from the Technical Support Document, Permit No. 09100058-001. 

Whether or not either $3400, or $2938 per ton are reasonable control costs for CO control is 

arguable. The MPCA has decided, based on information submitted by the company and other 

sources, that both are unreasonable figures based on the following: 

CO is a non-persistent pollutant. Attached is a portion of a report to congress that states that; 

“CO has a photochemical lifetime of about one month in the tropics; that lifetime becomes 

indefinitely long (and is controlled by transport) in the winter at high latitudes. The globally 

averaged destruction of CO corresponds to an estimated lifetime of 2.5 months.” Therefore, 

emissions of CO from this facility will eventually become CO2 on their own and an oxidation 

catalyst to speed the process is unnecessary in the absence of ambient impact concerns. 

Ambient impacts are negligible. The air dispersion modeling performed for the facility predicts 

ambient impacts that are classified as insignificant under the Federal Prevention of Significant 

Deterioration regulations. Maximum predicted concentration of CO is 0.3% of the standard. (For 

Concord, the impacts are estimated at 0.01% of the NAAQS.) 

CO ambient problems are primarily a transportation source issue. The National Air Quality and 

Emissions Trends Report from 1996 shows that transportation now accounts for 79 percent of the 

nation’s total CO emissions. The attached graph from that report shows that non-transportation 

fuel combustion accounts for only 6.7% of overall CO emissions. CO emissions and ambient 

concentrations have been dropping since 1987 (and presumably prior as well) primarily due to 

measures taken to control emissions from mobile sources. 

The Minnesota Pubic Utilities Commission externality hearings found that the costs to the 

environment attributable to CO emissions were $0.021-0.041 per ton. 

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Chapter 3. Carbon Monoxide (CO) Control 

Technology Review. 

Carbon monoxide (CO) is emitted from natural gas-fired boilers as a result of incomplete combustion. 

Incomplete combustion can also result in reduced boiler efficiency and emissions of particulate matter, 

volatile organic compounds, and organic hazardous air pollutants. Because fuel costs represent the 

highest single operating cost for these boilers, these boilers are designed to achieve the highest 

combustion efficiencies practicable. CO emissions can be reduced by operating the boiler with higher 

furnace temperatures, higher excess oxygen levels, and longer furnace residence times. Unfortunately, 

techniques for reducing CO emissions can increase NOx emissions. Achieving low CO and low NOx

emissions is therefore a balancing act in boiler design and operation. 

3.1 BACT Baseline. 

There are no specific state implementation plan (SIP) requirements or new source performance standards 

for CO emissions from natural gas-fired boilers. Therefore, baseline emissions are simply the 

uncontrolled emissions from the boilers. 

3.2 STEP 1. Identify All Available Control Technologies. 

Table 3-1 summarizes the CO BACT emission limits for new and modified natural gas-fired boilers in the 

U.S. EPA’s RACT/BACT/LAER Clearinghouse. The technologies identified include Good Combustion 

Practices (GCP), and in one instance, Oxidation Catalysts (OC). Emission limits range from 0.035 to 

0.14 lb/mmBtu for natural gas combustion. Please note that many of the emission limits in these tables 

were expressed as pounds per hour. These rates were converted to lb/mmBtu to make the emission limits 

comparable. 
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TABLE 3-1. Natural gas-fired boiler carbon monoxide (CO) emission limits representing BACT from the U.S. EPA

RBLC ID FACILITY PERMIT DATE PROCESS THRUPUT , mmBtu/hr CONTROR-0040 Klamath Generation 03/12/03 Auxiliary Boiler TN-0153 Williams Refining & Marketing, L.L.C. 04/03/02 Heater 9.1 LA-0229 Shintech Louisiana Plaquemine Plant 2 07/10/08 Utility Boilers 250.0 GC*GA-0127 Southern Company Plant Mcdonough 01/07/08 Auxiliary Boiler 200.0 OR-0046 Calpine Turner Energy Center 01/06/05 Auxiliary Boiler OC CO-0052 Rocky Mountain Energy Center. 08/11/02 Auxiliary Boiler 129.0 GC*AL-0230 Thyssenkrupp Steel And Stainless USA 08/17/07 3 Boilers 64.9 MN-0062 Heartland Corn Products 12/22/05 Boiler 198.0 WV-0023 Longview Power 03/02/04 Auxiliary Boiler 225.0 GCAR-0070 Genova Arkansas I 08/23/02 Auxiliary Boiler 33.0 GCAR-0026 Pine Bluff Energy Center 05/05/99 Boiler 362.0 GCSC-0049 Skygen Broad River Energy 12/02/99 Utility Boilers 230.0 GCTN-0153 Williams Refining & Marketing 04/03/02 WCR Heater 209.0 *ID-0017 Southeast Idaho Advanced Energy Center 02/10/09 Package Boiler 250.0 GCMN-0066 Northern States Power Riverside Plant 05/16/06 Auxiliary Boiler 160.0 GCWI-0228 Wisconsin Public Service - Weston 10/19/04 Auxiliary Boiler 229.8 GCOK-0045 Redbud Power Plant 08/15/01 Auxiliary Boiler 20.0 GCIN-0085 PSEG Lawrenceburg Energy 06/07/01 Auxiliary Boiler 124.6 GCAR-0055 Nucor Yamato Steel (Armorel) 10/10/01 Process Heaters GCTN-0153 Williams Refining & Marketing 04/03/02 Boiler, No. 9 95.0 AR-0057 Tenaska Arkansas Partners, LP 10/09/01 Boiler, (2) 122.0 GCNE-0024 Cargill - Blair Plant 06/22/04 Boiler 276.7 GC

Footnotes 

“GCP” means good combustion practices. “OC” means oxidation catalyst. 
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3.3 STEP 2. Identify Technically Feasible Control Technologies. 

Available control technologies for the control of CO emissions include good combustion practices, 

oxidation catalysts, and thermal oxidation. 

3.3.1 Oxidation Catalysts. 

Oxidation catalysts are used to reduce CO emissions from natural gas or oil-fired combustion turbines, 

with typical CO reductions of 50 – 90%. However, as indicated in Table 3.1, oxidation catalysts have 

limited demonstration in reducing CO emissions from natural gas boilers. The CO oxidation catalysts are 

generally noble metal catalysts which are susceptible to poisoning from sulfur and calcium bearing 

compounds. These catalysts may experience deactivation and fouling in high sulfur oil-fired boiler flue 

gas streams. To be effective, the oxidation catalyst must be placed in a location with gas temperatures of 

at least 600 o

F. Oxidation catalysts operate according to the following general reaction: 

 2CO + O2 → 2CO2 

Typical excess oxygen (O2) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in natural 

gas-fired boilers. These low excess O2 levels will limit the effectiveness of the oxidation catalyst. 

3.3.2 Thermal Oxidation 

Thermal oxidation has never been required nor used on a natural gas-fired boiler, and its theoretical 

ability to reduce CO emissions from these boilers is questionable. Thermal oxidation would involve 

injecting additional air into the flue gas and heating the oxygen enriched mixture to approximately 1,500 o

F to oxidize CO to carbon dioxide. However, since the combustion of the reheat fuel would itself result 

in CO emissions, there is no evidence that thermal oxidation would result in any CO emission reductions. 

Since thermal oxidation has never been demonstrated on a natural gas-fired boiler, and because there is no 

evidence that it could reduce CO emissions, thermal oxidation is not a technically feasible CO control 

technology for these boilers. 

3.3.3 Good Combustion Practices 

Good combustion practices or combustion controls generally include the following components: 

1. Good air/fuel mixing in the combustion zone. 

2. High temperatures and low oxygen levels in the primary combustion zone. 

3. Overall excess oxygen levels high enough to complete combustion while maximizing 

boiler thermal efficiency. 

4. Sufficient residence time to complete combustion. 

In natural gas-fired boilers, good combustion practices is a technically feasible CO control technology. 

Combustion efficiency is related to the three “T’s” of combustion: Time, Temperature, and Turbulence. 

These components of combustion efficiency are designed into utility boilers to maximize fuel efficiency 
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and reduce the highest single operating cost of a utility boiler: FUEL. A fourth critical parameter is the 

level of oxygen in the boiler, referred to as the excess air or excess oxygen level. Therefore, combustion 

control is accomplished primarily through boiler design as it relates to time, temperature, and turbulence, 

and through boiler operation as it relates to excess oxygen levels. Combustion design for modern boilers 

is intended to simultaneously minimize formation of CO and NOx emissions. This is a difficult task, 

since emissions of NOx and emissions of CO are inversely related. That is, measures used to reduce NOx

emissions often lead to increases in CO emissions. Therefore, the boiler design to minimize CO 

emissions is interrelated with the boiler design to minimize NOx formation. 

3.4 STEP 3. Rank the Technically Feasible Control Technologies. 

Based on the above analysis, the technically feasible CO control technologies for these natural gas-fired 

boilers includes good combustion practices based on the use of the ultra low NOx burners combined with 

flue gas recirculation, and the addition of an oxidation catalyst system as a post combustion control 

system. Good combustion practices are expected to limit CO emissions to less than 75 parts per million 

at 5% excess oxygen, equal to 0.06 lb/mmBtu. The use of an oxidation catalyst is expected to further 

reduce CO emissions by 50%, to 37 parts per million, and 0.03 lb/mmBtu. 

3.5 STEP 4. Evaluate the Most Effective Controls. 

3.5.1 Rank No. 1: Oxidation Catalyst and Good Combustion Practices. 

The use of good combustion practices combined with an oxidation catalyst on these natural gas-fired 

boilers could reduce CO emissions to 0.03 lb/mmBtu. Based on limiting the operation of these boilers to 

6,200 hours per year, this combination of controls could reduce CO emissions from 32.6 tons per year, to 

16.3 tons per year. 

3.5.1.1 Environmental Impacts. 

The primary environmental impact from the use of oxidation catalysts on these boilers is a reduction in 

CO emissions. The use of an oxidation catalyst may also reduce VOC emissions by 25%. 

3.5.1.2 Energy Impacts. 

Energy impacts from the use of an oxidation catalyst would include a small increase in induced draft fan 

power requirements necessary to overcome a small pressure drop across the catalyst. 

3.5.1.3 Economic Impacts. 

The costs for oxidation catalysts on these boilers would include the capital costs for the catalyst and 

ancillary equipment, labor, auxiliary power requirements, catalyst replacement, maintenance, and 

administrative costs. The oxidation catalyst cost analysis is included in Table 3-2. From Table 3-2, an 

oxidation catalyst system is expected to have an equipment cost of $105,000 per boiler, and a total capital 
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requirement of $210,000. From Table 3-2, the oxidation catalyst system is expected to have an annual 

cost of $136,100 for each boiler. The oxidation catalyst systems would reduce CO emissions by 16.3 

tons. Based on these costs, the oxidation catalyst systems would have an average cost effectiveness of 

$8,360 per ton of CO removed. 

TABLE 3-2. Oxidation catalyst control system costs for each natural gas-fired boiler. 

 CAPITAL COST ANNUAL COST 

Total Capital Cost 

Equipment Cost, 2010 Dollars $105,000 

Capital Recovery Factor, CRF 0.1098 

Total Capital Investment (TCI) $210,000 $23,100 

Labor Costs (1 hour per day) $18,300 

Maintenance Costs 

Maintenance Labor, hr/year 300 

Catalyst Inspection and Replacement Labor, hr per year 400 

Labor Cost, $ per year $35,000 

Material Cost, $ per year $35,000 

Total Annual Maintenance Cost $/yr $70,000 

Catalyst Replacement Costs 

Catalyst Cost $70,000 

Sinking Fund Factor 0.174 

Total Catalyst Replacement Costs $12,200 

Auxiliary Power Requirements $8,300 

Overhead and Administrative Costs 2% of TCI $4,200

TOTAL ANNUAL COST $136,100 

Footnotes 

1. The cost of capital for this project is 7%, and the project life is 15 years. The annual cost of this investment is 

given by the capital recovery factor (CRF): 

 where: i = annual interest rate (decimal)

 n = control system life (years)

2. For the catalyst, the catalyst life is 5 years. The annual cost is given by the sinking fund factor (SFF): 

 

3. The oxidation catalyst capital cost is based on the catalyst system equipment cost multiplied by 2.0 for the costs 

of installation and other necessary equipment.. 

[ ] (1 ) 1

(1 )

+ −

+ = n

n

i

i i CRF

[ ] (1+ ) −1 = n i

i SFF
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3.5.1.4 Conclusion. 

The use of an oxidation catalyst in combination with good combustion practices on these natural gas-fired 

package boilers can achieve CO emission rates of 0.03 lb/mmBtu. However, each oxidation catalyst 

system would have a total capital requirement of $210,000, and a total annual cost of $136,100. The 

oxidation catalyst systems would reduce CO emissions by 16.3 tons per year for each boiler, resulting in 

an average cost effectiveness of $8,360 per ton of CO removed for each boiler. This is a very high cost, 

indicating that the use of an oxidation catalyst for the control of CO emissions on these natural gas-fired 

boilers is not an economically feasible control option. 

Numerous regulatory agencies have made determinations regarding the cost effectiveness of oxidation 

catalysts on combustion turbines and have rejected this technology as economically infeasible at costs as 

low as $1,700 per ton of CO removed. These determinations include the South Carolina Santee Cooper 

Rainey Generating Station, $1,717 per ton; Mississippi MEP Clarksdale Power Plant, $5,593 per ton; 

Florida Duke Energy Lake Station, $5,563 per ton; Wisconsin West Marinette Station, $6,053 per ton, 

and the Lakefield Junction Station, Trimont, MN, $2,938 per ton. In 2001, the Minnesota Pollution 

Control Agency considered the requirement to put oxidation catalysts on six 92 MW combustion turbines 

at the Lakefield Junction Station, Trimont, MN. The following is from the Technical Support Document 

for this facility, Permit No. 09100058-001. 

Whether or not either $3400, or $2938 per ton are reasonable control costs for CO control is 

arguable. The MPCA has decided, based on information submitted by the company and other 

sources, that both are unreasonable figures based on the following: 

1. CO is a non-persistent pollutant. Attached is a portion of a report to congress that states 

that; “CO has a photochemical lifetime of about one month in the tropics; that lifetime 

becomes indefinitely long (and is controlled by transport) in the winter at high latitudes. 

The globally averaged destruction of CO corresponds to an estimated lifetime of 2.5 

months.” Therefore, emissions of CO from this facility will eventually become CO2 on 

their own and an oxidation catalyst to speed the process is unnecessary in the absence 

of ambient impact concerns. 

2. Ambient impacts are negligible. The air dispersion modeling performed for the facility 

predicts ambient impacts that are classified as insignificant under the Federal 

Prevention of Significant Deterioration regulations. Maximum predicted concentration 

of CO is 0.3% of the standard. (For this plant, the maximum CO ambient air impact 

for the entire Project is much less than the significant impact levels under NR 405, 

Wis. Adm. Code, indicating that these boilers will have an insignificant impact on 

ambient air concentrations .)

3. CO ambient problems are primarily a transportation source issue. The National Air 

Quality and Emissions Trends Report from 1996 shows that transportation now 

accounts for 79 percent of the nation’s total CO emissions. The attached graph from 

that report shows that non-transportation fuel combustion accounts for only 6.7% of 

overall CO emissions. CO emissions and ambient concentrations have been dropping 

since 1987 (and presumably prior as well) primarily due to measures taken to control 

emissions from mobile sources. 

4. The Minnesota Pubic Utilities Commission externality hearings found that the costs to 

the environment attributable to CO emissions were $0.021-0.041 per ton. 
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3.5.2 Rank No. 2: Good Combustion Practices. 

The use of package boilers with Ultra Low NOx Burners, Overfire Air, and Flue Gas Recirculation, and 

the use of good combustion practices can achieve a CO emission rate of 0.06 lb/mmBtu. Based on 

limiting the annual heat input to each boiler to no more than 1,085,000 mmBtu per year (equal to 

2,170,000 mmBtu per year for both boilers combined), the use of good combustion practices will limit 

CO emissions from each boiler to 32.6 tons per year. 

3.6 STEP 5. Proposed CO BACT Determination. 

Based on this analysis, We Energies has concluded that the use of good combustion practices represents 

the best available control technology (BACT) for the control of CO emissions from these natural gas-fired 

package boilers. Based on this analysis, We Energies proposes the following limits as BACT for the 

control of CO emissions from the natural gas-fired boilers. 

(1) Carbon monoxide (CO) emissions from the natural gas-fired boilers 

B02 and B03 shall be controlled using good combustion practices as 

the best available control technology. 

(2) Carbon monoxide (CO) emissions may not exceed 0.06 pounds per 

million Btu of heat input, based on a 30-day rolling average. 

(3) The total heat input to boilers B02 and B03 combined may not exceed 

2,170,000 mmBtu in any consecutive 12-month period. 

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Chapter 4. Nitrogen Oxides (NOx) Control 

Technology Review. 

Nitrogen oxides (NOx) consist of several compounds, including nitrogen oxide (NO), and nitrogen 

dioxide (NO2). During combustion, NO usually accounts for more than 90% of the total NOx emissions. 

However, since NO is subsequently converted to NO2 in the atmosphere, the mass emission rate of NOx

are normally reported as NO2. 

NOx is formed during combustion by two major mechanisms; thermal formation, called “Thermal NOx”, 

and fuel formation, called “Fuel NOx”. Thermal NOx results from the high temperature oxidation of 

nitrogen (N2) and oxygen (O2). Thermal NOx formation is influenced by the flue gas residence time and 

excess oxygen, but, as its name implies, thermal NOx formation is primarily influenced by temperature. 

Thermal NOx formation increases exponentially with temperature, and becomes significant at 

temperatures above 2800 °F. Fuel NOx results from the oxidation of organic nitrogen compounds in the 

fuel. Fuel bound nitrogen is more easily converted to NOx during combustion. Fuel NOx may account for 

up to 80% of the total NOx emissions, especially from solid fuel combustion. 

4.1 BACT Baseline. 

The proposed natural gas-fired boilers would be subject to the Standards of Performance for IndustrialCommercial-Institutional Steam Generating Units under 40 CFR Part 60, Subpart Db, and NR 440.205, 

Wis. Adm. Code. This subpart applies to steam generating units that commence construction, 

modification, or reconstruction after June 19, 1984, and that have a heat input capacity from fuels 

combusted in the steam generating unit greater than 100 mmBtu/hr. 

The NOx standards in Subpart Db are specified by the type of fuel combusted. In NR 440.205(5)(a), the 

NOx emission limit is 0.20 lb/mmBtu for a high heat release boiler firing natural gas and distillate oil. 

This boiler will have a maximum heat release rate of more than 70,000 Btu/hr-ft3

, a high heat release rate. 

Compliance with the NOx emission limit is to be determined on a 30-day rolling average basis and applies 

at all times, including startup, shutdown, and/or malfunction in accordance with 40 CFR 60.44b(i) and 

(h). Boilers with a heat input capacity of 250 mmBtu/hr or less with an annual capacity factor for natural 

gas and distillate oil greater than 10% can install a continuous monitoring system for NOx or can use 

operating conditions to predict emissions in accordance with 40 CFR 60.48b(g). 
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4.2 STEP 1. Identify All Potential Control Strategies. 

Table 4-1 summarizes the NOx BACT emission limits for new and modified natural gas-fired boilers in 

the U.S. EPA’s RACT/BACT/LAER Clearinghouse. The technologies identified include low NOx 

burners (LNB), Flue Gas Recirculation (FGR), Good Combustion Practices (GCP), and Selective 

catalytic reduction (SCR). Emission limits range from 0.01 to 0.10 lb/mmBtu for natural gas combustion. 

Please note that many of the emission limits in these tables were expressed as pounds per hour. These 

rates were converted to lb/mmBtu to make the emission limits comparable. 

There are two major technology categories for controlling NOx emissions from boilers: combustion 

controls and post-combustion controls. Combustion NOx control techniques use technologies such as low 

NOx burners, and/or overfire air to control residence time, oxygen, and combustion temperature to limit 

NOx formation. Post combustion NOx control systems are designed to reduce emissions after NOx has 

been created. The most common secondary control technique involves the injection of ammonia or urea 

into the flue gas to reduce NOx to nitrogen and water. When injected upstream of a catalyst, this process 

is called Selective Catalytic Reduction (SCR); when injected without a catalyst, this process is called 

Selective Non-Catalytic Reduction (SNCR). Combustion and post combustion controls may be used 

together to achieve the lowest emission rates. 

The following NOx control technologies were identified in a review of potential controls: 

Combustion Controls 

• Low NOx burners (LNB) 

• Overfire air (OFA) 

• Flue Gas Recirculation (FGR) 

• Oxygen-Enhanced Combustion (OEC) 

• Fuel Reburn 

Post Combustion Controls 

• Selective Non-Catalytic Reduction (SNCR) 

• Selective Catalytic Reduction (SCR) 

• SCONOxTM 

• Emerging Control Technologies. 

 
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TABLE 4-1. Natural gas-fired boiler nitrogen oxides (NOx) emission limits representing BACT from the U.S. EPA's 

RBLC ID Facility Permit Date Process Thruput, mmBtu/hr Controls LA-0229 Shintech Plaquemine Plant 2 07/10/08 Utility Boilers 250 LNB, SCR TX-0499 Sandy Creek Energy Station 07/24/06 Auxiliary Boiler 175 OR-0046 Calpine Turner Energy Center 01/06/05 Auxiliary Boiler SCR PA-0193 Merck and Company - West Point Plant 08/26/99 Boilers, (2) 249 LNB, FGR*ID-0017 Southeast Idaho Advanced Energy Center 02/10/09 Package Boiler 250 LNB, FGR MN-0076 Blandin Paper/Rapids Energy Center 09/18/08 Boiler 280 LNB, FGR *AL-0230 Thyssenkrupp Steel and Stainless 08/17/07 3 Boilers 65 ULNB, FGNJ-0036 AES Red Oak, LLC 10/24/01 Auxiliary Boiler 120 Limit to 3IN-0085 PSEG Lawrenceburg Energy Facility 06/07/01 Auxiliary Boiler 125 LNB AR-0026 Pine Bluff Energy Center 05/05/99 Boiler 362 LNB, FGRCO-0052 Rocky Mountain Energy Center 08/11/02 Auxiliary Boiler 129 LNB, 1,90MN-0062 Heartland Corn Products 12/22/05 Boiler 198 ID-0015 J R Simplot Company - Don Siding Plant 04/05/04 Boiler 175 LNB TX-0411 Calpine Amelia Energy Center 03/26/02 Auxiliary Boiler 155 SC-0049 Skygen Broad River Energy 12/02/99 Utility Boilers 230 LNB, FGRID-0015 J R Simplot Company - Don Siding Plant 04/05/04 Boiler 64 LNB NE-0024 Cargill - Blair Plant 06/22/04 Boiler 277 LNB, FGR IA-0050 Cargill - Eddyville 04/22/99 Boiler 7 182 LNB, FGR AL-0128 Alabama Power - Theodore Cogeneration 03/16/99 Boiler 220 LNB, FGR FL-0251 Okeelanta Corporation Sugar Mill 10/29/01 Boiler 211 LNB, FGRNE-0024 Cargill - Blair Plant 06/22/04 Boilers A, B & C 198 LNB, FGR LA-0183 Louisiana Pigment Co. Titanium Dioxide Facility 11/14/03 Utility Boilers 135 LNB, GCP WI-0204 UWGP - Fuel Grade Ethanol Plant 08/14/03 Boiler /Oxidizer 140 GCP WV-0023 Maidsville Longview Power, LLC 03/02/04 Auxiliary Boiler 225 LNB, GCP WI-0228 Wisconsin Public Service - Weston Plant 10/19/04 Auxiliary Boiler 230 LNB, GCP VA-0270 Virginia Commonwealth University East Plant 03/31/03 Boiler 150 LNB, FGR

Footnotes “GCP” means good combustion practices. “SCR” means selective catalytic reduction. “LNB” means low NOx burner. “ULNB” mean“FGR” means flue gas recirculation. 
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4.3 STEP 2. Identify Technically Feasible Control Technologies. 

There are two key concepts in determining the feasibility of potential control technologies: “availability” 

and “applicability.” A technology is considered “available” if it can be obtained commercially, has 

completed a commercial demonstration, and has reached the point of licensing. When considering a 

technology’s applicability, technical judgment must be exercised to determine if it can reasonably be 

installed and operated on the proposed source. In determining the feasibility of a given technology 

controlling to a given emission rate there is a third concept, “demonstrated in practice.” A control rate or 

emission rate is “demonstrated in practice” if a unit with similar operating conditions has continuously. 

4.3.1 Low NOX Burners and Overfire Air. 

Low NOx burners (LNB) are designed to control the mixing of air and fuel to reduce the peak 

temperatures of combustion in natural gas and fuel oil-fired boilers. Low NOx burners reduce NOx

emissions by staging the combustion process. Staging slows down the combustion process, resulting in 

cooler flame temperatures which suppresses thermal NOx formation. 

Low NOx burners are designed to control fuel and air mixing at the burner in order to create larger flame 

patterns. This reduces the peak flame temperature and results in lower thermal NOx formation. The 

modified flame structure also reduces the amount of oxygen available in the hottest part of the flame, 

improving burner efficiency. Primary combustion, NOx reduction and fuel burnout are accomplished in 

three stages in a modern, LNB equipped boiler: 

1. The first stage is a fuel rich zone where oxygen levels are maintained below the 

stoichiometric requirement to complete combustion. Most NOx is formed in this zone. 

2. The second stage is a reducing zone where unburned hydrocarbon radicals reduce the 

NOx formed in the first stage. 

3. In the third stage, overfire air completes combustion, but produces additional NOx. The 

NOx formation is minimized by completing combustion in an air-lean environment. 

Some LNBs include the installation of over-fire air ports that provide sufficient oxygen to complete the 

combustion process, but at temperatures well below those found in the burner flame. This is more 

common in solid fuel combustion. For natural gas and fuel oil combustion, this deep staging of overfire 

air is not required. Instead, the staging of combustion is done within the burner itself. 

LNB and ultra low NOx burners are an available and highly effective NOx control technology for these 

natural gas-fired boilers. These burners are capable of limiting NOx emissions to approximately 9 parts 

per million (ppm). A typical, modern ultra low NOx burner for natural gas and distillate fuel oil 

combustion is shown in Figure 4-1. 
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FIGURE 4-1. A typical, modern ultra-low NOx burner for natural gas combustion (from CleaverBrooks NATCOM®). 

4.3.2 Overfire Air (Staged Combustion). 

Overfire air (OFA) is a combustion staging processes typically used in conjunction with low NOx burners. 

A portion of the combustion air is redirected from the LNB to a higher elevation in the furnace to reduce 

peak flame temperatures by reducing the concentration of oxygen in portions of the furnace. This 

technique is used to create an oxygen depleted zone where unburned hydrocarbon species act to reduce 

the NOx that was formed near the burner. The overfire air creates an oxidation zone to complete 

combustion. NOx formation is minimized by completing combustion in an air-lean environment. 

4.3.3 Flue Gas Recirculation. 

Flue gas recirculation (FGR) is a combustion process often used in conjunction with low NOx burners to 

reduce peak flame temperatures and create an oxygen depleted zone in the boiler by reducing the 

concentration of oxygen in portions of the furnace. Flue gas recirculation reduces the oxygen content of 

the air at the base of the furnace by diluting the primary air blown into the furnace with recirculated flue 

gas from the back pass of the boiler. This technique is used to create an oxygen depleted reducing zone 

where unburned hydrocarbon species act to reduce the NOx that was formed near the burner. This oxygen 

depleted zone also reduces the peak flame temperatures which minimizes NOx formation. 
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4.3.4 Oxygen-Enhanced Combustion. 

Oxygen-Enhanced Combustion (OEC) is a combustion control technology aimed at reducing the 

formation of thermal NOx. Praxair Technology, Inc. has developed a method of using oxygen to achieve 

additional NOx reduction from low NOx burners on pulverized coal-fired boilers. Field tests were 

conducted at the James River Power Station Unit 3, a wall-fired boiler. In pilot- and full-scale testing, 

NOx emissions were reduced by as much as 60%, to levels below 0.15 lb/mmBtu, when a small portion of 

low-NOx burner combustion air was replaced with locally injected oxygen. 

We are not aware of the use of OEC on natural gas-fired boilers. Because there is no operational 

experience with OEC on these boilers, and because the application of OEC to these boilers has significant 

technological questions, OEC is not a technically feasible control option. 

4.3.5 Natural Gas or Coal Reburning 

Natural gas or coal reburning are NOx control techniques used primarily for reducing NOx emissions from 

existing utility scale coal-fired boilers. Reburning redistributes a portion of both fuel and air into the 

upper regions of the boiler furnace to create a second flame zone, generating chemically reducing 

conditions that destroy NOx in the primary combustion zone. In large utility pulverized coal-fired boilers, 

fuel reburning is conducted between the upper burner row and the furnace exit. Most reburn systems 

divert 10 to 20% of the total boiler heat input to the upper furnace. If reburn conditions are not carefully 

controlled, high temperature corrosion problems can occur which can damage the boiler.

At least five utility coal-fired demonstrations of reburn are in different levels of operation. In the best 

applications, reburning may reduce NOx emissions to 0.15 lb/mmBtu. However, to be effective in 

reducing NOx emissions, reburning requires a large furnace volume to adequately stage combustion. This 

natural gas and/or coal reburning process is not applicable to natural gas-fired boilers. Therefore, natural 

gas and coal reburning are not technically feasible control options. 

4.3.6 Selective Catalytic Reduction. 

Selective Catalytic Reduction (SCR) is a post combustion NOx control system which consists of an 

ammonia (NH3) injection system and a catalytic reactor. Urea can be decomposed in an external reactor 

to form ammonia for use in an SCR. The ammonia injection grid is located upstream of the catalyst. 

Ammonia reacts with NOx and O2 in the presence of the catalyst to form molecular nitrogen (N2) and 

water according to the following general equations: 

 4NH3 + 4NO + O2 → 4N2 + 6H2O 

 4NH3 + 2NO2 + O2 → 3N2 + 6H2O 

 2NH3 + NO + NO2 → 2N2 + 3H2O 

This process is called “selective” because ammonia reacts preferentially with NOx in the flue gas in the 

presence of a catalyst. A catalyst is used to enhance NOx reduction and ammonia utilization. The most 

common catalyst is a vanadium-based material supported on a honeycomb substrate that is installed in 
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multiple layers in the catalytic reactor. Secondary reactions also occur in the presence of the SCR catalyst, 

including the oxidation of SO2 to SO3 and the oxidation of elemental mercury. 

Based on this review, SCR is a technically feasible control option for these natural gas-fired boilers. 

4.3.7 Selective Non-Catalytic Reduction. 

In a selective non-catalytic reduction (SNCR) control system, urea or ammonia is injected into the boiler 

where the flue gas temperature is approximately 1,600 °F to 2,100 °F. At these temperatures, the reagent, 

urea [CO(NH2)2] or ammonia [NH3], reacts with NOx, forming elemental nitrogen [N2 ] and water without 

the need for a catalyst. The overall NOx reduction reactions are similar to those for the SCR systems. 

Multiple injection points are required to thoroughly mix the reagent in the boiler furnace. The limiting 

factor for a SNCR system is the ability to contact the NOx with the reagent as the concentration decreases 

without resulting in excessive ammonia slip, and without excessive ammonia decomposition before the 

NOx emissions can be reduced. 

SNCR has been widely used in fluidized bed boilers where the high alkaline ash loading of the CFB 

boilers makes ‘high dust’ loading SCR systems technically infeasible. SNCR has also been widely used 

in modern stoker boilers. However, SNCR is not appropriate for use in package natural gas-fired boilers, 

since the short residence time does not allow for adequate reaction time to reduce NOx emissions. 

Therefore, SNCR is not a technically feasible control option for these boilers. 

4.3.8 Catalytic Absorption/Oxidation (SCONOxTM) 

SCONOxTM is a control technology that has been applied in combustion turbine applications. ABB 

Alstom Power purchased a proprietary technology called SCONOxTM from Goal Line Environmental 

Technologies. A SCONOx system has been in operation since December of 1996 on the 30 MW Sun 

Law Energy Federal cogeneration plant in Vernon, California. Since August of 1999, SCONOx has been 

in operation on a 5 MW cogeneration plant at Genetics Institute in Andover, Massachusetts. ABB 

Alstom Power subsequently completed design of a scaled-up SCONOx system for 100 MW and greater 

combined cycle gas turbines. 

The SCONOx system is based on a proprietary catalytic oxidation and absorption technology. In 

operation, NO and CO are first oxidized to NO2 and CO2. Next, NO2 is adsorbed onto an adsorption 

media. When the media is saturated, NO2 is desorbed and treated by the proprietary catalyst. Because the 

operation of SCONOx to oxidize CO to CO2 is identical to the simple use of an oxidation catalyst, there is 

effectively no difference between SCONOx and an oxidation catalyst in terms of CO and VOC control. 

Therefore, SCONOx and an oxidation catalyst are effectively the same technology for controlling CO and 

VOC emissions. 

To date, SCONOx has only been installed on small scale natural gas-fired combustion turbines. 

Therefore, this technology is not technically feasible for these boilers. Even if one were to conclude that 

it is applicable to these natural gas-fired boilers, the controlled emission rates would be similar to the use 

of SCR. 
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4.3.9 Emerging Control Technologies. 

Emerging technologies to reduce NOx emissions include Enviroscrub, Powerspan’s Electro-Catalytic 

Oxidation (ECOTM) scrubber, and the NOxStar and Cascade processes. Enviroscrub and ECO are 

emerging technologies with the potential to reduce NOx emissions and potentially other pollutants as well. 

However, these technologies are either not yet commercially available or are not proven with a long term 

demonstrated level of performance. The most advanced process is the ECO system. ECOTM is an 

emerging post-combustion multi-pollutant control technology including NOX control and has 

demonstrated performance, reliability and economics through testing at a pilot plant. However, no full 

size commercial scale ECOTM systems have been installed or operated. 

Enhanced and hybrid SNCR and SCR systems that are emerging NOx control technologies include 

NOxStar and Cascade. NOxStar is a hydrocarbon enhanced SNCR system that injects hydrocarbons 

downstream of an SNCR system to produce radicals that will further reduce NOx emissions. The Cascade 

process is a hybrid combination of SNCR and SCR systems. Neither of these systems has demonstrated 

long term levels of performance, and neither of them has been demonstrated on a full scale boiler. Due to 

lack of experience and a proven record of commercial operation, these emerging control technologies are 

not technically feasible for NOx control for these boilers. 

4.3.10 Summary of the Technically Feasible Controls. 

Table 4-2 is a summary of the technical feasibility of the NOx controls for the proposed natural gas-fired 

boilers. 

TABLE 4-2. Summary of the technical feasibility of retrofit NOx control technologies. 

Technology Technical 

Feasibility 

Low NOx Burners (LNB) Yes LNB are widely used in natural gas-fired 

package boilers. 

Overfire Air (OFA) Yes OFA is a design feature of modern natural 

gas-fired package boilers. 

Flue Gas Recirculation (FGR) Yes FGR is a design feature of modern natural 

gas-fired package boilers. 

Oxygen Enhanced Combustion No Never applied to natural gas-fired 

package boilers. 

Natural Gas or Coal Reburn No Never applied to natural gas-fired 

package boilers. 

Selective Non-Catalytic Reduction (SNCR) No SNCR is not applicable to natural gasfired package boilers. 

Selective Catalytic Reduction (SCR) Yes SCR has been demonstrated on both 

natural gas-fired boilers. 
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4.4 STEP 3. Rank the Technically Feasible Control Technologies. 

Table 4-3 is a summary of the ranking of the technically feasible NOx control technologies for the 

proposed natural gas-fired boilers. While SCR systems can be designed to reduce NOx emissions by 

90%, the use of SCR systems cannot be expected to achieve this reduction efficiency on a long term basis. 

For natural gas combustion, the SCR is expected to reduce NOx emissions to 0.01 lb/mmBtu, or a NOx

emission rate of 7 parts per million (ppm) at 5% excess oxygen. 

 

TABLE 4-3. Ranking of the technically feasible NOx control technologies. 

Control System Expected Emission Rate, 

lb/mmBtu 

Package Boiler with Ultra Low NOx Burners, Overfire Air, and 

Flue Gas Recirculation, and Selective Catalytic Reduction 0.01 

Package Boiler with Ultra Low NOx Burners, Overfire Air, and 

Flue Gas Recirculation 0.02 

4.5 STEP 4. Evaluate the Most Effective Controls 

4.5.1 Rank No. 1: Selective Catalytic Reduction. 

The use of an SCR can achieve a NOx emission rate of 0.01 lb/mmBtu for these natural gas-fired boilers. 

Based on limiting the operation of each boiler to 6,200 hours per year, the SCR system could reduce NOx

emissions from 10.9 tons per year for the boiler with ultra low NOx burners, to 5.5 tons per year, equal to 

a reduction of 5.5 tons per year. 

4.5.1.1 Environmental Impacts. 

The primary environmental impact from the use of SCR on these boilers is a reduction in NOx emissions. 

The use of SCR would also have adverse environmental impacts. Ammonia slip emissions from the 

operation of the SCR system would result in direct emissions of ammonia and ammonium nitrate. 

Ammonia will react with sulfate in the atmosphere to form ammonium sulfate. Ammonium sulfate and 

ammonium nitrate are predominant sources of regional haze, and contribute to PM2.5. 

4.5.1.2 Energy Impacts. 

Energy impacts from the use of SCR would include the increased electric energy required for the induced 

draft fans overcome the increase in pressure drop across the SCR system. 
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TABLE 4-4. Estimated SCR NOx control system costs for each natural gas-fired boiler. 

 CAPITAL COST ANNUAL COST

Total Capital Cost 

Total Equipment Cost, 1999 Dollars $393,240 

Total Capital Cost, 1999 Dollars $668,508 

Total Capital Cost, 2009 Dollars $864,342 

Capital Recovery Factor, CRF 0.1098 

Total Capital Investment (TCI) $864,300 $94,900 

Reagent (19% Aqueous Ammonia) Costs 

Ammonia Cost ($1.30 per gal for 19% ammonia), $ per ton $1,620 

Uncontrolled NOx Emissions, ton/yr 10.9 

Moles ammonia per mole NOx 1.1 

Total Reagent Costs $7,500 

Total Labor Costs (2 hr per day) $36,500 

Maintenance Costs 

Maintenance Labor, hr/year 365 

Catalyst Inspection and Replacement Labor, hr per year 400 

Labor Cost, $ per year $38,250 

Material Cost, $ per year $38,250 

Total Annual Cost ($/yr) $76,500 

Catalyst Replacement Costs 

Catalyst Cost $190,000 

Sinking Fund Factor 0.174 

Total Catalyst Replacement Costs $33,000 

Total Overhead and Administrative Costs 2% of TCI $17,300 

TOTAL ANNUAL COST $248,400 

 Footnotes 

1. The cost of capital for this project is 7%, and the project life is 15 years. The annual cost of this investment is 

given by the capital recovery factor (CRF): 

 where: i = annual interest rate (decimal)

 n = control system life (years)

2. For the catalyst, the catalyst life is 5 years. The annual cost is given by the sinking fund factor (SFF): 

 

3. The SCR capital cost is the cost for a 150 mmBtu/hr boiler as given in the U.S. EPA NOx ACT document, 

Appendix A.2.3., available at http://www.epa.gov/ttn/nsr/gen/appendix.pdf . The CPI was used to escalate the 

costs to 2010. 

[ ] (1 ) 1

(1 )

+ −

+ = n

n

i

i i CRF

[ ] (1+ ) −1 = n i

i SFF
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4.5.1.3 Economic Impacts. 

The costs for SCR controls on these boilers would include the capital costs for the SCR and ancillary 

equipment, labor, auxiliary power requirements, ammonia, catalyst replacement, maintenance, and 

administrative costs. The SCR cost analysis is included in Table 4-4. From Table 4-4, an SCR system is 

expected to have a total capital requirement of $864,000 and a total annual cost of $248,400. The SCR 

system would reduce NOx emissions from each boiler by 5.4 tons per year. Based on these costs, the 

SCR system would have an average cost effectiveness of $45,800 per ton of NOx removed. 

4.5.1.4 Conclusion. 

The use of SCR on these natural gas-fired package boilers can achieve NOx emission rates of 0.01 

lb/mmBtu. However, each SCR system would have a total capital requirement of $864,000, and a total 

annual cost of $246,000. The SCR system would reduce NOx emissions from each boiler by 5.4 tons per 

year, resulting in an average cost effectiveness of $45,800 per ton of NOx removed. These costs are very 

high, indicating that the use of SCR on these natural gas-fired boilers is not an economically feasible 

control option. 

4.5.2 Rank No. 2: Package Boiler with Ultra Low NOx Burners. 

The use of package boilers with Ultra Low NOx Burners, Overfire Air, and Flue Gas Recirculation can 

achieve a NOx emission rate of 0.02 lb/mmBtu. 

4.6 STEP 5. Proposed Nitrogen Oxide BACT Determination. 

Based on this analysis, We Energies has concluded that the use of package boilers with Ultra Low NOx

Burners, Overfire Air, and Flue Gas Recirculation is the best available control technology (BACT) for 

NOx emissions from the natural gas-fired boilers B02 and B03. Based on this analysis, We Energies 

proposes the following limits as BACT for the control of NOx emissions from these boilers. 

(1) Nitrogen oxide (NOx) emissions from the natural gas-fired boilers B02 

and B03 shall be controlled using Ultra Low NOx Burners, Overfire 

Air, and Flue Gas Recirculation as the best available control 

technology. 

(2) Nitrogen oxide (NOx) emissions may not exceed 0.02 pounds per 

million Btu of heat input, averaged over any consecutive 30-day period. 

(3) The total heat input to boilers B02 and B03 combined may not exceed 

2,170,000 mmBtu in any consecutive 12-month period. 

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Chapter 5. Particulate Matter and PM10 Control 

Technology Review. 

Particulate matter (PM) emissions from natural gas-fired-fired boilers originate from ash in the fuel, and 

from products of incomplete. In Wisconsin, “particulate matter emissions” are defined under NR 

400.02(119), Wis. Adm. Code, as: 

(119) “Particulate matter emissions” means all finely divided solid or liquid material, other than 

uncombined water, emitted to the ambient air as measured by an applicable reference method or 

an equivalent or alternative method specified by the department. 

Based on this definition, PM may be solid or liquid materials. PM which exists as a solid or liquid at 

temperatures of approximately 250 o

F are measured using U.S. EPA’s Reference Method (RM) 5, and are 

referred to as “front half” emissions. PM which exists as a solid or liquid at the lower temperature of 32 o

F are measured using U.S. EPA’s RM 202, and is commonly referred to as “back half” or “condensable” 

PM. Condensable PM may include acid gases, volatile organic compounds (VOC) and other materials, 

but by definition does not include condensed water vapor. Because of these different temperatures at 

which PM emissions are measured, the amount of PM measured depends on the reference methods used. 

5.1 BACT Baseline. 

The natural gas-fired boilers will be subject to the Standards of Performance for Industrial-CommercialInstitutional Steam Generating Units under 40 CFR Part 60, Subpart Db. This subpart applies to steam 

generating units that commence construction, modification, or reconstruction after June 19, 1984, and that 

has a heat input capacity from fuels combusted in the steam generating unit greater than 100 mmBtu/hr. 

The only NSPS PM standard that is applicable to similar natural gas and distillate fuel oil-fired boilers is 

the opacity standard when fuel oil is fired under 40 CFR 60.43b(f) and NR 440.205(4)(f). This paragraph 

limits the opacity of emissions when distillate fuel oil is fired to no more than 20% (6-minute average). 

The exception is one 6-minute period per hour with opacity may not exceeding 27%. Because these are 

natural gas-fired boilers, this opacity standard does not apply. 

5.2 STEP 1. Identify Potential Control Technologies. 

Table 5-1 summarizes the particulate matter BACT emission limits for new and modified natural gasfired boilers in the U.S. EPA’s RACT/BACT/LAER Clearinghouse. The only technologies identified 

include good combustion practices and the use of clean fuels including natural gas. Emission limits range 

from 0.002 to 0.08 lb/mmBtu for natural gas combustion. Please note that many of the emission limits in 

these tables were expressed as pounds per hour. These rates were converted to lb/mmBtu to make the 

emission limits comparable. 
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TABLE 5-1. Natural gas-fired boiler particulate matter emission limits representing BACT from the U.S. EPA's RB

RBLC ID Facility Permit Date Process Thruput, mmBtu/hr Controls WV-0023 Longview Power, LLC - Maidsville 03/02/04 Auxiliary Boiler 225 GCP, CleaOR-0040 Klamath Generation, LLC 03/12/03 Auxiliary Boiler AR-0026 Pine Bluff Energy LLC-Pine Bluff Energy Center 05/05/99 Boiler 362 GCP, CleaAR-0057 Tenaska Arkansas Partners, LP 10/09/01 Boiler 122 GCP TX-0499 Sandy Creek Energy Station 07/24/06 Auxiliary Boiler 175 *ID-0017 SE Idaho Power County Energy Center 02/10/09 Package Boiler 250 GCP NJ-0042 Roche Vitamins 02/05/99 Boiler 134 None ListNJ-0036 AES Red Oak, LLC 10/24/01 Auxiliary Boiler 120 GCP TX-0414 Atofina Petrochemicals Port Arthur Complex 04/22/99 Supplement Boiler 227 Low Ash OK-0045 Redbud Power Plant 08/15/01 Auxiliary Boiler 20 Low Ash FNC-0101 Forsyth Energy Plant 09/29/05 Auxiliary Boiler 110 LNB, GCP IN-0085 PSEG Lawrenceburg Energy Facility 06/07/01 Auxiliary Boiler 125 GCP WI-0228 Wisconsin Public Service - Weston Plant 10/19/04 Auxiliary Boiler 230 GCP, NatuTN-0153 Williams Refining & Marketing, LLC 04/03/02 Boiler 180 OH-0310 American Municipal Power Generating Station 02/07/08 Auxiliary Boiler 150 *AL-0230 Thyssenkrupp Steel & Stainless USA, LLC 08/17/07 3 Boilers 65 ULNB, FGMS-0069 Dupont Delisle Facility 06/08/04 Boiler 231 Natural GVA-0278 Virginia Commonwealth University East Plant 03/31/03 3 Boilers 151 AL-0128 Alabama Power Co. - Theodore Cogeneration 03/16/99 Boiler 220 Natural GVA-0270 Virginia Commonwealth University East Plant 03/31/03 Boiler 150 GCP NJ-0043 Liberty Generating Station 03/28/02 Auxiliary Boiler 200 MN-0039 Minnesota Corn Processors 08/08/00 Boiler 237 Natural GAR-0070 Genova Arkansas I, LLC 08/23/02 Auxiliary Boiler 33 GCP NJ-0042 Roche Vitamins 02/05/99 Boiler 84 TX-0386 Calpine Amella Energy Center 03/26/02 Auxiliary Boiler 155 WI-0204 United Wisconsin Grain Producers- Ethanol Plant 08/14/03 Boiler 140 NJ-0042 Roche Vitamins 02/05/99 Boiler 118 None List

Footnotes “GCP” means good combustion practices. “SCR” means selective catalytic reduction. “LNB” means low NOx burner. “ULNB” mean“FGR” means flue gas recirculation. 
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5.3 STEP 2. Identify Technically Feasible Control Technologies. 

As noted above, data from the U.S. EPA’s RBLC indicate that the only technologies selected as BACT 

for new natural gas-fired boilers include good combustion practices and the use of clean fuels including 

natural gas. Other PM controls include fabric filter baghouses, electrostatic precipitators, and mechanical 

collectors such as multicyclones, and wet venturi scrubbers. 

5.3.1 Fabric Filter Baghouses. 

A fabric filter baghouse (FFB) separates dry particles from the boiler flue gas by filtering the flue gas 

through fabric filters or “bags”. The components of a FFB include the fabric filters, a tube sheet to 

support the bags, a gas-tight enclosure, a mechanism to clean accumulated PM from the bags, and a 

hopper to collect accumulated ash. Baghouses are compartmentalized to facilitate cleaning and to provide 

for maintenance and repair. When the pressure drop across a compartment increases to a specified limit, 

the accumulated PM is removed by placing that compartment in the cleaning mode. 

PM laden flue gas enters the FFB and passes through the bags. As the flue gas flows through the fabric 

filter media, a layer of collected material, called the “filter cake”, builds up on the fabric. Both the filter 

media and the filter cake are important for the particulate filtration performance of the baghouse. For 

woven filter media, the filter cake is actually the primary control mechanism. Particles are collected on 

the filter cake through impaction and interception in a mechanism called “sieving”. In addition, the filter 

cake acts like a fixed-bed reactor. The ash collected in the filter cake has active reagents such as calcium 

oxide (CaO) and unburned carbon which can react with gaseous air pollutants as they pass through the 

filter cake. This baghouse mechanism contributes to greater absorption and control of air pollutants 

including sulfur dioxide (SO2), sulfuric acid mist, and hazardous air pollutants including mercury, 

hydrogen chloride (HCl), and hydrogen fluoride (HF). A depiction of the mechanism for particulate 

removal on the filter media is shown in Figure 5-1. 

FFB have several methods for cleaning, including reverse gas (RGFFB), reverse air with mechanical 

shakers, and pulse jet (PJFFB). In a RGFFB, the fly ash is collected on the inside of the bags. Each 

compartment of a RGFFB is periodically taken out of service for cleaning by circulating clean flue gas 

from the outlet plenum backward through the offline compartment. This dislodges the collected dust, 

which falls into hoppers. In a PJFFB, the fly ash is collected on the outside of the bags. Cleaning is 

normally accomplished on line by directing a pulse of air backward through the bag. The air pulse 

dislodges the fly ash, which falls into hoppers. A PJFFB can operate at higher air-to-cloth ratios than a 

RGFFB. However, because the pulse jet cleaning method is more aggressive than in the RGFFB, the 

bags in a RGFFB normally have a longer service life. 

FFBs have several important advantages when used for PM control from coal-fired boilers, including high 

particulate matter control efficiencies which are largely independent of fuel characteristics, relatively 

constant outlet grain loading over the entire boiler load range, and simple operation and maintenance. 

The primary disadvantage of fabric filter baghouses is the relatively high pressure drop across the 

baghouse as compared to a dry ESP and the resulting increased fan power requirements. 
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FIGURE 5-1. Depiction of the flue gas flow through the fabric filter baghouse filter cake showing 

the mechanism for particulate collection. 

Dust Laden 

Flue Gas

Cleaned Flue Gas 

to Atmosphere

Bag Fabric

Layer of Collected 

Ash or "Filter Cake"

RTP Environmental Associates, Inc.

5.3.2 Dry Electrostatic Precipitators. 

Electrostatic precipitators (ESP) are a common PM control system for both coal and biomass-fired 

boilers. However, ESPs are not normally used on natural gas-fired boilers. An ESP uses a large 

enclosure to slow the gas stream, which allows more time to electrostatically charge particulates and 

collect them in the ESP. An ESP is arranged in a series of fields which consist of negatively charged 

discharge electrodes and positively charged collection plates. The discharge electrodes impart a negative 

charge to particles in the gas stream. The negatively charged particles then migrate to the larger 

positively charged plates. PM collected on the plates is periodically removed by rapping the plate. Most 

of the PM knocked off the plates falls into collection hoppers for removal. A portion of the collected PM 

is re-entrained in the gas stream during rapping. This re-entrained PM is normally collected in 

subsequent sections of the ESP. 

ESP’s may be located either upstream of the air heater (hot-side ESP) or downstream of the air heater 

(cold-side ESP). The location is selected to achieve the best PM resistivity1

 conditions. Most modern 

 

1

 Gas composition, temperature, and particle composition all influence resistivity, which is a measure of 

the ability of a particle to retain an electrostatic charge. The ability to collect particles using electrostatic 
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ESPs are cold-side ESPs. Factors affecting the PM collection efficiency of an ESP include flue gas flow 

rate through the ESP, total plate area, PM resistivity, voltage, and the sectionalization of the ESP. The 

smaller the collection area of the ESP, the narrower the acceptable resistivity range becomes. To 

optimize particulate resistivity and maximize collection efficiency, many ESPs utilize a sulfur trioxide 

(SO3) injection system to condition the ash and reduce particulate resistivity. In addition, modern ESP 

controls allow the ESP operation to be optimized to maximize PM control through overall ESP 

performance management, power optimization, and programmed cleaning cycles. Finally, good 

sectionalization of the ESP is important to maximize ESP performance and reliability. 

5.3.3 Wet Electrostatic Precipitators. 

The principle of operation of a wet ESP is similar to a dry ESP. Particulate matter in the flue gas is 

exposed to an electric field which induces a charge on the particle which is then drawn to an oppositely 

charged collection electrode. However, in a wet ESP, the flue gas is cooled below the dew point and 

consequently particulate matter may be present as either solid or liquid particles. A recent application of 

wet ESPs is downstream of a wet FGD for the control of sulfuric acid mist on large, utility scale boilers 

firing high sulfur eastern coals. In this application, the flue gas temperature is below the sulfuric acid and 

water saturation temperatures as it passes through the wet ESP. As such, water droplets and other 

condensable materials in the flue gas, including sulfuric acid, are charged and collected by the ESP plates. 

Filterable PM not entrained from the FGD system may also be collected in the wet ESP. The collection 

electrodes are either continuously or periodically flushed with water to remove collected materials. 

Although wet ESPs can be effective for removing sulfuric acid mist downstream of a wet FGD when 

firing high sulfur coals, wet ESPs have not been used for natural gas-fired boilers. 

5.3.4 Wet Scrubbers. 

Wet scrubbers are used in many industrial processes to control PM emissions. Wet scrubbers reduce PM 

emissions through several mechanisms, including condensation, inertial impaction of PM with water 

droplets, and reactions of PM and PM precursors with the scrubber reagent. 

5.3.5 Mechanical Collectors. 

Mechanical collectors are not as effective as a FFB or ESP for particulate matter control. Therefore, 

while mechanical collectors are a technically feasible BACT alternative, the performance of mechanical 

collectors is inferior to FFBs and ESPs. 

 

attraction is directly related to particle resistivity. If the particle resistivity is outside the design range, 

particle collection efficiency is reduced. 
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5.4 STEP 3. Rank the Technically Feasible Technologies. 

All of the identified PM control technologies, including fabric filter baghouses, dry ESPs, wet ESPs, wet 

scrubbers, and mechanical collectors are technically feasible technologies for natural gas-fired boilers. 

However, none of these technologies have been required as BACT for new or modified natural gas -fired 

boilers. This is because natural gas has almost no inert materials or ash, so that the “uncontrolled” PM 

and PM10 emissions from the combustion of these fuels is as low as the controlled PM emission rate from 

solid fuel combustion using state-of-the art air pollution control systems like fabric filter baghouses. As a 

result, for natural gas combustion, none of the control technologies are expected to achieve emission rates 

lower than the use of natural gas fuel and good combustion practices designed to minimize products of 

incomplete combustion. The natural gas emission rate is expected to be 0.0076 lb/mmBtu for both PM 

and PM10 emissions. 

5.5 STEP 4. Evaluate the Most Effective Controls. 

The combustion of only natural gas is expected to achieve an emission rate of 0.0076 lb/mmBtu for both 

PM and PM10. This is the highest ranked level of control. 

5.6 STEP 5. Proposed Particulate Matter BACT Determination. 

Based on this analysis, We Energies has concluded that the use of package boilers firing only natural gas 

is the best available control technology (BACT) for the control of PM and PM10 emissions from the 

natural gas-fired boilers B02 and B03. Based on this analysis, We Energies proposes the following limits 

as BACT for the control of PM and PM10 emissions from these boilers. 

(1) Particulate matter and PM10 emissions from the natural gas-fired boilers 

B02 and B03 shall be controlled using Ultra Low NOx Burners, 

Overfire Air, and Flue Gas Recirculation as the best available control 

technology. 

(2) Particulate matter and PM10 emissions may not exceed 0.0076 pounds 

per million Btu of heat input. 

(3) Compliance with this emission limit shall be based upon the 

measurement of particulate matter emissions in accordance with U.S. 

EPA Reference Method 5, 5B, or 17, and U.S. EPA Other Method 28, or 

another method approved in writing by the department.

(4) The total heat input to boilers B02 and B03 combined may not exceed 

2,170,000 mmBtu in any consecutive 12-month period. 
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Chapter 6. PM2.5 Control Technology Review. 

Particulate matter emissions that are less than 2.5 micrometers in diameter are known as "fine" particles, 

and are referred to as PM2.5. Various pollutants contribute to ambient PM2.5 concentrations. Fuel 

combustion, including natural gas, result in direct emissions of PM2.5. In addition, PM2.5 “precursors” can 

also result in the formation of PM2.5 in the atmosphere. The U.S. EPA has identified SO2, NOx, volatile 

organic compounds (VOCs), and ammonia (NH3) as PM2.5 precursors. These gas-phase precursors 

undergo chemical reactions in the atmosphere to form secondary PM2.5. Direct emissions of PM2.5 from 

combustion includes solid or filterable PM2.5, and condensable or back half PM2.5. 

Under the recently promulgated rules to revise the New Source Review (NSR) program in 40 CFR Part 

52 to include PM2.5, the EPA identified the following PM2.5 pollutants, and their significant levels: 

1. 10 ton per year of direct PM2.5 emissions 

2. 40 ton per year of SO2 emissions 

3. 40 ton per year of NOx emissions unless demonstrated not to be a PM2.5 precursor. 

Based on the final rules, VOC and ammonia may not be considered to be precursors to PM2.5 unless the 

state demonstrates that these emissions are a significant contributor to the area PM2.5 concentrations. In 

addition, during the PM2.5 SIP development period, the EPA has indicated that NOx emissions will not be 

regulated as a PM2.5 precursor to give States the opportunity to determine whether NOx emissions are a 

significant contributor to the ambient PM2.5 concentration2

. 

6.1 BACT Baseline. 

There are no state implementation plan emission limits or new source performance standards for direct 

PM2.5 emissions from these natural gas-fired boilers. 

Direct PM2.5 emissions from the combustion of natural gas include filterable PM2.5, and condensable 

PM2.5. The U.S. EPA’s Compilation of Air Pollutant Emission Factors, AP-42, 5th Edition, Table 1.4-2 

includes emission factors for filterable and condensable PM emissions. The total filterable plus 

condensable emission factor is 7.6 lb/106

 scf natural gas, equal to 0.0076 lb/mmBtu. For this analysis, all 

PM emissions from natural gas combustion are also expected to be PM2.5. 

 

2

 Federal Register / Vol. 73, No. 96 / Friday, May 16, 2008, page 28343. 
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6.2 STEP 1. Identify All Potential Control Technologies. 

6.2.1 Direct PM2.5 Emissions. 

As noted in the PM and PM10 control technology review, the technologies selected as BACT include 

primarily fabric filter baghouses and electrostatic precipitators. Other controls include mechanical 

collectors such as multicyclones, and wet venturi scrubbers. 

6.2.2 PM2.5 Precursors. 

As noted above, the U.S. EPA has identified SO2, NOx, VOCs, and ammonia (NH3) as PM2.5 precursors. 

Based on the final rules, volatile organic compounds (VOC) and ammonia (NH3) may not be considered 

to be precursors to PM2.5 unless the State demonstrates that these emissions are a significant contributor to 

the area PM2.5 concentrations. This control technology review includes a complete control technology 

review for SO2, NOx, and VOC emissions. Therefore, further analysis of these pollutants as PM2.5

precursors is unnecessary. 

6.3 STEP 2. Identify Technically Feasible Control Technologies. 

As noted above, data from the U.S. EPA’s RBLC indicate that the technologies selected as BACT include 

primarily fabric filter baghouses and electrostatic precipitators. Other controls include mechanical 

collectors such as multicyclones, and wet venturi scrubbers. 

6.3.1 Fabric Filter Baghouses. 

Fabric filter baghouse (FFB) were discussed in the PM/PM10 control technology review. Fabric filter 

baghouses are very effective at reducing PM emissions, especially in the fine particle size ranges. Figure 

6-1 shows the cumulative emission factor for PM emissions versus the particle size for several different 

PM control systems for coal combustion3

. Figure 6-1 shows that fabric filter baghouses are very effective 

in reducing PM emissions, especially fine PM. 

As noted in the PM/PM10 analysis, the primary filtering media in a fabric filter baghouse is actually the 

filter cake rather than the fabric itself. The filter cake acts much like a fixed-bed reactor, contributing to 

greater absorption of pollutants, including fine particulate matter, sulfur dioxide (SO2), sulfuric acid mist, 

mercury and hazardous air pollutants including hydrogen chloride (HCl) and hydrogen fluoride (HF). 

Since pollutants such as sulfuric acid mist, HCl, and HF directly contribute to condensable PM, fabric 

filter baghouses are also very effective at reducing the condensable portion of PM2.5 emissions by 

controlling these PM2.5 precursors in the baghouse. However, because natural gas has only trace levels of 

sulfur, chlorine, and fluorine, these condensable PM removal mechanisms are of limited importance to 

natural gas combustion. 

 

3

 Data is from the Air Pollution Engineering Manual, Air & Waste Management Association, coal combustion 

sources with various air pollution control systems. 
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FIGURE 6-1. Cumulative emission factor for PM emissions versus the particle size. 

0.00

0.01

0.10

1.00

10.00

100.00

0.1 1 10 100

Particle Size, um

Cummulative Emission Factor, lb/ton

Multiple Cyclones

Electrostatic 

Precipitator

Fabric Filter 

Baghouse

6.3.1.1 Filter Media for Fabric Filter Baghouses and PM2.5 Control. 

There is a wide variety of fabric filter material available for fabric filter baghouses. For reverse air 

baghouses, the most common fabric is a simple woven fabric such as woven fiberglass. For pulse jet 

baghouses, the most common fabric is a woven fabric backing called a “scrim” with a felted layer needle 

punched into the scrim. Other fabric materials include Nomex®, Ryton®, Gortex®, and Hyglass®. 

Developments have been made in fabric filter media to improve PM2.5 control. Advanced filter media 

provide enhanced PM2.5 emissions control. The U.S. EPA implemented the Environmental Technology 

Verification (ETV) program in 1995 to generate independent data on the performance of innovative 

pollution control technologies. The ETV program identified baghouse filtration products as a high 

priority technology group in 2000. As stated in a report4

, “New fabrics have been developed that offer the 

combination of highly effective particulate removal and low operational pressure drop. Improving 

performance of the fabrics can be observed in verification test data trends.” Completed verifications of 

baghouse filtration products are available from the U.S. EPA’s ETV program at 

 

4 The Evolution of Improved Baghouse Filter Media as Observed in the Environmental Technology 

Verification Program, Andrew Trenholm, RTI International, John Mycock, ETS Inc., John McKenna, ETS Inc., 

and Michael Kosusko, U.S. EPA, Presented at the Air & Waste Management Association Annual Conference, June, 

2008, available at: http://epa.gov/etv/pubs/600etv08023.pdf . 
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http://www.epa.gov/nrmrl/std/etv/vt-apc.html. ETV test results indicate filter media with direct PM2.5

emission levels as low as 0.000007 gr/dscf, equal to approximately 0.0001 lb/mmBtu. Note, however, 

that this is the tested performance for the filter media, not for the entire baghouse system. Leaks which 

occur in even the best state-of-the-art baghouse will increase the outlet grain loading, even when using 

advanced filter media. 

Baghouse filtration product enhancements include felted bags and high efficiency microfiber felts, 

intrinsically coated (IC) bags, membrane bags, and electrostatic fabric filter technology. 

Felted bags are often used in pulse-jet fabric filter baghouses which use higher energy cleaning systems 

than in a reverse air baghouse. Felted filters don’t require the initial filter cake to collect fine particulates 

as compared to woven filters. Felted filters are generally 2 to 3 times thicker than woven filters. This 

thicker overall filter improves fine particle collection, since each individual randomly oriented fiber acts 

as a target for particle capture by impaction and interception. Small particles are collected on the outer 

surface of the filter, rather than depending on the filter cake to achieve fine particle control. Figure 6-2 is 

a depiction of the fabric filter media filtration process for a simple woven fabric as compared to a felted 

fabric media. 

High efficiency microfiber felts are based on the same concept as felted filter media, but use ultra-fine 

fibers to enhance fine particulate matter control. The U.S. EPA’s ETV program tested outlet PM2.5 levels 

as low as 0.0004 gr/dscf (0.00055 lb/mmBtu). 

FIGURE 6-2. Depiction of the fabric filter media filtration process for a simple woven fabric as 

compared to a felted fabric media. 

From the U.S. EPA’s Air Pollution Training Institute (APTI) Course Fabric Filter Operation. 
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Intrinsically coated bags use a fabric made of coated fibers. The coating is typically Teflon® or a 

similar fluoro-polymer material. Intrinsically coated bags improve bag durability and also reduce the pore 

size between fibers, improving direct PM2.5 control. However, this coating also inhibits filter cake 

formation. While this can help reduce the pressure drop across the baghouse, the reduced filter cake 

accumulation may reduce the control effectiveness of the fabric filter baghouse for PM2.5 precursors and 

condensable PM2.5 species by limiting the contact between these precursors and solids in the filter cake 

which would otherwise remove these precursors. 

Membrane bags have a polytetrafluoroethylene (PTFE) coating such as Teflon® applied to the surface 

of the fabric rather than to the individual fibers. Membrane bags have even smaller pore sizes than 

intrinsically coated bags. This smaller pore size may further improve direct PM2.5 control. However, the 

coating over the entire bag further inhibits filter cake formation and may further reduce the control 

effectiveness of the fabric filter baghouse for PM2.5 precursors and condensable PM2.5 species by limiting 

the contact between these precursors and solids in the filter cake. 

High efficiency microfiber felts are based on the same concept as felted filter media, but use ultra-fine 

fibers to enhance fine particulate matter control. The U.S. EPA’s ETV program tested outlet PM2.5 levels 

as low as 0.0004 gr/dscf (0.00055 lb/mmBtu). 

Electrostatic fabric filter baghouses have been developed through a partnership of the U.S. EPA and 

Southern Research Institute. The technology is licensed to General Electric Energy (GE) and is marketed 

as the Max-9TM electrostatic fabric filter baghouse. The Max-9TM is a dust collection technology that 

combines discharge electrodes and fabric filters in the same casing to provide high collection efficiency 

while operating at a 60 to 80% lower system pressure drop. The Max-9 ESFF is an electrostatic 

precipitator/pulse-jet baghouse hybrid, employing high voltage discharge electrodes to charge particulate, 

but with fabric filters instead of collecting plates in the casing. GE Power states that “The Max-9 ESFF 

provides collection efficiencies an order of magnitude higher than those achieved by either the best fabric 

filters or precipitators currently on the market, with demonstrated efficiency of 99.999%.”5

GE states that the ESFFB technology is recommended for use in conjunction with a primary particulate 

control device; i.e., the Max-9 is recommended as a “polishing” control device for PM emissions. The 

U.S. EPA and the Southern Research Institute conducted pilot testing of a slip stream at a major power 

plant in the Southern United States. The pilot plant was configured to allow testing with or without 

discharge electrode energization. With the electrostatic stimulation turned on, collection efficiency 

increased from 99.99% to 99.999%, a full order of magnitude better. Plus, there was an 80% reduction in 

pressure drop, and an 80-90% reduction in sub-micron particle emissions. 

While the Max-9 ESFFB technology shows great promise, this technology has not been demonstrated on 

a full scale facility. Therefore, this technology is not technically feasible for these natural gas-fired 

boilers. 

 

5

 As stated at: http://www.gepower.com/prod_serv/products/particulate_matter/en/max9/index.htm. 
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6.3.2 Dry Electrostatic Precipitators. 

Electrostatic precipitators (ESP) are a common PM control system for both coal and biomass-fired 

boilers, and are discussed in the PM/PM10 control technology review. While dry ESPs are a technically 

feasible control technology, a dry ESP is expected to have significantly lower control efficiencies for both 

direct filterable PM2.5 emissions, and also for PM2.5 precursors. 

6.3.3 Wet Electrostatic Precipitators. 

The principle of operation of a wet ESP is similar to a dry ESP. Wet ESPs can be effective for removing 

sulfuric acid mist downstream of a wet FGD when firing high sulfur coals. However, we are not aware of 

the use of a wet ESPs as a PM control system for natural gas-fired boilers. Wet ESPs experience current 

suppression when PM concentrations in the electrode wash water are too high which would reduce or 

eliminates the PM control effectiveness of the wet ESP. Therefore, a wet ESP must be considered as a 

secondary or “polishing” PM control device. 

While wet ESPs cannot operate as the primary control device, wet ESPs have shown promise at reducing 

PM2.5 emissions as a polishing device. A pilot wet ESP was installed at First Energy’s Bruce Mansfield 

Plant in Shippingport, PA. The pilot wet ESP uses a slipstream of flue gas from the outlet of an FGD 

system on an 835 MW unit firing 3% sulfur coal. The plant installed the pilot WESP to test for PM2.5 and 

SO3 mist removal as a potential control technology to reduce visible emissions. The slipstream results 

indicate reductions in PM2.5 emissions from 62% to 96%. These results also showed similar high SO3

mist removal, which may account for much of the PM2.5 emission reductions. However, these tests were a 

slipstream test, not a fullscale test, and were for a limited duration. 

6.3.4 Wet Scrubbers. 

Wet scrubbers are used in many industrial processes to control PM emissions. Wet scrubbers reduce PM 

emissions through several mechanisms, including condensation, inertial impaction of PM with water 

droplets, and reactions of PM and PM precursors with the scrubber reagent. 

6.3.5 Mechanical Collectors. 

Mechanical collectors are not as effective as a FFB or ESP for PM control, especially for fine PM control. 

Therefore, while mechanical collectors are a technically feasible BACT alternative, the performance of 

mechanical collectors is inferior to FFBs and ESPs. 

6.4 STEP 3. Rank the Technically Feasible Technologies. 

Direct PM2.5 emissions from the combustion of natural gas is expected to be very small, equal to 0.0076 

lb/mmBtu. In addition, fabric filter baghouses, dry ESPs, wet ESPs, wet scrubbers, and mechanical 

collectors are technically feasible technologies. However, we are not aware of the use of any post 

combustion PM control systems on any natural gas-fired boiler. Further, because of the very low 

expected PM2.5 emission rates from the combustion of natural gas, there is no basis to conclude that post 
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combustion PM controls would actually result in reductions in PM2.5 emissions. Therefore, the highest 

ranked or most effective PM2.5 control technology for these natural gas-fired boilers is the use of natural 

gas as the fuel. 

6.5 STEP 4. Evaluate the Most Effective Controls. 

Based on the ranking summarized in Table 6-1, the use of natural gas fuel and good combustion practices 

designed to minimize products of incomplete combustion is expected to achieve a PM2.5 emission rate of 

0.0076 lb/mmBtu. The use of additional add on controls will not reduce emissions below these levels. 

6.6 STEP 5. Proposed PM2.5 BACT Determination. 

Based on this analysis, We Energies has concluded that the use of package boilers firing only natural gas 

is the best available control technology (BACT) for the control of PM2.5 emissions from the natural gasfired boilers B02 and B03. Based on this analysis, We Energies proposes the following limits as BACT 

for the control of PM and PM10 emissions from these boilers. 

(1) PM2.5 emissions from the natural gas-fired boilers B02 and B03 shall be 

controlled using Ultra Low NOx Burners, Overfire Air, and Flue Gas 

Recirculation as the best available control technology. 

(2) PM2.5 emissions may not exceed 0.0076 pounds per million Btu of heat 

input. 

(3) The total heat input to boilers B02 and B03 combined may not exceed 

2,170,000 mmBtu in any consecutive 12-month period. 

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Chapter 7. Sulfur Dioxide (SO2) Control 

Technology Review. 

Sulfur dioxide (SO2) emissions from natural gas-fired boilers result from the oxidation of sulfur in the 

fuel. During combustion, the majority of the sulfur is emitted as SO2. A small portion of the sulfur is 

further oxidized to sulfur trioxide (SO3). When the flue gas temperature drops below the dew point 

temperature, sulfur trioxide is converted to sulfuric acid (H2SO4). Therefore, control technologies which 

control SO2 emissions also reduce sulfuric acid mist emissions to varying degrees. 

7.1 BACT Baseline. 

The proposed natural gas-fired boilers would be subject to the Standards of Performance for IndustrialCommercial-Institutional Steam Generating Units under 40 CFR Part 60, Subpart Db. This subpart 

applies to units that commence construction, modification, or reconstruction after June 19, 1984, and have 

a heat input from fuels combusted in the steam generating unit greater than 100 mmBtu/hr. The SO2

standards in Subpart Db are only applicable when distillate fuel oil is fired. Under 40 CFR 60.41b and 

NR 440.205(2)(zj), "very low sulfur oil" is defined as: 

 (zj) “Very low sulfur oil” means an oil that contains no more than 0.50 

weight percent sulfur or that, when combusted without sulfur dioxide 

emission control, has a sulfur dioxide emission rate equal to or less than 

215 ng/J (0.50 lb/million Btu) heat input. 

For facilities combusting only very low sulfur oil, SO2 emissions are limited to 0.50 lb/mmBtu. 

According to 40 CFR 60.42b(j) and NR 440.205(3)(j), affected sources combusting only very low sulfur 

oil are not subject to the SO2 percent reduction requirements. According to 40 CFR 60.42b(j) and NR 

440.205(6)(j) and NR 440.205(8)(f), facilities that combust very low sulfur oil are not required to conduct 

performance testing or install and operate continuous monitors for SO2 if fuel receipts are maintained. 

Because these boilers will fire only natural gas, there are no applicable NSPS SO2 standards. 

7.2 STEP 1. Identify Potential Control Technologies. 

Potential SO2 control technologies include pre-combustion controls such as low sulfur fuels, and post 

combustion controls, such as flue gas desulfurization. Table 7-1 summarizes the SO2 BACT emission 

limits for new and modified natural gas-fired boilers in the U.S. EPA’s RACT/BACT/LAER 

Clearinghouse. The only technologies identified include the use of clean fuels. Emission limits range 

from 0.0006 to 0.006 lb/mmBtu for natural gas combustion. Please note that many of the emission limits 

in these tables were expressed as pounds per hour. These rates were converted to lb/mmBtu to make the 

emission limits comparable. 
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TABLE 7-1. Natural gas-fired boiler SO2 emission limits representing BACT from the U.S. EPA's RBLC database. 

RBLC ID Facility Permit Date Process Thruput, mmBtu/hr Controls *AL-0230 Thyssenkrupp Steel & Stainless USA 08/17/07 3 Boilers 65 OH-0310 American Municipal Power Generating Station 02/07/08 Auxiliary Boiler 150 WI-0228 Wisconsin Public Service - Weston Plant 10/19/04 Auxiliary Boiler 230 Natural GOK-0045 Redbud Power Plant 08/15/01 Auxiliary Boiler 20 Pipeline NAR-0026 Pine Bluff Energy LLC-Pine Bluff Energy Center 05/05/99 Boiler, Natural Gas 362 Low SulfuTX-0499 Sandy Creek Energy Station 07/24/06 Auxiliary Boiler 175 NJ-0042 Roche Vitamins 02/05/99 Boiler 3 (Nat Gas) 152 None ListVA-0278 Virginia Commonwealth University East Plant 03/31/03 Boiler 151 Low SulfuVA-0270 Virginia Commonwealth University East Plant 03/31/03 Boiler 150 Low SulfuNJ-0042 Roche Vitamins 02/05/99 Boiler 134 None ListNJ-0042 Roche Vitamins 02/05/99 Boiler 118 None ListNJ-0042 Roche Vitamins 02/05/99 Boiler 84 None ListMN-0039 Minnesota Corn Processors 08/08/00 Boiler 237 Natural GNJ-0043 Liberty Generating Station 03/28/02 Auxiliary Boiler 200 None NJ-0036 AES Red Oak LLC 10/24/01 Auxiliary Boiler 120 Natural GTX-0386 Calpine Amella Energy Center 03/26/02 Auxiliary Boiler 155 NC-0101 Forsyth Energy Plant 09/29/05 Auxiliary Boiler 110 Natural GIN-0085 PSEG Lawrenceburg Energy Facility 06/07/01 Auxiliary Boiler 125 Natural GAR-0057 Tenaska Arkansas Partners, LP 10/09/01 Boiler 122 Natural GCA-1024 AES Huntington Beach 08/01/02 Boiler: 225 Sulfur In FOH-0241 Miller Brewing Company - Trenton 05/27/04 Boiler 238 

Footnotes “GCP” means good combustion practices. “SCR” means selective catalytic reduction. “LNB” means low NOx burner. “ULNB” mean“FGR” means flue gas recirculation. 
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7.3 STEP 2. Identify Technically Feasible Control Technologies. 

As noted above, the only technologies identified as BACT in the U.S. EPA’s RACT/BACT/LAER 

Clearinghouse for new natural gas-fired boilers include the use of low sulfur fuels including natural gas. 

However, post combustion controls including flue gas desulfurization (FGD) are technically feasible 

control options. However, while these technologies may be technically feasible, because the fuel sulfur 

levels are so low in natural gas, FGD systems are not expected to reduce potential SO2 emissions 

significantly below the uncontrolled levels from the combustion of natural gas. 

7.3.1 Low Sulfur Fuels and Fuel Cleaning. 

Sulfur dioxide emissions may be controlled by the use of post-combustion FGD systems designed to 

remove SO2 from the flue gas after combustion. Because SO2 emissions occur from the oxidation of fuel 

sulfur, SO2 emissions may also be controlled by limiting the fuel sulfur content. As noted above, the only 

technologies identified as BACT in the U.S. EPA’s RACT/BACT/LAER Clearinghouse for new natural 

gas and distillate fuel oil-fired boilers include the use of these low sulfur fuels. 

Under the Acid Rain Program in 40 CFR 72.2, pipeline natural gas means a naturally occurring fluid 

mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath 

the Earth's surface that maintains a gaseous state at standard atmospheric temperature and pressure under 

ordinary conditions, and which is provided by a supplier through a pipeline. Pipeline natural gas contains 

0.5 grains or less of total sulfur per 100 standard cubic feet. Additionally, pipeline natural gas must either 

be composed of at least 70 percent methane by volume or have a gross calorific value between 950 and 

1100 Btu per standard cubic foot. Based on these values, the uncontrolled SO2 emission rate of pipeline 

natural gas is: 

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡ = 1.0 mmBtu

1,000,000 Btu

950 Btu

1.0 scf NG

1.0 lb S

2.0 lbSO

7,000 grains S

1.0 lb S

100 scf NG

0.5 grains S 2 ERNG

ERNG = 0.0015 lb SO2/mmBtu 

An emission rate of 0.0015 lb/mmBtu is equal to an SO2 concentration in the flue gas of 0.8 parts per 

million (ppm) at 5% excess oxygen. 

The emission factor for uncontrolled SO2 emissions from the U.S. EPA’s AP-42, Compilation of Air 

Pollutant Emission Factors, 5th Edition, section 1.4, Natural Gas Combustion, is 0.6 pounds per million 

cubic feet of natural gas. At a natural gas heat value of 1,000 Btu/scf, this emission factor is equal to 

0.0006 lb/mmBtu. 

7.3.2 Flue Gas Desulfurization. 

Flue Gas Desulfurization (FGD) technologies are primarily used for large utility and industrial coal-fired 

boilers. FGD systems may be broadly classified as “wet” and “dry” systems. Wet FGD systems are 
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characterized by low flue gas outlet temperatures, saturated or wet flue gas conditions, and a wet sludge 

reaction product which is dewatered before reuse or disposal. For most solid fuels and boiler types, the 

flue gas saturation temperature is about 130 o

F. In wet FGD applications, the primary PM control system 

is located upstream of the wet FGD system so that the fly ash and FGD system reaction products are 

collected separately. This is necessary to avoid saturated conditions in the PM control system which 

would plug a fabric filter baghouse or dry ESP. Wet FGD systems are also characterized by relatively 

high water use as compared to dry FGD systems. 

Dry FGD systems are characterized by outlet flue gas temperatures about 20 to 50 °F above the saturation 

point, or about 150 o

F to 180 oF. In dry FGD applications, the PM system is located downstream of the 

dry FGD system so that the fly ash and the FGD reaction product are commingled into a single stream. 

Dry FGD systems also have reduced water use as compared to wet FGD systems. 

7.3.2.1 Wet Flue Gas Desulfurization. 

Wet FGD is a well demonstrated technology for the control of SO2 emissions from utility scale coal-fired 

boilers. However, we are not aware of the use of wet FGD systems on any natural gas or distillate fuel 

oil-fired boilers either in the U.S. or abroad. In a wet FGD system, the flue gas is exposed to an alkaline 

reagent which reacts with SO2 to form a solid. There are several alkaline reagents used in wet FGD 

systems, including water-based slurries of lime or limestone, liquors containing dissolved sodium or 

magnesium salts, or amine based liquors including ammonia. 

Regardless of the wet FGD design, the flue gas leaving the absorber is saturated with water, and the stack 

will have a visible condensed moisture plume. The conditions downstream of the absorber are highly 

corrosive, requiring highly corrosion-resistant materials for the downstream ductwork and stack. 

Equipment is also needed to manage the condensation that occurs on the downstream ductwork and in the 

stack. The wet FGD reaction products also require dewatering, usually by a combination of hydroclones 

and vacuum filters. Large areas are needed to manage the dewatering and byproduct storage, as well as 

the substantial water treatment facilities required for the FGD systems. These factors contribute to the 

high capital and operating costs of wet FGD systems. 

7.3.2.1.1 Advanced Wet FGD Designs. 

The first FGD systems in the U.S. were installed largely in response to the 1971 Clean Air Act. Most of 

these original FGD systems were calcium based wet FGD systems. About half of these early systems 

were lime and the other half limestone. Many of these FGD systems were plagued with operational issues 

including scaling, plugging, and low SO2 removal. These first wet FGD systems utilized spray tower 

absorbers, often without a perforated plate tray, as the method for contacting the flue gas with the reagent. 

FGD systems installed in the 1990’s were 2nd and 3rd generation systems which generally achieved greater 

than 90% SO2 removal with improved reliability. The limestone systems installed during this time were 

mostly forced oxidation systems which demonstrated the ability to achieve similar performance and 

reliability as lime systems. The SO2 removal efficiencies of the 2nd and 3rd generation systems were 
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improved primarily by improving gas to liquid contact. These improvements include absorption trays 

with perforated plates and multiple levels of interspatial reagent spray nozzles. 

FGD system suppliers have introduced several new designs to improve the flue gas to FGD liquid reagent 

contact and minimize operating costs. Designs such as the Jet Bubbling Reactor developed by Chiyoda 

and Alstom’s Flowpac systems were developed to improve the gas-to-liquid contact by forcing the flue 

gas to bubble through the liquid reagent using a gas sparger design rather than spraying the alkaline slurry 

into the gas stream. Mitsubishi developed the Double Contact Flow Scrubber (DCFS) which uses 

‘fountains’ of slurry to contact the flue gas. Babcock Power Environmental Inc. utilizes bidirectional 

sprays and wall rings to maximize contact between the flue gas and liquid reagent. All of these wet FGD 

systems use the limestone forced oxidation (LSFO) process. 

7.3.2.1.2 Wet Limestone with Forced Oxidation. 

In recent years, the WFGD market has turned almost completely to the use of wet lime or limestone with 

forced oxidation on utility scale coal-fired boilers because it improves SO2 control, reduces chemical 

scale formation, and produces gypsum, a stable and potentially saleable byproduct. Wet limestone with 

forced oxidation (LSFO) is a modification of the conventional wet limestone FGD process. A 

conventional wet limestone system forms a scrubber product composed mostly of calcium sulfite 

(CaSO3). The LSFO process further oxidizes calcium sulfite to calcium sulfate dihydrate (gypsum, or 

CaSO4·2H2O). The gypsum content of the scrubber sludge is typically 95% on a dry basis, making the 

sludge easier to dewater. Gypsum is a naturally occurring mineral that is used as a raw material in the 

manufacture of plaster, wallboard, Portland cement, agricultural soil conditioners, and other products. 

In the LSFO process, flue gas exits the primary PM pollution control system at approximately 300 o

F and 

enters a spray tower where an alkaline slurry consisting of limestone (calcium carbonate), calcium sulfite, 

and calcium sulfate is contacted with the flue gas. Through a series of reactions, SO2 in the flue gas 

reacts with calcium carbonate to form CaSO3. The flue gas exits the absorption tower through a series of 

chevron mist eliminators to remove entrained moisture droplets. The calcium sulfite remains in the slurry 

which drains into a recirculation tank located at the bottom of the spray tower. By injecting air into the 

slurry using fans or blowers, the calcium sulfite is oxidized to CaSO4·2H2O. A portion of the slurry in the 

recirculation tank is pumped back into the spray tower, and a portion is removed. The removed slurry is 

dewatered and stockpiled for transport offsite. The overall FGD reaction is: 

CaCO3(s) + SO2(g) + 1⁄2O2(g) + 2H2O → CaSO4·2H2O(s) + CO2(g) 

The LSFO process can achieve high levels of control on coal-fired boilers. Recent BACT determinations 

put the level of control at 95 - 97% range. However, the same performance principle for any SO2 control 

system is also true for the LSFO – as the boiler outlet SO2 concentration decreases, the ability to achieve 

high control efficiencies also decreases. 
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7.3.2.1.3 Technical Feasibility 

WFGD is a well demonstrated technology for the control of SO2 emissions from coal-fired boilers. Wet 

FGD systems have been installed primarily on large utility scale pulverized coal-fired boilers combusting 

higher sulfur coals. Other advanced designs from Chiyoda, Alstom, Mitsubishi, and Babcock Power 

Environmental Inc. are also technically feasible. However, as noted above, the current wet FGD systems 

are 3rd generation FGD systems which would integrate many of the advances in wet FGD design. While a 

wet FGD system is technically feasible for this natural gas-fired boiler, we are not aware of the use of wet 

FGD systems on any natural gas-fired boilers either in the U.S. or abroad. 

7.3.2.2 Dry Flue Gas Desulfurization. 

Dry FGD is also a well demonstrated technology for the control of SO2 emissions from coal-fired electric 

generating units. Like wet FGD systems, dry FGD systems can be divided into several types. Dry FGD 

systems involve injecting a dry sorbent into the furnace or flue gas duct; the by-product solids are 

collected with the boiler fly ash. In semi-dry FGD systems, the sorbent is introduced as an aqueous slurry 

or a humidified dry powder to improve SO2 control efficiency. The water content is controlled so that the 

reaction by-products are dry solids. While the flue gas temperature in both types remains above the 

adiabatic saturation temperature, the semi-dry systems have lower temperatures and a closer approach to 

the saturation temperature. The primary PM control system for dry FGD applications is often a fabric 

filter baghouse since they can provide higher reagent utilization. 

Dry FGD systems do not have a saturated plume and therefore do not require the same design elements 

related to a saturated and corrosive plume as wet FGD systems. Since the dry FGD reaction products are 

also dry, there is no need for dewatering equipment or wastewater discharge. The reaction product in dry 

FGD systems is primarily calcium sulfite, with smaller amounts of calcium sulfate. Because of the 

calcium sulfite content, the dry FGD byproduct will undergo pozzolanic (cementitious) reactions when 

wetted. This material has limited commercial value and is typically disposed of as waste material. 

7.3.2.2.1 Lime Spray Drying Absorber 

One of the most widely used dry FGD technologies is the lime spray dry absorber (LSDA). LSDA is a 

semi-dry FGD technology that is often used on utility scale low sulfur coal-fired boilers. The LSDA 

process employs a spray dryer absorber (SDA) and a downstream PM control device. The SDA 

introduces a lime or limestone slurry and flue gas at the top of an absorber vessel. Rotary atomizers or 

nozzles are used to create a spray of slurry droplets which are dispersed in the flue gas stream. The water 

in the slurry droplets evaporates as the flue gas passes through the absorber, cooling and humidifying the 

flue gas stream and rapidly drying the slurry to a powder. In practice, water is added to control the SDA 

outlet temperature to approximately 155o

F, or an approach temperature approximately 25oF above the 

saturation temperature. SO2 in the flue gas reacts with calcium hydroxide in the reactor or on the fabric 

filter bags to form solid calcium sulfite (CaSO3) and calcium sulfate (CaSO4): 

 2Ca(OH)2 (s) + 2SO2 (g) + 2H2O (g) → 2(CaSO3 • 2H2O) 

 2Ca(OH)2 (s) + 2SO2 (g) + 2H2O (g) +O2 → 2(CaSO4 • 2H2O) 
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Fly ash, reaction products, and unreacted lime are captured downstream in the PM control system. A 

portion of the collected material is recycled back to the SDA to improve reagent utilization. 

7.3.2.2.2 Advanced Semi-Dry FGD Systems 

Advanced Semi-Dry FGD systems include circulating fluidized bed (CFB) systems, hydrated lime 

injection systems such as Turbosorp, circulating dry scrubbers (CDS), and flash dry absorbers, also called 

novel integrated desulphurization system (NIDS). These systems are often utilized in circulating 

fluidized bed (CFB) boiler applications where excess lime (CaO) produced in the CFB boiler can be used 

to further reduce SO2 emissions. The ash captured in the baghouse containing excess lime is hydrated to 

form calcium hydroxide (Ca(OH)2). The ash is then reinjected into the flue gas in a vessel upstream of 

the PM control device. 

These advanced semi-dry systems may be contrasted with conventional SDA systems in that the ash is 

humidified but remains a free-flowing solid, as opposed to being hydrated to a slurry as in the SDA 

process. This lower water content eliminates the need for slurry handling, atomization, and a large 

reactor. Reinjecting a dry solid also allows the reagent to disperse rapidly in the flue gas. These systems 

may also be contrasted with conventional SDA systems in that the solids recirculation rate is 30 to 100 

times, compared to 3 – 5 times in a conventional SDA system. These semi-dry FGD systems have 

demonstrated the ability to achieve SO2 emission reductions equivalent to, and in some cases greater than, 

that achieved by conventional dry FGD systems and LSDA. 

7.3.2.2.3 Technical Feasibility. 

Dry FGD systems, including lime spray drying absorbers, circulating fluidized bed systems, hydrated 

lime injection systems, and flash dryer absorbers, are all demonstrated for the control of SO2 emissions 

from coal-fired boilers. While a dry FGD system is technically feasible for the natural gas-fired boilers, 

we are not aware of the use of dry FGD systems on any natural gas-fired boilers either in the U.S. or 

abroad. 

7.3.2.3 Sorbent Injection. 

Sorbent injection systems may be considered as dry FGD systems in which a powdered sorbent is injected 

into the furnace or downstream ductwork. Several types of sorbent injection are available, including 

furnace sorbent injection, and duct sorbent injection. 

Duct sorbent injection (DSI) is a dry FGD system. In a typical DSI system, water is injected into the duct 

downstream of the air preheater to cool and humidify the flue gas. Sorbents such as hydrated quicklime 

or trona (sodium sesquicarbonate or Na2CO3 • NaHCO3 • 2H2O) are injected into the duct upstream of the 

PM control system. The fly ash, sorbent reaction products, and unused sorbent are collected in the PM 

control system. Duct sorbent injection has typical SO2 removal efficiencies ranging from 40 to 70%. 

Furnace sorbent injection is also a dry system. Sorbents such as limestone, hydrated lime or trona is 

injected into the boiler furnace. The injection point is selected based on the temperature window that is 

required for the reagent, typically around 1,000 – 1,500°F. Water is injected into the ductwork between 
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the air heater and the PM collector for flue gas conditioning to promote additional SO2 removal. The 

reaction product and fly ash are collected in the PM collection system. In retrofit situations, furnace 

sorbent injection systems typically achieve SO2 removal efficiencies of 30-40%. 

7.3.2.3.1 Technical Feasibility. 

Sorbent injection is technically feasible for the natural gas-fired boilers,. However, while a sorbent 

injection system is technically feasible, we are not aware of the use of dry FGD systems on any natural 

gas-fired boilers either in the U.S. or abroad. 

7.3.2.4 Emerging Flue Gas Desulfurization Technologies. 

Emerging SO2 control technologies include Enviroscrub (also known as the Pahlman process), ECO 

scrubber, REACT, and the Airborne process. These emerging technologies are not yet demonstrated 

through installation and successful operation on a full scale utility boiler or are not available or 

applicable. Of these advanced processes, the ECO system process is closest to commercial operation. 

The ECO process has been installed as a slip stream unit on a bituminous coal-fired boiler. The ECO 

system being offered is a redesigned version of the slip stream scrubber taking into account the “lessons 

learned.” The ECO system design has not yet been installed or demonstrated on a full scale on any boiler. 

The REACT technology from Japan consists of three major process steps: absorption, regeneration, and 

byproduct recovery. The absorption process utilizes pelletized activated coke (ATC) and ammonia for 

removal of SO2 and sulfuric acid from the flue gas. The mechanism for the removal of pollutants is very 

different between the REACT and wet FGD processes, although they are both located in the flue gas 

stream downstream of the primary PM control system. The absorption and regeneration processes of the 

REACT technology are dry, and require secondary particulate removal to collect the reaction product. 

In October, 2004, the U.S. Department of Energy announced that Peabody Energy’s Mustang Energy 

project will be awarded a $19.7 million Clean Coal Power Initiative grant for demonstrating technology to 

achieve ultra-low emissions at a proposed 300 MW facility near Grants, New Mexico. The Mustang 

Clean Coal Project is intended to demonstrate Airborne’s emission control process. The technology 

would combine a dry sodium bicarbonate injection with enhanced wet sodium bicarbonate scrubbing. 

Because the sodium bicarbonate reagent is expensive and the reaction product has limited value, the 

Airborne ProcessTM regenerates the scrubber reagent. The regeneration process would recover the reagent 

for reuse and convert SO2 and NOx into ammonium sulfate and ammonium nitrate based fertilizers. 

7.3.2.4.1 Technical Feasibility. 

While several advanced FGD technologies show promise in achieving very low SO2 emission rates, these 

processes are not commercial, nor are they demonstrated in practice. With respect to the Airborne 

project, because the Mustang project is receiving U.S. DOE funding to demonstrate the technology’s 

feasibility, it is, by definition, not demonstrated in practice. With respect to other advanced technologies, 

due to the lack of demonstrated performance of these emerging technologies, these technologies are not 

considered technically feasible SO2 control options for these boilers. 
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7.4 STEP 3. Rank the Technically Feasible Technologies. 

Design SO2 control efficiencies for advanced wet FGD systems are as high as 98% to 99%, down to SO2

outlet concentrations of approximately 9 ppm or 0.02 lb/mmBtu. Design SO2 control efficiencies for 

advanced dry FGD systems are as high as 95% to 98%, down to SO2 outlet concentrations of 

approximately 15 ppm or 0.032 lb/mmBtu. However, neither wet nor dry FGD systems are expected to 

routinely achieve these very low concentrations. The uncontrolled SO2 emission rates for natural gas is 

0.0006 lb/mmBtu. While flue gas desulfurization systems are technically feasible, these controls are not 

expected to achieve SO2 emission rates significantly below the uncontrolled SO2 emission rates for 

natural gas combustion of approximately 0.4 parts per million at 5% excess O2. Therefore, the use of wet 

FGD and dry FGD in combination with the use of natural gas are expected to achieve the same outlet SO2

emission rate as the use of natural gas only. 

7.5 STEP 4. Evaluate the Most Effective Controls. 

The most effective SO2 control option for these natural gas-fired boilers is the use low sulfur containing 

fuels including natural gas. Based on the use of these fuels, potential SO2 emissions would be limited to 

less than 0.3 tons per year. 

7.6 STEP 5. Proposed Sulfur Dioxide BACT Determination. 

Based on this analysis, We Energies has concluded that the use of package boilers firing only natural gas 

is the best available control technology (BACT) for the control of SO2 emissions from the natural gasfired boilers B02 and B03. Based on this analysis, We Energies proposes the following limits as BACT 

for the control of PM and PM10 emissions from these boilers. 

(1) Sulfur dioxide (SO2) emissions from the natural gas-fired Boilers B02 

and B03 shall be controlled using low sulfur fuels including natural gas 

as the best available control technology. 

(2) Sulfur dioxide (SO2) emissions may not exceed 0.0006 pounds per 

million Btu of heat input. 

(3) The total heat input to boilers B02 and B03 combined may not exceed 

2,170,000 mmBtu in any consecutive 12-month period. 

 

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Chapter 8. Volatile Organic Compound (VOC) 

Control Technology Review. 

As with CO emissions, volatile organic compounds (VOC) are emitted from natural gas-fired boilers as a 

result of incomplete combustion. Incomplete combustion can also result in emissions of particulate 

matter, CO, and organic hazardous air pollutants, and it reduces boiler efficiency. Because fuel costs 

represent the highest single operating cost for these boilers, large industrial boilers are designed to 

achieve the highest combustion efficiencies practicable. VOC emissions can be reduced by operating the 

boiler with higher flame temperatures, higher excess oxygen levels, and longer furnace residence times. 

Unfortunately, techniques for reducing VOC emissions can increase NOx emissions. Consequently, as 

with CO emissions, achieving low VOC and NOx emission rates is a balancing act in the boiler design 

and operation. 

8.1 BACT Baseline. 

There are no specific state implementation plan (SIP) requirements or new source performance standards 

for VOC emissions from natural gas-fired boilers. 

8.2 STEP 1. Identify All Available Control Technologies. 

Table 8-1 summarizes the VOC BACT emission limits for new and modified natural gas-fired boilers in 

the U.S. EPA’s RACT/BACT/LAER Clearinghouse. The technologies identified include the use of clean 

fuels including natural gas and distillate fuel oil, the use of good combustion practices, and the use of 

oxidation catalysts. Emission limits range from 0.0013 to 0.0479 lb/mmBtu of heat input for natural gas 

combustion. Please note that many of the emission limits in these tables were expressed as pounds per 

hour. These rates were converted to pounds per million Btu based on the rated heat input for the boiler to 

make the emission limits comparable. 
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Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. 

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TABLE 8-1. Natural gas-fired boiler VOC emission limits representing BACT from the U.S. EPA's RBLC database

RBLC ID Facility Permit Date Process Thruput, mmBtu/Hr Controls NJ-0042 Roche Vitamins 02/05/99 Boiler 152 None ListNJ-0042 Roche Vitamins 02/05/99 Boiler 134 None ListNJ-0042 Roche Vitamins 02/05/99 Boiler 118 None ListAR-0026 Pine Bluff Energy LLC-Pine Bluff Energy Center 05/05/99 Boiler 362 GCP NJ-0042 Roche Vitamins 02/05/99 Boiler 84 None ListTX-0499 Sandy Creek Energy Station 07/24/06 Auxiliary Boiler 175 NJ-0036 AES Red Oak LLC 10/24/01 Auxiliary Boiler 120 GCP AR-0057 Tenaska Arkansas Partners, LP 10/09/01 Boiler (2) 122 GCP OR-0046 Calpine Turner Energy Center, LLC 01/06/05 Auxiliary Boiler 417904 OC MN-0066 Northern States Power Co. - Riverside Plant 05/16/06 Auxiliary Boiler 160 GCP OK-0045 Redbud Power Plant 08/15/01 Auxiliary Boiler 20 GCP AL-0128 Alabama Power Co. - Theodore Cogeneration 03/16/99 Boiler 220 Efficient C*GA-0127 Southern Company Plant Mc Donough 01/07/08 Auxiliary Boilers 200 NC-0101 Forsyth Energy Plant 09/29/05 Auxiliary Boiler 110 LNB, GCP WI-0228 Wisconsin Public Service - Weston Plant 10/19/04 Auxiliary Boiler 230 LNB, GCP WV-0023 Longview Power, LLC 03/02/04 Auxiliary Boiler 225 GCP IN-0085 PSEG Lawrenceburg Energy Facility 06/07/01 Auxiliary Boiler 125 GCP OH-0310 American Municipal Power Generating Station 02/07/08 Auxiliary Boiler 150 OH-0241 Miller Brewing Company - Trenton 05/27/04 Boiler (2) 238 VA-0278 Virginia Commonwealth University East Plant 03/31/03 Boiler (3) 151 GCP AR-0070 Genova Arkansas I, LLC 08/23/02 Auxiliary Boiler 33 GCP TX-0437 Hartburg Power, LP 07/05/02 Auxiliary Boiler 40 GCP TX-0386 Calpine Amella Energy Center 03/26/02 Auxiliary Boiler 155 TN-0089 Proctor & Gamble Manufacturing Company 03/05/01 Utility Boiler 225 WI-0204 United Wisconsin Grain Producers-Ethanol Plant 08/14/03 Boiler /Oxidizer 140 NJ-0043 Liberty Generating Station 03/28/02 Auxiliary Boiler 200 OC 

Footnotes “GCP” means good combustion practices. “SCR” means selective catalytic reduction. “LNB” means low NOx burner. “ULNB” mean

“FGR” means flue gas recirculation. “OC” means oxidation catalyst.
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8.3 STEP 2. Identify Technically Feasible Control Technologies. 

Available control technologies for the control of VOC emissions include good combustion practices, 

oxidation catalysts, and thermal oxidation. 

8.3.1 Oxidation Catalysts. 

Oxidation catalysts are used to reduce CO emissions, and to a lesser extent VOC emissions, from natural 

gas or oil-fired combustion turbines. Typical VOC reduction efficiencies in these combustion turbine 

applications are less than 50%. However, oxidation catalysts have limited demonstration in reducing 

VOC emissions from boilers. The CO oxidation catalysts are generally noble metal catalysts which are 

susceptible to poisoning from sulfur and calcium bearing compounds. These catalysts may experience 

deactivation and fouling in high sulfur oil-fired boiler flue gas streams. To be effective, the oxidation 

catalyst must be placed in a location with gas temperatures of at least 600 o

F. Oxidation catalysts operate 

according to the following general reaction: 

 2CO + O2 → 2CO2 

Typical excess oxygen (O2) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in natural 

gas-fired boilers. These low excess O2 levels will limit the effectiveness of the oxidation catalyst. 

8.3.2 Thermal Oxidation 

Thermal oxidation has never been required nor used on a natural gas-fired boiler, and its theoretical 

ability to reduce VOC emissions from these boilers is questionable. Thermal oxidation would involve 

injecting additional air into the flue gas and heating the oxygen enriched mixture to approximately 1,500 o

F to oxidize VOC to carbon dioxide and water. However, since the combustion of the reheat fuel would 

itself result in VOC emissions, there is no evidence that thermal oxidation would result in any VOC 

emission reductions. Since thermal oxidation has never been demonstrated on a natural gas-fired boiler, 

and because there is no evidence that it could reduce VOC emissions, thermal oxidation is not a 

technically feasible VOC control technology for these boilers. 

8.3.3 Good Combustion Practices 

Good combustion practices or combustion controls generally include the following components: 

1. Good air/fuel mixing in the combustion zone. 

2. High temperatures and low oxygen levels in the primary combustion zone. 

3. Overall excess oxygen levels high enough to complete combustion while maximizing 

boiler thermal efficiency. 

4. Sufficient residence time to complete combustion. 

In natural gas-fired boilers, good combustion practices is the only technically feasible CO control 

technology. Combustion efficiency is related to the three “T’s” of combustion: Time, Temperature, and 
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Turbulence. These components of combustion efficiency are designed into utility boilers to maximize 

fuel efficiency and reduce the highest single operating cost of a utility boiler: FUEL. A fourth critical 

parameter is the level of oxygen in the boiler, referred to as the excess air or excess oxygen level. 

Therefore, combustion control is accomplished primarily through boiler design as it relates to time, 

temperature, and turbulence, and through boiler operation as it relates to excess oxygen levels. 

Combustion design for modern boilers is intended to simultaneously minimize formation of CO, VOC, 

and NOx emissions. This is a difficult task, since emissions of NOx and emissions of CO (and VOC) are 

inversely related. That is, measures used to reduce NOx emissions often lead to increases in CO and VOC 

emissions. Therefore, the boiler design to minimize VOC emissions is interrelated with the boiler design 

to minimize NOx formation. 

8.4 STEP 3. Rank the Technically Feasible Control Technologies. 

Based on the above analysis, the technically feasible VOC control technologies for these natural gas-fired 

boilers includes good combustion practices based on the use of the ultra low NOx burners combined with 

flue gas recirculation, and the use of oxidation catalysts as a post combustion control system. Good 

combustion practices are expected to limit VOC emissions to 0.006 lb/mmBtu, equal to 20 parts per 

million at 5% excess oxygen (based on VOCs as propane). The use of an oxidation catalyst is expected 

to reduce VOC emissions by 25%, to 15 parts per million, and 0.0045 lb/mmBtu. 

8.5 STEP 4. Evaluate the Most Effective Controls. 

8.5.1 Rank No. 1: Oxidation Catalyst and Good Combustion Practices. 

The use of good combustion practices combined with an oxidation catalyst on these natural gas-fired 

boilers could reduce VOC emissions to 0.0045 lb/mmBtu. Based on limiting the operation of these 

boilers to 6,200 hours per year, this combination of controls could reduce VOC emissions from 3.3 tons 

per year, to 2.5 tons per year. 

8.5.1.1 Environmental Impacts. 

The primary environmental impact from the use of oxidation catalysts on these boilers is a reduction in 

CO and VOC emissions. 

8.5.1.2 Energy Impacts. 

Energy impacts from the use of an oxidation catalyst would include an increase in induced draft fan 

power requirements necessary to overcome a small pressure drop across the catalyst. 

8.5.1.3 Economic Impacts. 

The costs for oxidation catalysts on these boilers would include the capital costs for the catalyst and 

ancillary equipment, labor, auxiliary power requirements, catalyst replacement, maintenance, and 
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administrative costs. The oxidation catalyst cost analysis is included in Table 8-2. From Table 8-2, an 

oxidation catalyst system is expected to have an equipment cost of $105,000 per boiler, and a total capital 

requirement of $210,000. From Table 8-2, the oxidation catalyst system is expected to have an annual 

cost of $136,100 for each boiler. The oxidation catalyst systems would reduce VOC emissions by 0.8 

tons. Based on these costs, the oxidation catalyst systems would have an average cost effectiveness of 

$170,000 per ton of VOC removed. 

TABLE 8-2. Oxidation catalyst control system costs for each natural gas-fired boiler. 

 CAPITAL COST ANNUAL COST 

Total Capital Cost 

Equipment Cost, 2010 Dollars $105,000 

Capital Recovery Factor, CRF 0.1098 

Total Capital Investment (TCI) $210,000 $23,100 

Labor Costs (1 hour per day) $18,300 

Maintenance Costs 

Maintenance Labor, hr/year 300 

Catalyst Inspection and Replacement Labor, hr per year 400 

Labor Cost, $ per year $35,000 

Material Cost, $ per year $35,000 

Total Annual Maintenance Cost $/yr $70,000 

Catalyst Replacement Costs 

Catalyst Cost $70,000 

Sinking Fund Factor 0.174 

Total Catalyst Replacement Costs $12,200 

Auxiliary Power Requirements $8,300 

Overhead and Administrative Costs 2% of TCI $4,200

TOTAL ANNUAL COST $136,100 

Footnotes 

1. The cost of capital for this project is 7%, and the project life is 15 years. The annual cost of this investment is 

given by the capital recovery factor (CRF): 

 where: i = annual interest rate (decimal)

 n = control system life (years)

2. For the catalyst, the catalyst life is 5 years. The annual cost is given by the sinking fund factor (SFF): 

 

3. The oxidation catalyst capital cost is based on the catalyst system equipment cost multiplied by 2.0 for the costs 

of installation and other necessary equipment.. 

[ ] (1 ) 1

(1 )

+ −

+ = n

n

i

i i CRF

[ ] (1+ ) −1 = n i

i SFF
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8.5.1.4 Conclusion. 

The use of an oxidation catalyst in combination with good combustion practices on these natural gas-fired 

package boilers can achieve VOC emission rates of 0.0045 lb/mmBtu. However, each oxidation catalyst 

system would have a total capital requirement of $210,000, and a total annual cost of $136,100. The 

oxidation catalyst systems would reduce VOC emissions by 0.8 tons per year, resulting in an average cost 

effectiveness of $170,000 per ton of VOC removed. This is a very high cost, indicating that the use of an 

oxidation catalyst for the control of VOC emissions on these natural gas-fired boilers is not an 

economically feasible control option. 

8.5.2 Rank No. 2: Good Combustion Practices. 

The use of package boilers with Ultra Low NOx Burners, Overfire Air, and Flue Gas Recirculation, and 

the use of good combustion practices can achieve a VOC emission rate of 0.006 lb/mmBtu. Based on 

limiting the annual heat input to each boiler to no more than 1,085,000 mmBtu per year (equal to 

2,170,000 mmBtu per year for both boilers combined), the use of good combustion practices will limit 

VOC emissions from each boiler to 3.3 tons per year. 

8.6 STEP 5. Proposed VOC BACT Determination. 

Based on this analysis, We Energies has concluded that the use of good combustion practices represents 

the best available control technology (BACT) for the control of VOC emissions from these natural gasfired package boilers. Based on this analysis, We Energies proposes the following limits as BACT for the 

control of VOC emissions from the natural gas-fired boilers. 

(1) Volatile organic compounds (VOC) emissions from the natural gasfired boilers B02 and B03 shall be controlled using good combustion 

practices as the best available control technology. 

(2) Volatile organic compounds (VOC) emissions may not exceed 0.0060 

pounds per million Btu of heat input. 

(3) Compliance with these emission limits shall be based upon the U.S. EPA 

Reference Method 25A, or another method approved in writing by the 

department. 

 (4) The total heat input to boilers B02 and B03 combined may not exceed 

2,170,000 mmBtu in any consecutive 12-month period. 
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Chapter 9. Fluorides Control Technology Review. 

Fluorine (F) is a trace element in natural gas. When these fuels are burned, fluorine may be emitted as 

hydrogen fluoride or hydrofluoric acid (HF), or as fluorine compounds, such as sodium fluoride (NaF) 

and calcium fluoride (CaF2). Fluoride compounds such as NaF are solids at the flue gas temperatures. On 

the other hand, hydrogen fluoride is a colorless liquid at temperatures less than 66 o

F. At temperatures 

above 66 o

F, hydrofluoric acid is a gas. Because hydrofluoric acid is soluble in water and is a strong 

acid, it readily combines with the alkaline substances in ash. 

9.1 BACT Baseline. 

There are no specific NSPS or SIP emission limitations for fluoride emissions from natural gas-fired 

boilers. Therefore, the BACT baseline is the uncontrolled emission rate. 

9.2 STEP 1. Identify All Potential Control Technologies 

Based on the permits reviewed, there were no natural gas-fired boilers with hydrogen fluoride (HF) 

emission limits. In January, 2010, a preliminary database of emission test data, CEMS data, and fuel 

analysis data for boilers at major sources of HAP was made available at 

http://www2.ergweb.com/projects/combustion/combustiontesting.html. This data includes emission data 

from the U.S. EPA’s Phase I survey and the Phase II test plan. HF stack test data for natural gas and 

distillate fuel oil is summarized in Table 9-1. There was no fluorine fuel data for natural gas. 

TABLE 9-1. Natural gas and distillate fuel oil-fired boiler hydrogen fluoride (HF) test results. 

State / Facility ID Non-Detect? Value, lb/mmBtu Fuel 

UT Westinghouse BDL 0.000004 Natural gas 

SC GP Chem Russellville ND 0.000020 Diesel fuel 

IN Nucor Steel 0.000078 Natural gas 

IN Alcoa Warrick BDL 0.000091 Natural gas 

CO Rocky Mtn Steel 212 0.00013 Natural gas 

IN Outokumpu Stainless Plate ND 0.00045 Natural gas 

MI Consumer Energy Co- Campbell ND 0.00058 No. 2 Distillate 

TN Invista Chattanooga ND 0.00062 No. 2 Distillate 

IN Arcelor Mittal Burns Harbor ND 0.0009 Natural gas 

WI Charter Steel ND 0.0010 Natural gas 

NC Domtar ND 0.0010 No. 2 Distillate 

IL Poly One 0.0016 Natural gas 

NC Camp Lejeune MCB 0.0078 Natural gas 

SC Eastman Colombia ND 0.069 Natural gas 

SC Michelin Sandy Springs ND 0.071 Natural gas 
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Emission rates ranged from less than 0.000004 to 0.071 lb/mmBtu, a range of 4 orders of magnitude. Of 

the 15 listed emission test results, only 4 results indicated emissions above the detection limit. In 

addition, the two highest reported values were also below the detection limit of the test. The median 

value in Table 9-1 is 0.00062 lb/mmBtu. 

Based on the above data, the median value from Table 9-1 is 0.00062 lb/mmBtu. This value may be used 

to estimate HF emissions from natural gas combustion. 

9.3 STEP 2. Identify Technically Feasible Control Technologies. 

As noted above, fluoride emissions may be emitted as solids, such as sodium fluoride, or as the acid gas 

hydrogen fluoride. Therefore, fluoride emissions may be controlled using particulate matter control 

systems, and also acid gas control systems. Technologies that may control fluoride emissions include 

fabric filter baghouses, electrostatic precipitators, wet or dry FGD systems, and sorbent injection. 

9.3.1 Flue Gas Desulfurization Systems. 

Wet and dry flue gas desulfurization systems are effective fluoride control systems when combusting 

coal. From the EPRI report, Emission Factors Handbook: Guidelines for Estimating Trace Substance 

Emissions from Fossil fuel Steam Electric Plants, Final Report, April, 2002, the expected HF control 

efficiency for all coal-fired FGD systems is 94%. Since we are not aware of any FGD systems on natural 

gas-fired boilers, there is no available data on HF emission reductions which may occur with the use of 

FGD systems. 

9.3.2 Sorbent Injection. 

Sorbent injection such as hydrated lime may also reduce emissions of HF. The injection of lime into the 

flue gas upstream of a fabric filter baghouse is well demonstrated to reduce H2SO4 emissions. Again, 

since we are not aware of any FGD systems on natural gas-fired boilers, there is no available data on HF 

emission reductions which may occur with the use of sorbent injection. 

9.4 STEP 3. Rank The Technically Feasible Control Technologies. 

From the above discussion, there is no available data to suggest that post combustion pollution control 

systems can reduce HF emissions below the very low levels which occur from the combustion of only 

natural gas. Therefore, the highest ranked control is the combustion of low fluorine containing fuels 

including natural gas. 

STEP 4. Evaluate the Most Effective Controls. 

Based on the above analysis, the combustion of low fluorine containing fuels including natural gas 

represents the best available control technology for these package boilers. Further reduction from 

potential acid gas control systems cannot be confirmed. 
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STEP 5. Proposed Fluorides BACT Determination 

Based on this analysis, We Energies has concluded that the use of low fluorine containing fuels including 

natural gas represents the best available control technology (BACT) for HF emissions from these natural 

gas-fired package boilers. Based on this analysis, We Energies proposes the following limits as BACT 

for the control of fluoride (HF) emissions from the natural gas-fired boilers. The available data covers a 

very wide range of potential emission rates. Therefore, rather than specifying a specific allowable 

emission limit, We Energies proposes the following limits as BACT for the control of HF emissions from 

the natural gas-fired boilers. 

(1) Hydrogen fluoride (HF) emissions from the package boilers shall be 

controlled using low fluorine containing fuels including natural gas as 

the best available control technology. 
Prevention of Significant Deterioration 

Air Pollution Control Construction Permit Application 

Appendix C. 

Control Technology Review. 

Best Available Control Technology (BACT) Analysis for the Balance 

of Plant Equipment, including Material Handling Systems, Cooling 

Towers, and Emergency Diesel Feed Water Pump. 

50 MW Biomass-Fired Cogeneration Facility to be 

Located at the Domtar – Rothschild Mill.

March, 2010 

Prepared for: 

We Energies 

231 W. Michigan St. 

Milwaukee, WI 53203 

Prepared By: 

 

RTP ENVIRONMENTAL ASSOCIATES INC.® 

903 Superior Avenue, Suite 6 

Tomah, WI 54660 

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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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Executive Summary 

This document is a Control Technology Review for the balance of plant equipment, including material 

handling equipment and processes, cooling towers, and an emergency diesel engine-driven feed water 

pump for We Energies’ 50 MW Biomass Fuels Cogeneration Facility to be located at the Domtar – 

Rothschild Mill. This control technology review is required for major new sources under the Prevention 

of Significant Deterioration (PSD) program under NR 405.08, Wis. Adm. Code. This Project will involve 

the installation of a one new biomass-fired boiler and two new natural gas-fired package boilers. To 

support these new boilers, the Plant will require new biomass fuel handling equipment, biomass boiler ash 

handling equipment, a new cooling tower, and a new diesel engine driven feed water pump. These new 

emission units are summarized in Table ES-1. The proposed control technologies and emission limits 

representing the best available control technology (BACT) for these processes and emission units are 

summarized in Table ES-2. 

TABLE ES-1. List of new material handling, cooling towers, diesel engine, and balance of plant 

emission units. 

Stack 

ID 

Process 

ID Description 

S121 P121 Biomass Fuels Unloading, Screening, Hogging, and Conveying Dust Collector 

S122 F122 Self Unloading Truck Biomass Fuels Unloading 

S123 F123 Biomass Fuels Storage and Reclaim 

S124 P124 Boilerhouse Fuel Storage Silos 

S125 F125 Biomass Fuels Delivery Truck Haul Roads 

S131 P131 CFB Boiler Bed Material Silo 

S132 P132 CFB Boiler Ash Silo 

S133 F133 Boiler Ash Haul Roads 

S141 P141 Cooling Tower 

S151 P151 Emergency Diesel Engine Feed Water Pump 
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TABLE ES-2. Proposed control technologies and emission limits representing BACT for We 

Energies’ 50 MW Biomass Fuels Cogeneration Facility balance of plant equipment. 

Process 

ID Description Proposed BACT Requirements 

P121 

Biomass Fuels Unloading, 

Screening, Hogging, and 

Conveying Dust Collector 

(1) PM emissions shall be controlled using buildings or 

enclosures combined with dust collection systems or 

wet dust suppression systems as BACT. 

(2) PM/PM10 emissions shall be limited to 0.004 

gr/dscf. 

(3) PM2.5 emissions shall be limited to 0.002 gr/dscf. 

F122 Self Unloading Truck Biomass 

Fuels Unloading 

(1) PM/PM10, and PM2.5 emissions shall be controlled 

using self unloading trucks in combination with a wet 

dust suppression system as BACT. 

F123 Biomass Fuels Storage and 

Reclaim 

(1) Particulate matter (PM), PM10, and PM2.5 emissions 

shall be controlled using a biomass fuels storage 

building designed to enclose the entire storage pile and 

the reclaim activities as BACT. 

P124 Boilerhouse Fuel Storage Silos 

P131 CFB Boiler Bed Material Silo 

P132 CFB Boiler Ash Silo 

(1) PM, PM10, and PM2.5 emissions shall be controlled 

using a bin vent filter as BACT. 

(2) PM/PM10 emissions shall be limited to 0.004 

gr/dscf. 

(3) PM2.5 emissions shall be limited to 0.002 gr/dscf. 

F125 Biomass Fuels Delivery Truck 

Haul Roads 

F133 Boiler Ash Haul Roads 

(1) PM, PM10, and PM2.5 emissions shall be controlled 

using paved roadways in combination with a dust 

suppression system as BACT. 

P141 Cooling Tower 

(1) PM, PM10, and PM2.5 emissions from the 

mechanical draft cooling tower, Process P141, shall be 

controlled using high efficiency drift eliminators as 

BACT. 

(2) The cooling tower drift eliminators shall be 

designed for a drift loss of no more than 0.0005%. 

P151 Emergency Diesel Engine Feed 

Water Pump 

(1) The diesel feed water pump shall comply with the 

applicable NSPS in 40 CFR § 60.4205 as BACT. 

(2) The diesel fuel may not exceed 0.0015% sulfur. 

(3) The diesel feed water pump may not be operated 

more than 100 hours in any 12-month period. 
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Table of Contents 

Chapter 1. Introduction and Sources Evaluated.................................................8

Chapter 2. Control Technology Review Methodology........................................9

2.1 Best Available Control Technology Definition. .............................................................................. 9

2.2 Top Down BACT Methodology. ................................................................................................... 10

2.3 New Versus Modified Facilities. ................................................................................................... 10

2.4 Identifying Potential Control Technologies................................................................................... 11

2.5 Technical Feasibility...................................................................................................................... 11

2.6 Economic Feasibility. .................................................................................................................... 12

2.6.1 Average Cost Effectiveness. ............................................................................................. 12

2.6.2 Incremental Cost Effectiveness......................................................................................... 13

Chapter 3. Control Technology Review for Process P121; Biomass Fuels 

Material Handling Processes. ...............................................................................14

3.1 Emission Unit Description............................................................................................................. 14

3.2 BACT Baseline. ............................................................................................................................. 15

3.3 Step 1. Identify All Available Control Technologies. .................................................................. 15

3.4 Step 2. Eliminate Technically Infeasible Options......................................................................... 16

3.5 Step 3. Rank the Technically Feasible Control Technologies. ..................................................... 16

3.6 Step 4. Evaluate the Most Effective Controls............................................................................... 17

3.7 Step 5. Proposed BACT Requirements......................................................................................... 17

Chapter 4. Control Technology Review for Process F122: Biomass Fuels Self 

Unloading Truck Unloading. ................................................................................18

4.1 BACT Baseline. ............................................................................................................................. 18

4.2 Step 1. Identify All Available Control Technologies. .................................................................. 19

4.3 Step 2. Eliminate Technically Infeasible Options......................................................................... 19

4.4 Step 3. Rank the Technically Feasible Control Technologies. ..................................................... 19

4.5 Step 4. Evaluate the Most Effective Controls............................................................................... 19

4.5.1 Total Enclosure and Dust Collection System. .................................................................. 19

4.6 Step 5. Proposed BACT Requirements......................................................................................... 20

Chapter 5. Control Technology Review for Process F123: Biomass Fuels 

Storage and Reclaim. .............................................................................................21

5.1 BACT Baseline. ............................................................................................................................. 21

5.2 Step 1. Identify All Available Control Technologies. .................................................................. 22
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5.3 Step 2. Eliminate Technically Infeasible Options......................................................................... 22

5.4 Step 3. Rank the Technically Feasible Control Technologies. ..................................................... 22

5.5 Step 4. Evaluate the Most Effective Controls............................................................................... 22

5.6 Step 5. Proposed BACT Requirements......................................................................................... 22

Chapter 6. Control Technology Review for Process P124: Boilerhouse Fuel 

Storage Silos............................................................................................................23

6.1 BACT Baseline. ............................................................................................................................. 23

6.2 Step 1. Identify All Available Control Technologies. .................................................................. 23

6.3 Step 2. Eliminate Technically Infeasible Options......................................................................... 24

6.4 Step 3. Rank the Technically Feasible Control Technologies. ..................................................... 24

6.5 Step 4. Evaluate the Most Effective Controls............................................................................... 24

6.6 Step 5. Proposed BACT Requirements......................................................................................... 24

Chapter 7. Control Technology Review for Processes F125 and F133; 

Biomass Fuels and Ash Truck Haul Roads. ........................................................25

7.1 BACT Baseline. ............................................................................................................................. 26

7.2 Step 1. Identify All Available Control Technologies. .................................................................. 26

7.3 Step 2. Eliminate Technically Infeasible Options......................................................................... 27

7.4 Step 3. Rank the Technically Feasible Control Technologies. ..................................................... 27

7.5 Step 4. Evaluate the Most Effective Controls............................................................................... 27

7.6 Step 5. Proposed BACT Requirements......................................................................................... 27

Chapter 8. Control Technology Review for Process P131, CFB Boiler Bed 

Material Silo; and Process P132, CFB Boiler Ash Silo. .....................................29

8.1 BACT Baseline. ............................................................................................................................. 29

8.2 Step 1. Identify All Available Control Technologies. .................................................................. 29

8.3 Step 2. Eliminate Technically Infeasible Options......................................................................... 30

8.4 Step 3. Rank the Technically Feasible Control Technologies. ..................................................... 30

8.5 Step 4. Evaluate the Most Effective Controls............................................................................... 30

8.6 Step 5. Proposed BACT Requirements......................................................................................... 30

Chapter 9. Control Technology Review for Process P141: Cooling Tower....31

9.1 Emission Unit Description............................................................................................................. 31

9.2 Cooling Tower Emissions.............................................................................................................. 31

9.3 BACT Baseline. ............................................................................................................................. 33

9.4 Step 1. Identify all available control technologies......................................................................... 33

9.5 Step 2. Identify the technically feasible control options............................................................... 33

9.6 Step 3. Rank the technically feasible control options. ................................................................. 33

9.7 Step 4. Evaluate the most effective controls................................................................................ 34
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9.8 Step 5. Propose BACT................................................................................................................. 34

Chapter 10.Control Technology Review for Process P151: Emergency Feed 

Water Pump............................................................................................................35

10.1 Carbon Monoxide (CO) Control Technology Review................................................................... 37

10.1.1 Step 1. Identify All Available Control Technologies. ..................................................... 37

10.1.2 Step 2. Eliminate Technically Infeasible Options............................................................ 37

10.1.3 Step 3. Rank the Technically Feasible Control Technologies. ........................................ 37

10.1.4 Step 4. Evaluate the Most Effective Controls.................................................................. 37

10.1.5 Step 5. Proposed BACT Requirements............................................................................ 37

10.2 Nitrogen Oxides (NOx) Control Technology Review.................................................................... 38

10.2.1 Step 1. Identify All Available Control Technologies. ..................................................... 38

10.2.2 Step 2. Eliminate Technically Infeasible Options............................................................ 38

10.2.3 Step 3. Rank the Technically Feasible Control Technologies. ........................................ 38

10.2.4 Step 4. Evaluate the Most Effective Controls.................................................................. 38

10.2.5 Step 5. Proposed BACT Requirements............................................................................ 38

10.3 PM, PM10, and PM2.5 Control Technology Review. ...................................................................... 39

10.3.1 Step 1. Identify All Available Control Technologies. ..................................................... 39

10.3.2 Step 2. Eliminate Technically Infeasible Options............................................................ 39

10.3.3 Step 3. Rank the Technically Feasible Control Technologies. ........................................ 39

10.3.4 Step 4. Evaluate the Most Effective Controls.................................................................. 39

10.3.5 Step 5. Proposed BACT Requirements............................................................................ 39

10.4 Sulfur Dioxide (SO2) Control Technology Review. ...................................................................... 40

10.4.1 Step 1. Identify All Available Control Technologies. ..................................................... 40

10.4.2 Step 2. Eliminate Technically Infeasible Options............................................................ 40

10.4.3 Step 3. Rank the Technically Feasible Control Technologies. ........................................ 40

10.4.4 Step 4. Evaluate the Most Effective Controls.................................................................. 40

10.4.5 Step 5. Proposed BACT Requirements............................................................................ 40

10.5 Volatile Organic Compound (VOC) Control Technology Review................................................ 41

10.5.1 Step 1. Identify All Available Control Technologies. ..................................................... 41

10.5.2 Step 2. Eliminate Technically Infeasible Options............................................................ 41

10.5.3 Step 3. Rank the Technically Feasible Control Technologies. ........................................ 41

10.5.4 Step 4. Evaluate the Most Effective Controls.................................................................. 41

10.5.5 Step 5. Proposed BACT Requirements............................................................................ 41

10.6 Fluorides (as HF) Control Technology Review............................................................................. 42

10.6.1 Step 1. Identify All Available Control Technologies. ..................................................... 42

10.6.2 Step 2. Eliminate Technically Infeasible Options............................................................ 42

10.6.3 Step 3. Rank the Technically Feasible Control Technologies. ........................................ 42

10.6.4 Step 4. Evaluate the Most Effective Controls.................................................................. 42

10.6.5 Step 5. Proposed BACT Requirements............................................................................ 42
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Tables 

TABLE 3-1. Potential PM control technologies for the biomass fuels material handling processes. .......16

TABLE 3-2. Potential emissions for Processes P121 based on the BACT limits. ....................................17

TABLE 4-1. Potential PM and PM10 control technologies for Process F123, self-unloading trucks. .......19

TABLE 5-1. Potential PM control technologies for Process F124, biomass fuels storage........................22

TABLE 7-1. Potential PM control technologies for truck haul roads........................................................26

TABLE 7-2. Fugitive dust emissions from the Biomass Fuels Delivery Truck Haul Roads, Process F125.

............................................................................................................................................................28

TABLE 7-3. Fugitive dust emissions from the Ash Truck Haul Roads, Process F133. ............................28

TABLE 9-1. Specifications for the new plume abated mechanical draft cooling tower, Process P141. ...31

TABLE 9-2. Potential emissions for the new mechanical draft cooling tower, Process P141. .................33

TABLE 9-3. Cooling tower BACT requirements for recently permitted power plants.............................34

TABLE 10-1. Potential emissions for the diesel engine driven feed water pump based on limiting 

operation to 100 hours per year. .........................................................................................................36
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Chapter 1. Introduction and Sources Evaluated. 

This document is a Control Technology Review for the balance of plant equipment, including material 

handling equipment and processes, cooling towers, and an emergency diesel engine-driven feed water 

pump for We Energies’ 50 MW Biomass Fuels Cogeneration Facility to be located at the Domtar – 

Rothschild Mill. This control technology review is required for major new sources under the Prevention 

of Significant Deterioration (PSD) program under NR 405.08, Wis. Adm. Code. 

We Energies’ 50 MW Biomass Fuels Cogeneration Facility will be a combined heat and power facility 

that produce 50 MW of electric power and will also provide process steam to the Domtar Mill. The 

Project will involve the installation of one new biomass-fired boiler, and two new natural gas-fired 

package boilers. To support these new boilers, the Plant will require new biomass fuel handling 

equipment, biomass boiler ash handling equipment, a new cooling tower, and a new diesel engine driven 

emergency feed water pump. A list of these new emission units is included in Table 1-1. 

TABLE 1-1. List of new material handling, cooling towers, and diesel engine emission units. 

Stack 

ID 

Process 

ID Description 

S121 P121 Biomass Fuels Unloading, Screening, Hogging, and Conveying Dust Collector 

S122 F122 Self Unloading Truck Biomass Fuels Unloading 

S123 F123 Biomass Fuels Storage and Reclaim 

S124 P124 Boilerhouse Fuel Storage Silos 

S125 F125 Biomass Fuels Delivery Truck Haul Roads 

S131 P131 CFB Boiler Bed Material Silo 

S132 P132 CFB Boiler Ash Silo 

S133 F133 Boiler Ash Haul Roads 

S141 P141 Cooling Tower 

S151 P151 Emergency Diesel Engine Feed Water Pump 

 

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Chapter 2. Control Technology Review 

Methodology. 

2.1 Best Available Control Technology Definition. 

The Clean Air Act and the Prevention of Significant Deterioration (PSD) rules in the Code of Federal 

regulations, 40 CFR 52.21(b)(12) define “best available control technology” (BACT) as: 

 “...an emission limitation based on the maximum degree of reduction for each pollutant subject to 

regulation under this Act which would be emitted from any proposed major stationary source or major 

modification which the administrator on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, determines is achievable for such source or 

modification through application of production processes and available methods, systems, and 

techniques, including fuel cleaning or treatment of innovative fuel combustion techniques for control of 

each such pollutant. In no event shall application of BACT result in emissions of any pollutant which 

would exceed the emissions allowed by any applicable standard under 40 CFR Parts 60 and 61.” 

In Wisconsin, BACT is defined as: 

...means an emissions limitation, including a visible emissions standard, based on the maximum degree 

of reduction for each air contaminant subject to regulation under the Act which would be emitted from 

any proposed major stationary source or major modification which the department, on a case-by-case 

basis, taking into account energy, environmental, and economic impacts, and other costs, determines is 

achievable for such source or modification through application of production processes or available 

methods, systems, and techniques, including clean fuels, fuel cleaning or treatment or innovative fuel 

combination techniques for control of the air contaminant. In no event may application of best available 

control technology result in emissions of any air contaminant which would exceed the emissions 

allowed by any applicable standard under chs. NR 440 and 445 to 449 and under sections 111 and 112 

of the Act (42 USC 7411 and 7412). Emissions from any source utilizing clean fuels or any other means 

to comply with this subsection may not be allowed to increase above the levels that would have been 

required under this subsection as it existed prior to enactment of the 1990 clean air Act amendments on 

November 15, 1990. If the department determines that technological or economic limitations on the 

application of measurement methodology to a particular emissions unit would make the imposition of 

an emissions standard infeasible, a design, equipment, work practice, operational standard or 

combination thereof, may be prescribed instead to satisfy the requirement for the application of best 

available control technology. The standard shall, to the degree possible, set forth the emissions 

reduction achievable by implementation of such design, equipment, work practice or operation, and 

shall provide for compliance by means which achieve equivalent results. 

(NR 405.02(7), Wis. Adm. Code)

The BACT requirement applies for a given pollutant to each individual new or modified emission unit 

when the project, on a facility-wide basis, has a significant net emissions increase for that pollutant. 
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Individual BACT determinations are performed on a unit-by-unit, pollutant-by-pollutant basis. This 

BACT analysis considers potential controls for SO2, NOx, PM10, CO, and sulfuric acid mist (SAM).

2.2 Top Down BACT Methodology. 

The U.S. EPA recommends a “top-down” approach in conducting a BACT analysis. This method 

evaluates progressively less stringent control technologies until a level of control considered BACT is 

reached, based on the environmental, energy, and economic impacts. The top-down method was used in 

this analysis. The five steps of a top-down BACT analysis are: 

1. Identify all available control technologies with practical potential for application to the emission 

unit and regulated pollutant under evaluation; 

2. Eliminate all technically infeasible control technologies; 

3. Rank remaining control technologies by effectiveness and tabulate a control hierarchy; 

4. Evaluate most effective controls and document results; and 

5. Select BACT, which will be the most effective practical option not rejected, based on economic, 

environmental, and/or energy impacts. 

The impact analysis of any BACT review includes an evaluation of environmental, energy, technical, and 

economic impacts. The net environmental impact associated with a control alternative may be considered 

if dispersion modeling analyses are performed. The energy impact analysis estimates the direct energy 

impacts of the control alternatives in units of energy consumption. If possible, the energy requirements 

for each control option are assessed in terms of total annual energy consumption. The most important 

issue of the BACT review is generally the economic impact. The economic impact of a control option is 

assessed in terms of cost effectiveness and ultimately, whether the option is economically reasonable. The 

economic impacts are reviewed on a cost per ton controlled basis, as directed by the U.S. EPA’s Office of 

Air Quality Planning and Standards (OAQPS) Cost Control Manual, Fifth Edition. 

The EPA has consistently interpreted the statutory and regulatory BACT definitions as containing two 

core requirements, which EPA believes must be met by any BACT determination, irrespective of whether 

it is conducted in a “top-down” manner. First, the BACT analysis must include consideration of the most 

stringent available technologies: i.e., those that provide the “maximum degree of emissions reduction.” 

Second, any decision to require a lesser degree of emissions reduction must be justified by an objective 

analysis of “energy, environmental, and economic impacts” contained in the record. 

2.3 New Versus Modified Facilities. 

There can be significant differences in the technical and economic feasibility of retrofitting controls on 

existing boilers, versus the use of these same controls on new boilers. In addition, a given control 

technology may not be able to achieve the same level of control when retrofitted onto existing units as the 

same control technology can achieve on new units. For example, the use of low NOx burners on existing 
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boilers often cannot achieve the same NOx, CO, and VOC emission rates as the use of low NOx burners 

on a new boiler which has been designed to optimize the low NOx burner design. This can in turn affect 

the ultimate NOx emission rates which can be achieved by post combustion controls such as selective 

catalytic reduction. 

Retrofitting controls on existing boilers can also have significantly different costs as compared to the use 

of these same technologies on new units. Retrofitting controls on existing boilers can have numerous 

issues, including site constraints and room for the new controls, demolition requirements for existing 

controls, and down time during construction and interconnection of the new systems. 

2.4 Identifying Potential Control Technologies. 

As stated in the U.S. EPA’s October 1990 New Source Review Workshop Manual, the first step in a "topdown" analysis is to identify, for the emissions unit in question, all "available" control options. Available 

control options are those air pollution control technologies or techniques with a practical potential for 

application to the emissions unit and the regulated pollutant being evaluated. Air pollution control 

technologies and techniques include the application of production process or available methods, systems, 

and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control 

of the affected pollutant, including technologies employed outside of the United States. In some 

circumstances, inherently lower-polluting processes are appropriate for consideration as available control 

alternatives. The control alternatives should include not only existing controls for the source category in 

question, but also (through technology transfer) controls applied to similar source categories and gas 

streams, and innovative control technologies. Technologies required under lowest achievable emission 

rate (LAER) determinations are available for BACT purposes and must also be included as control 

alternatives and usually represent the top alternative. In Step 1, applicants should identify all control 

options with potential application to the emissions unit under review. 

2.5 Technical Feasibility. 

Step 2 of the BACT analysis involves the evaluation of all of the identified available control technologies 

from Step 1 to determine their technical feasibility. A control technology is technically feasible if it has 

been previously installed and operated successfully at a similar emission source, or there is technical 

agreement that the technology can be applied to the emission source. Technical infeasibility is 

demonstrated through clear physical, chemical, or other engineering principles that demonstrate that 

technical difficulties preclude the successful use of the control option. 

The technology must be commercially available for it to be considered as a candidate for BACT. EPA’s 

New Source Review Workshop Manual, page B.12 states, “Technologies which have not yet been applied 

to (or permitted for) full scale operations need not be considered available; an applicant should be able to 

purchase or construct a process or control device that has already been demonstrated in practice.” 

In general, if a control technology has been "demonstrated" successfully for the type of emission source 

under review, then it would normally be considered technically feasible. For an undemonstrated 
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technology, “availability” and “applicability” determine technical feasibility. Page B.17 of the New 

Source Review Workshop Manual states: 

Two key concepts are important in determining whether an undemonstrated 

technology is feasible: "availability" and "applicability." As explained 

in more detail below, a technology is considered "available" if it can be 

obtained by the applicant through commercial channels or is otherwise 

available within the common sense meaning of the term. An available 

technology is "applicable" if it can reasonably be installed and operated 

on the source type under consideration. A technology that is available 

and applicable is technically feasible. Availability in this context is 

further explained using the following process commonly used for bringing 

a control technology concept to reality as a commercial product: 

• concept stage; 

• research and patenting; 

• bench scale or laboratory testing; 

• pilot scale testing; 

• licensing and commercial demonstration; and 

• commercial sales. 

 

Applicability involves not only commercial availability (as evidenced by past or expected near-term 

deployment on the same or similar type of emission source), but also involves consideration of the 

physical and chemical characteristics of the gas stream to be controlled. A control method applicable to 

one emission source may not be applicable to a similar source depending on differences in physical and 

chemical gas stream characteristics. 

2.6 Economic Feasibility. 

Economic feasibility is normally evaluated according to the average and incremental cost effectiveness. 

From the U.S. EPA’s New Source Review Manual, page B.31, average cost effectiveness is the dollars 

per ton of pollutant reduced. The incremental cost effectiveness is the cost per ton reduced from the 

technology being evaluated as compared to the next lower technology. The EPA NSR Review Manual 

states that, “where a control technology has been successfully applied to similar sources in a source 

category, an applicant should concentrate on documenting significant cost differences, if any, between the 

application of the control technology on those sources and the particular source under review”. 

2.6.1 Average Cost Effectiveness. 

In the EPA’s New Source Review Manual, page B.37, average cost effectiveness is calculated as: 

Average Cost Effectiveness Control option annualized cost 

($ per ton removed) = Baseline emission rate – Control option emissions rate 

The average cost effectiveness is based on the overall reduction in the air pollutant from the baseline 

emission rate. In the draft Workshop Manual, the EPA states that the baseline emission rate represents 
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uncontrolled emissions for the source. However, the manual also states that when calculating the cost 

effectiveness of adding controls to inherently lower emitting processes, baseline emissions may be 

assumed to be the emissions from the lower emitting process itself. 

2.6.2 Incremental Cost Effectiveness. 

In addition to determining the average cost effectiveness of a control option, the U.S. EPA’s New Source 

Review Manual states that the incremental cost effectiveness between dominant control options should 

also be calculated. The incremental cost effectiveness compares the costs and emissions performance 

level of a control option to those of the next most stringent control option: 

Incremental Cost ($ per Control option annualized cost – Next control option annualized cost 

incremental ton removed) = Next control option emission rate – Control option emissions rate 

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Chapter 3. Control Technology Review for 

Process P121; Biomass Fuels Material Handling 

Processes. 

3.1 Emission Unit Description. 

We Energies’ 50 MW Biomass-Fired Cogeneration Facility Project will involve the installation of one 

new biomass fuel-fired, circulating fluidized bed (CFB) boiler. To support this new boiler, the Plant will 

require new biomass fuel handling equipment. The individual fuel material handling processes or 

operations will include delivery, unloading, conveying, hogging (shredding), storage, and reclaim. The 

biomass fuels will be received in a shredded form which may require final shredding to prepare the fuel 

for combustion. These fuels may be received either by self unloading trucks, or by fixed bed trucks 

which will be unloaded using a truck dumper. Under normal operation, the majority of biomass fuels will 

be received by the fixed bed trucks using the truck dumper, estimated at six trucks per hour. To control 

fugitive dust emissions to the highest degree possible, the truck dumper will unload the trucks into an 

enclosure. After unloading, the fuels will be conveyed via completely enclosed conveyors to Transfer 

Tower 1, and then to the Hog Building. In the Hog Building, the fuels will be shredded in a hog to the 

final size required to fire the fuels in the CFB boiler. After the Hog Building, the fuels will be conveyed 

to Transfer Tower 2, and then to the Biomass Fuels Storage Building. This building will have a belt 

tripper to load the fuels into the building, and a reclaim system to reclaim the fuels for delivery to the 

boiler. After the fuel is reclaimed, the fuel will be conveyed to Transfer Tower No. 1, and then to the 

CFB Boiler fuel silos for combustion. 

To control fugitive dust emissions from these operations, the unloading enclosure, conveyor transfer 

points, and transfer towers will be equipped with dust collection hoods. These hoods will be connected to 

an induced draft fan to collect dust generated at these points. The dust laden air will be directed to a 

fabric filter baghouse to remove PM prior to venting the air. 

Process P121 will include a dust collection system that will control dust from the unloading, conveying, 

and hogging operations. This process will also include a pneumatic or mechanical fuel conveying system 

that will convey bark and wood waste from the Domtar Mill’s wood room to the Hog Building. The 

conveying air (if pneumatic) and dust collection pickup air will be exhausted to a fabric filter baghouse 

prior to discharge to the atmosphere. The conveying air will be exhausted to a fabric filter baghouse prior 

to discharge to the atmosphere. 
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3.2 BACT Baseline. 

Fugitive dust emissions material handling operations is regulated under NR 415.04(2)(b), Wis. Adm. 

Code. This section states: 

(b) Materials handling operations are subject to the following 

requirements: 

1. Materials handling operations, including but not limited to 

crushing, grinding, mixing, screening, compacting, conveying, 

handling of waste material with more than 5% silt, and loading 

and unloading of railcar, truck, ship or barge shall have fugitive 

emissions controlled to 20% opacity when wind speeds are less 

than 25 miles per hour except for 3 minutes in any hour when 

fugitive emissions may equal 50% opacity. 

2. Any device used to control fugitive emissions from 

materials handling operations which has a discharge to the 

ambient air shall be controlled equal to or less than 0.20 pounds 

of particulate matter per 1000 pounds of exhaust gas. 

Dust collection systems would be subject to a PM emission limit of 0.20 pounds of PM per 1,000 pounds 

of exhaust gas. For an exhaust gas density of 0.075 pounds per cubic foot, an emission limit of 0.20 

pounds of PM per 1,000 pounds of exhaust gas is equal to 0.06 grains per dry standard cubic foot of 

exhaust gas. 

In addition, NR 415.04(1)(b) and (f) includes the following requirements for the control of fugitive dust 

from roads and roadways: 

(b) Application of asphalt, water, suitable chemicals or plastic 

covering on dirt roads, material stockpiles and other surfaces 

which can create airborne dust, provided such application does 

not create a hydrocarbon, odor or water pollution problem. 

(f) The paving or maintenance of roadway areas so as not to 

create air pollution. 

3.3 Step 1. Identify All Available Control Technologies. 

There is limited information available on the control of fugitive dust and particulate matter emissions 

from biomass fuel material handling processes. However, these biomass fuel material handling processes 

are similar (to some degree) to coal material handling systems. Several studies have been conducted on 

the control of fugitive dust from coal material handling systems. The potential PM control technology 

options are summarized in Table 3-1. These controls include the use of building enclosures or hoods, the 

use or application of dust suppression chemicals or the application of water sprays, and the use of dust 

collection systems with fabric filter baghouses. In most cases, these control systems can be used in 

combination to improve the overall control of PM, PM10, and PM2.5 emissions. 
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3.4 Step 2. Eliminate Technically Infeasible Options. 

All of the options identified in Table 3-1 are technically feasible control technologies. 

3.5 Step 3. Rank the Technically Feasible Control Technologies. 

Table 3-1 includes the potential controls and a general ranking of the control effectiveness for the 

proposed material handling processes. Note that in some cases, the ranking of the most effective controls 

can be subjective, since control efficiencies can be difficult to quantify. The use of a building or 

enclosure combined with the use of a dust collection system and a fabric filter baghouse is generally 

expected to be the most effective control. However, in some cases, this may not be the case. A dust 

collector is often employed primarily as a housekeeping device to help keep the inside of the building or 

enclosure clean. A dust collector is an active dust control system that induces an airflow into the building 

and out through the dust collection system. Because fabric filter baghouses emit a threshold amount of 

PM regardless of inlet loading, the dust collector, when in operation, is always emitting PM, albeit at very 

low rates. Conversely, the use of buildings or enclosures combined with wet dust suppression systems is 

a passive control system that does not induce an airflow out of the building or enclosure. For this control 

arrangement, PM emitted to the atmosphere outside of the building or enclosure is emitted passively. In 

some cases, especially when unloading wet or moist biomass fuels, the use of wet dust suppression 

systems may be more effective than the use of dust collection systems. Further, the fabric filter bags in 

the dust collector systems may be blinded or plugged by operating the dust collectors when very wet 

biomass materials are being unloaded. 

TABLE 3-1. Potential PM control technologies for the biomass fuels material handling processes. 

Estimated Control Efficiency Control Technologies 

Range Reference 

1. Building enclosures or hoods. 70 – 99% 1, 2, 3 

2. Building enclosures or hoods combined with 

dust collectors with fabric filter baghouse. 90 - 99% 1, 3 

3. Building enclosures or hoods combined with 

dust suppression sprays. 90 - 99% 3 

4. Dust suppression and water sprays. 70 – 95% 3 

Footnotes 

1. Fugitive Emissions from Coal-Fired Power Plants, Electric Power Research Institute, 

Document EPRI CS-3455, June, 1984, Table 3-19. 

2. EPRI CS-3455, Table 3-16. 

3. Coal Handling Emissions Evaluation Roundtable (CHEER) Workshop report, Texas Natural 

Resource Conservation Commission, May 1996. 
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3.6 Step 4. Evaluate the Most Effective Controls. 

Based on this analysis, the use of a building or enclosure combined with the use of dust collectors and 

fabric filter baghouses, or the use of a building or enclosure combined with wet dust suppression systems 

represent the most effective controls for PM emissions from these biomass fuel handling processes. Both 

dust control systems are highly effective control systems. The use of either control system will be highly 

effective in controlling PM, PM10, and PM2.5 emissions from these processes. Further, the flexibility to 

use either control system is beneficial in maintaining the control systems and will also help control 

emissions from changing fuel and atmospheric conditions. 

TABLE 3-2. Potential emissions for Processes P121 based on the BACT limits. 

EMISSIONS 

Unit Description PM2.5, 

lb/hr 

PM2.5, 

tons/yr 

PM10, 

lb/hr 

PM10, 

tons/yr 

PM, 

lb/hr 

PM, 

tons/yr 

P121 Biomass Fuels Unloading, 

Screening, Hogging, and Conveying 1.87 8.21 3.75 16.41 3.75 16.41 

Footnotes 

Estimates for Processes P121 include biomass handling throughput from both fixed bed and selfunloading trucks, and unloading of fixed bed trucks. Emissions from self-unloading trucks is addressed 

Chapter 4. 

3.7 Step 5. Proposed BACT Requirements. 

Based on the above analysis, We Energies proposes the use of a building or enclosure combined with dust 

collectors and fabric filter baghouses, or the use of a building or enclosure combined with wet dust 

suppression systems as the best available control technology for the biomass fuel material handling 

processes P121. The building or enclosures will include an enclosed truck dumper hopper, fully enclosed 

conveyor galleries, and fully enclosed conveyor transfer points. We Energies proposes the following as 

BACT for these biomass fuel material handling processes: 

(1) Particulate matter emissions from the biomass fuel material 

handling processes P121 shall be controlled using buildings or 

enclosures combined with dust collection systems or wet dust 

suppression systems as the best available control technology. 

(2) PM and PM10 emissions from the dust collection control systems 

shall be limited to 0.004 grains per dry standard cubic foot of 

exhaust gas. 

(3) PM2.5 emissions from the dust collection control systems shall be 

limited to 0.002 grains per dry standard cubic foot of exhaust gas. 
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Chapter 4. Control Technology Review for 

Process F122: Biomass Fuels Self Unloading 

Truck Unloading. 

Biomass fuels may be delivered by self unloading semi trailer trucks and unloaded to a hopper feeding the 

same conveyor as the truck dumper hoppers. The U.S. EPA’s AP-42, Compilation of Air Pollutant 

Emission Factors, 5th Edition, section 13.2.4, Equation 1 may be used for estimating emissions from this 

unloading process which is a drop operation: 

1.4

1.3

2

5 (0.0032)

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡

= M

U

E k

where, E = Emission factor, pound per ton of material unloaded 

U = Mean wind speed, mph = 6.9 

M = Material moisture content, % = 25 

k = Particle size multiplier (dimensionless) 

k = 0.053 (for PM2.5) = 0.35 (for PM10) = 0.74 (for PM)

The normal moisture content for biomass fuels is expected to range from 25 -50% on an as-received basis. 

Based on a mean wind speed of 6.9 miles per hour, the uncontrolled emission factor for unloading biomass 

fuels is 0.0000075 lb/ton (PM2.5), 0.0000496 lb/ton (PM10), and 0.00010 lb/ton (PM). 

As noted previously, the majority of the biomass fuels received will normally be delivered by fixed bed 

trucks which will be unloaded using the truck dumper which is included as part of Process P121. For the self 

unloading trucks, the maximum truck unloading rate is expected to be 25 tons per truck, and 5 trucks per 

hour, or a total of 125 tons per hour.1

 The maximum annual use is expected to be 778,700 ton per year. 

Based on these values, the maximum uncontrolled PM2.5, PM10, and PM emissions are expected to be 6, 39, 

and 82 pounds per year. 

4.1 BACT Baseline. 

Fugitive dust emissions material handling operations is regulated under NR 415.04(2)(b), Wis. Adm. 

Code. This section states: 

 

1

 Emissions from fixed bed truck unloading is addressed in Chapter 3.0. 
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(b) Materials handling operations are subject to the following 

requirements: 

1. Materials handling operations, including but not limited to 

crushing, grinding, mixing, screening, compacting, conveying, 

handling of waste material with more than 5% silt, and loading 

and unloading of railcar, truck, ship or barge shall have fugitive 

emissions controlled to 20% opacity when wind speeds are less 

than 25 miles per hour except for 3 minutes in any hour when 

fugitive emissions may equal 50% opacity. 

4.2 Step 1. Identify All Available Control Technologies. 

Potential PM control technology options for this unloading process are summarized in Table 4-1. 

4.3 Step 2. Eliminate Technically Infeasible Options. 

All of the options identified in Table 4-1 are technically feasible for the truck unloading process. 

4.4 Step 3. Rank the Technically Feasible Control Technologies. 

Table 4-1 includes the potential controls and a ranking of the control effectiveness. In some cases, these 

control technologies can be combined to improve the overall effectiveness of the controls. Note that the 

ranking of the most effective controls for fugitive dust sources can be subjective, since control 

efficiencies are in some cases difficult to quantify. 

TABLE 4-1. Potential PM and PM10 control technologies for Process F123, self-unloading trucks. 

Control Technologies Control Efficiency Reference 

1. Enclosures 70 – 100% Reference 1 

2. Dust Collectors (Fabric Filter Baghouse) 80 – 99% Reference 1 

3. Telescoping chutes and/or lowering wells 75 – 85% Reference 1 

4. Water sprays and/or chemical dust suppression 70 – 90% Reference 1 

5. Minimize drop heights 25% Reference 1 

Ref. 1. Fugitive Emissions from Coal-Fired Power Plants, Electric Power Research Institute (EPRI), Document 

EPRI CS-3455, June, 1984, Table 3-19. Ref. 2. EPRI CS-3455, Table 3-16. 

4.5 Step 4. Evaluate the Most Effective Controls. 

4.5.1 Total Enclosure and Dust Collection System. 

Enclosures combined with the use of a dust collection system and a fabric filter baghouse are generally 

expected to be the most effective control (or combination of controls). However, in some cases, this may 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

- 20 -

be misleading. A dust collector is often employed first and foremost as a housekeeping device to help 

keep the inside of the building or enclosure clean. They may also be used as a safety device to ventilate 

the enclosure for the working personnel. In many cases, the enclosure may be required to be ventilated 

for safety reasons. A dust collector is an active dust control system that induces an airflow into the 

enclosure and out through the dust collection system. Because fabric filter baghouses emit a threshold 

amount of PM regardless of inlet loading, the dust collection system, when in operation, is always 

emitting PM, albeit at low concentrations. Conversely, a wet dust suppression system is a passive control 

technology that does not induce an airflow out of the enclosure. Whatever PM is emitted to the 

atmosphere is emitted passively. 

Based on the uncontrolled emission factors and a maximum annual fuel throughput of 778,700 tons per 

year, this truck unloading process will have maximum uncontrolled PM, PM10, and PM2.5 emissions of 6, 

39, and 82 pounds per year These are extremely low numbers, based in large part on the fact that these 

materials have generally high moisture contents and therefore very little emissions. For a dust collection 

system with an airflow of 2,000 acfm and a design grain loading of 0.004 gr/dscf, the system would emit 

0.069 pounds per hour. For a fuel use of 778,700 tons per year and a design unloading process rate of 

100 tons per hour, the dust control system would operate at least 7,790 hours per year. Therefore, for the 

combined use of an enclosure and dust collection system, potential annual PM, PM10, and PM2.5 emissions 

would be approximately 538 pounds per year which would actually be higher than for the normal 

unloading process. 

4.6 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies has concluded that the use of self unloading trucks in combination 

with a wet dust suppression system represents the best available control technology (BACT) for process 

F122, the biomass fuels self unloading truck operation. We Energies proposes the following limits as 

BACT for Process F122: 

(1) Particulate matter (PM), PM10, and PM2.5 emissions shall be 

controlled using self unloading trucks in combination with a wet 

dust suppression system as the best available control technology. 

 

We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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Chapter 5. Control Technology Review for 

Process F123: Biomass Fuels Storage and 

Reclaim. 

After the biomass fuels are unloaded, they will be conveyed to the Hog Building to screen and shred the 

fuel. From the Hog Building, the fuel will be conveyed in fully enclosed conveyors to the Biomass Fuels 

Storage building. Inside the storage building, the biomass fuels will drop from the conveyor onto a pile. 

The fuels will then be reclaimed from the storage building in a “first in, first out” material management 

system. The maximum storage building load-in rate is expected to be 250 tons per hour and 778,700 tons per 

year. The maximum load-out rate is also expected to be 250 tons per hour. 

Emissions from the load-in and load-out or reclaim “drop” operations may be estimated using the U.S. 

EPA’s AP-42, Compilation of Air Pollutant Emission Factors, 5th Edition, section 13.2.4, Equation 1: 

1.4

1.3

2

5 (0.0032)

⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡

= M

U

E k

where, E = Emission factor, pound per ton of material unloaded 

U = Mean wind speed, mph = 1.0 

M = Material moisture content, % = 25% 

k = Particle size multiplier (dimensionless) 

k = 0.053 (for PM2.5) = 0.35 (for PM10) = 0.74 (for PM)

The normal moisture content for biomass fuels is expected to range from 25 -50% on an as-received basis. 

Based on a mean wind speed of 1.0 miles per hour inside the building, the uncontrolled emission factor for 

unloading biomass fuels is 6.0 x 10-7 lb/ton (PM2.5), 4.0 x 10-6 lb/ton (PM10), and 8.5 x 10-6 lb/ton (PM). 

Based on these values, the maximum uncontrolled PM2.5, PM10, and PM emissions are expected to be 1, 6, 

and 14 pounds per year. 

5.1 BACT Baseline. 

NR 415.04(1)(b) and (f) includes the following requirements for the control of fugitive dust from material 

storage and stockpiles: 

(b) Application of asphalt, water, suitable chemicals or plastic 

covering on dirt roads, material stockpiles and other surfaces 

which can create airborne dust, provided such application does 

not create a hydrocarbon, odor or water pollution problem. 
We Energies - Air Pollution Control Construction Permit Application for a 

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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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5.2 Step 1. Identify All Available Control Technologies. 

Potential PM and PM10 control technology options for the biomass fuels storage and reclaim processes are 

summarized in Table 5-1. 

TABLE 5-1. Potential PM control technologies for Process F124, biomass fuels storage. 

Control Technologies Control Efficiency Reference 

1. Enclosures or Silos 70 – 100% Reference 1 

2. Covers 70 – 99% Reference 1 

3. Minimize handling of storage pile materials 50 – 90% Reference 1 

4. Water sprays and/or chemical dust suppression 70 – 90% Reference 1 

5. Minimize drop heights 25% Reference 1 

Ref. 1. Fugitive Emissions from Coal-Fired Power Plants, Electric Power Research Institute (EPRI), Document 

EPRI CS-3455, June, 1984, Table 3-19. Ref. 2. EPRI CS-3455, Table 3-16. 

5.3 Step 2. Eliminate Technically Infeasible Options. 

All of the options identified in Table 5-1 are technically feasible for the biomass fuels storage process. 

5.4 Step 3. Rank the Technically Feasible Control Technologies. 

Table 5-1 includes the potential controls and a ranking of the control effectiveness. In some cases, these 

control technologies can be combined to improve the overall effectiveness of the controls. 

5.5 Step 4. Evaluate the Most Effective Controls. 

The highest level of control for the biomass fuels storage and reclaim operations may be achieved by 

placing the fuels inside of a storage building. The use of a full enclosure will reduce emissions by 90+%. 

5.6 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies has concluded that the use of a biomass fuels storage building 

designed to enclose the entire storage pile and the reclaim activities represents the best available control 

technology for process F123, the biomass fuels storage and reclaim processes. We Energies proposes the 

following limits as BACT for Process F1243: 

(1) Particulate matter (PM), PM10, and PM2.5 emissions shall be controlled using a 

biomass fuels storage building designed to enclose the entire storage pile and the 

reclaim activities as the best available control technology. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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Chapter 6. Control Technology Review for 

Process P124: Boilerhouse Fuel Storage Silos. 

Biomass fuels will be reclaimed from the storage building and conveyed via totally enclosed conveyors to 

the boiler fuel silos located inside the boilerhouse. The fuel silos will include bin vents to vent the silos 

when filling and emptying. 

The bin vents are expected to have an airflow of 300 cubic feet per minute at an uncontrolled grain 

loading of 0.04 grains per dry standard cubic foot of exhaust gas. Therefore, the uncontrolled emissions 

from the bin vents would be 0.45 tons per year. 

6.1 BACT Baseline. 

There are no new source performance standards for this bin vent filter. Under NR 415.04(2)(b), Wis. 

Adm. Code, material handling operations are subject to the following: 

(b) Materials handling operations are subject to the following 

requirements: 

1. Materials handling operations, including but not limited to 

crushing, grinding, mixing, screening, compacting, conveying, 

handling of waste material with more than 5% silt, and loading 

and unloading of railcar, truck, ship or barge shall have fugitive 

emissions controlled to 20% opacity when wind speeds are less 

than 25 miles per hour except for 3 minutes in any hour when 

fugitive emissions may equal 50% opacity. 

2. Any device used to control fugitive emissions from 

materials handling operations which has a discharge to the 

ambient air shall be controlled equal to or less than 0.20 pounds 

of particulate matter per 1000 pounds of exhaust gas. 

Therefore, this process is subject to a PM emission limit of 0.20 pounds of PM per 1,000 pounds of 

exhaust gas. For an exhaust gas density of 0.075 pounds per cubic foot, an emission limit of 0.20 pounds 

of PM per 1,000 pounds of exhaust gas is equal to 0.06 grains per dry standard cubic foot of exhaust gas. 

6.2 Step 1. Identify All Available Control Technologies. 

Potential PM/PM10 and PM2.5 control technology options for the bin vent filters include bin vent filters, or 

uncontrolled emissions. The most common bin vent filters for this application use fabric filter bags that 

collect entrained PM in a manner essentially the same as a fabric filter baghouse. Other bin vent filters 

use cartridge filters rather than fabric filters. Regardless of the filter media, the bin vent filter is a passive 

device, and simply exhausts whatever air is being conveyed into the silo. 
We Energies - Air Pollution Control Construction Permit Application for a 

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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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6.3 Step 2. Eliminate Technically Infeasible Options. 

The use of a bin vent filter and uncontrolled silo venting are technically feasible control options. 

6.4 Step 3. Rank the Technically Feasible Control Technologies. 

Bin vent filters will achieve a PM/PM10 control efficiency of approximately 99.9% of the inlet grain 

loading, or 0.004 grains per dry standard cubic foot of exhaust gas. In addition, bin vent filters will 

achieve a PM2.5 emission rate of 0.002 grains per dry standard cubic foot of exhaust gas. 

6.5 Step 4. Evaluate the Most Effective Controls. 

The only commercially available or feasible control technology to control PM, PM10, and PM2.5 emissions 

from fuel silo bin vents is the addition of vent filters to the silos. Recent permits for similar sources have 

PM and PM10 BACT emission limits for bin vents of 0.004 gr/dscf. Based on this analysis, we have 

concluded that the bin vents can achieve a PM and PM10 outlet grain loading of 0.004 gr/dscf, and a PM2.5

outlet grain loading of 0.002 gr/dscf. 

6.6 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies has concluded that the use of a bin vent filter represents the best 

available control technology for the control of PM, PM10, and PM2.5 emissions from the fuel silo bin 

vents, Process P124. We Energies proposes the following limits as BACT for the fuel storage silos: 

(1) Particulate matter (PM), PM10, and PM2.5 emissions from the 

boiler fuel storage silos shall be controlled using bin vent filters 

as the best available control technology. 

(2) PM and PM10 emissions shall be limited to 0.004 grains per dry 

standard cubic foot of exhaust gas. 

(3) PM2.5 emissions shall be limited to 0.002 grains per dry standard 

cubic foot of exhaust gas. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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Chapter 7. Control Technology Review for 

Processes F125 and F133; Biomass Fuels and 

Ash Truck Haul Roads. 

Biomass fuels will be delivered to the Plant by semi-trailer trucks. The ash from the combustion of the 

biomass fuels will be hauled from the site by totally enclosed pneumatic semi-trailer trucks. Emissions 

from the truck haul truck traffic may be calculated using the paved roads emission factor from AP-42 

(revision 11/2006), Section 13.2.1: Paved Roads, Equation (1): 

C sL W EF k u − ⎥

⎦

⎤ ⎢

⎣

⎡ ⎥

⎦

⎤ ⎢

⎣

⎡ =

0.65 1.5

2 3

where, EFu = Vehicle Emission Factor, lb/mile traveled 

k = 0.0024 [Table 13.2.1-1, for PM2.5] = 0.016 [PM10] = 0.082 [PM] 

sL = silt loading, g/m2

 = 0.6 

W = Average weight of truck (empty = 15 tons; loaded = 40 tons) 

W = 27.5 tons 

 C = emission factor for 1980's vehicle fleet exhaust, brake wear and tire wear. 

 C = 0.00036 lb/VMT [Table 13.2.1-2, for PM2.5] 

 C = 0.00047 lb/VMT [Table 13.2.1-2, for PM10 and PM] 

The silt loading of 0.6 g/m2

 is the ubiquitous silt loading default value for roads with less than 500 

average daily travel (ADT) from AP-42, Table 13.2.1-3. The vehicle weight is the average truck weight, 

with a loaded weight of 40 tons, and an empty weight of 15 tons. Based on these values, the fuel and ash 

haul truck traffic is expected to have uncontrolled emission factors of 0.030 pounds per vehicle mile 

traveled (lb/VMT) for PM2.5, 0.20 lb/VMT (PM10), and 1.04 lb/ton (PM). 

The biomass fuel haul trucks are expected to deliver up to 10 loads per hour, and up to 778,700 tons per 

year, equal to 31,150 deliveries. The total paved road round trip travel for each delivery is expected to be 

3,000 feet, or 0.57 mile. Therefore, the total annual paved road vehicle miles traveled will be 17,754 

miles per year. Based on these values, the maximum uncontrolled PM2.5, PM10, and PM emissions for the 

biomass fuels truck traffic would be 0.3, 1.8, and 9.2 tons per year. 

The maximum ash generation rate would be 29,200 tons per year. Based on a vehicle capacity of 25 tons, 

this annual ash generation rate would require 1,168 shipments. In addition, the maximum daily haul rate 

would be 8 shipments per day. The total paved road round trip travel for each delivery is expected to be 

3,000 feet, or 0.57 mile. Therefore, the total annual vehicle miles traveled will be 1,168 vehicles and 0.57 

miles per vehicle, or 666 miles per year. Based on these values, the maximum uncontrolled PM2.5, PM10, 

and PM emissions for the ash truck traffic would be 0.01, 0.07, and 0.35 tons per year. 
We Energies - Air Pollution Control Construction Permit Application for a 

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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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7.1 BACT Baseline. 

There are no new source performance standards for these haul trucks. Under NR 415.04(1)(b), Wis. 

Adm. Code, material handling vehicle haul operations are subject to the following: 

NR 415.04 Fugitive dust. No person may cause, allow or 

permit any materials to be handled, transported or stored without 

taking precautions to prevent particulate matter from becoming 

airborne. Nor may a person allow a structure, a parking lot, or a 

road to be used, constructed, altered, repaired, sand blasted or 

demolished without taking such precautions. 

(1) Such precautions shall include, but not be limited to: 

(a) Use, where possible, of water or chemicals for control of 

dust in the demolition of existing buildings or structures, or 

construction operations. 

(b) Application of asphalt, water, suitable chemicals or 

plastic covering on dirt roads, material stockpiles and other 

surfaces which can create airborne dust, provided such 

application does not create a hydrocarbon, odor or water pollution 

problem. 

(c) Installation and use of hoods, fans, and air cleaning 

devices to enclose and vent the areas where dusty materials are 

handled. 

(d) Covering or securing of materials likely to become 

airborne while being moved on public roads, railroads or 

navigable waters. 

(e) Conduct of agricultural practices such as tilling of land or 

application of fertilizers in such manner as not to create air 

pollution. 

(f) The paving or maintenance of roadway areas so as not to 

create air pollution. 

7.2 Step 1. Identify All Available Control Technologies. 

Potential PM/PM10 and PM2.5 control technology options for EG33 are summarized in Table 7-1. 

TABLE 7-1. Potential PM control technologies for truck haul roads. 

Control Technologies Control Efficiency Reference 

1. Pave roadways 80 – 95% 

2. Water and/or chemical dust suppression 0 – 95% AP-42, 13.2.2-2 

3. Wheel wash stations to minimize tracking 0 – 90% AP-42, s. 13.2.1.4 

4. Posted maximum vehicle speeds 0 – 50% 

Ref. 1. Fugitive Emissions from Coal-Fired Power Plants, Electric Power Research Institute (EPRI), Document 

EPRI CS-3455, June, 1984, Table 3-19. Ref. 2. EPRI CS-3455, Table 3-16. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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7.3 Step 2. Eliminate Technically Infeasible Options. 

All of the options identified in Table 7-1 are technically feasible. 

7.4 Step 3. Rank the Technically Feasible Control Technologies. 

Table 7-1 includes the potential controls and a ranking of the control effectiveness for the control of 

fugitive dust from the biomass delivery and ash haul trucks. These control technologies can be combined 

to improve the overall effectiveness of the controls. 

7.5 Step 4. Evaluate the Most Effective Controls. 

The highest levels of control would be achieved by paving of all roadways and by the use of dust 

suppression on the roads. We Energies proposes to pave all haul roads, and use dust suppression on the 

roads as necessary to control fugitive dust from these vehicles. This combination of controls is expected 

to reduce fugitive dust emissions from paved roadways by 85%. The controlled emission rates are 

detailed in Tables 7-2 and 7-3. 

7.6 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies has concluded that the use of paved roadways in combination with 

dust suppression represents the best available control technology (BACT) for the biomass fuel truck haul 

roads and the ash truck haul roads. We Energies proposes the following limits as BACT for these 

processes: 

(1) Particulate matter (PM), PM10, and PM2.5 emissions shall be controlled 

using paved roadways in combination with dust suppression as the 

best available control technology. 

(2) A Fugitive Dust Control Plans shall be developed and submitted to the 

Department. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP E

Appendix C: Control Technology Review for the Balance of Plant Equipment. 

- 28 -

TABLE 7-2. Fugitive dust emissions from the Biomass Fuels Delivery Truck Haul Roads, Process F125. 

Road 

Surface 

Silt 

Loading 

Average 

Weight of 

Truck 

Exhaust, 

Brake, 

Tire 

Factor 

PM 

Emission 

Factor 

Vehicle Miles 

Traveled 

Dust 

Suppressan

Control 

Efficiency 

POLLUTANT 

Particle 

Size 

Multiplier 

g/m2 ton lb/VMT lb/VMT VMT/hr VMT/yr % 

PM2.5 0.0024 0.6 27.5 0.00036 0.030 5.87 18,162 85% PM10 0.016 0.6 27.5 0.00047 0.203 5.87 18,162 85% PM 0.082 0.6 27.5 0.00047 1.040 5.87 18,162 85% 

TABLE 7-3. Fugitive dust emissions from the Ash Truck Haul Roads, Process F133. 

Road 

Surface 

Silt 

Loading 

Average 

Weight of 

Truck 

Exhaust, 

Brake, 

Tire 

Factor 

PM 

Emission 

Factor 

Vehicle Miles 

Traveled 

Dust 

Suppressan

Control 

Efficiency 

POLLUTANT 

Particle 

Size 

Multiplier 

g/m2 ton lb/VMT lb/VMT VMT/hr VMT/yr % 

PM2.5 0.0024 0.6 27.5 0.00036 0.030 1.2 683 85% PM10 0.016 0.6 27.5 0.00047 0.203 1.2 683 85% PM 0.082 0.6 27.5 0.00047 1.040 1.2 683 85% 

Footnotes 

1. Paved road emissions were estimated from Chapter 13.2.1, AP-42 (11/06). 2. Silt loading (g/m2) is the Ubiquitous Silt Loading Default Value for roads with less than 500 average daily travel from A

3. The average weight of both the fuel and ash haul trucks is based on a loaded truck weight of 40 tons, and an unloaded tr

4. For fuel delivery, the vehicle miles traveled per hour is based on 10 trucks per hour, and a round trip distance of 3,100 f5. For ash trucks, the vehicle miles traveled per hour is based on 2 trucks per hour, and a round trip distance of 3,100 feet (
We Energies - Air Pollution Control Construction Permit Application for a 

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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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Chapter 8. Control Technology Review for 

Process P131, CFB Boiler Bed Material Silo; and 

Process P132, CFB Boiler Ash Silo. 

The CFB boiler will require an inert bed material to operate. For this biomass-fired boiler, the bed 

material will be sand. This CFB boiler bed material silo bin vent is designated as Stack S131, Process 

P131. Fly ash from the CFB boiler will be conveyed by a vacuum ash handling system to an ash storage 

silo equipped with a vent filter. The silo bin vent will allow the silo to vent when filling or emptying. 

This ash silo bin vent is designated as Stack S132, Process P132. 

Both the CFB boiler bed material silo bin vent and the ash silo bin vent are expected to have a volumetric 

flow rate of 1,000 acfm (each). Based on an uncontrolled grain loading of 0.4 grains per cubic foot, these 

bin vents would have uncontrolled emissions of 3.4 pounds per hour and 15.0 tons per year. 

8.1 BACT Baseline. 

There are no new source performance standards for this bin vent filter. Under NR 415.04(2)(b), Wis. 

Adm. Code, material handling operations are subject to the following: 

(b) Materials handling operations are subject to the following 

requirements: 

1. Materials handling operations, including but not limited to 

crushing, grinding, mixing, screening, compacting, conveying, 

handling of waste material with more than 5% silt, and loading 

and unloading of railcar, truck, ship or barge shall have fugitive 

emissions controlled to 20% opacity when wind speeds are less 

than 25 miles per hour except for 3 minutes in any hour when 

fugitive emissions may equal 50% opacity. 

2. Any device used to control fugitive emissions from 

materials handling operations which has a discharge to the 

ambient air shall be controlled equal to or less than 0.20 pounds 

of particulate matter per 1000 pounds of exhaust gas. 

Therefore, this process is subject to a PM emission limit of 0.20 pounds of PM per 1,000 pounds of 

exhaust gas. For an exhaust gas density of 0.075 pounds per cubic foot, an emission limit of 0.20 pounds 

of PM per 1,000 pounds of exhaust gas is equal to 0.06 grains per dry standard cubic foot of exhaust gas. 

8.2 Step 1. Identify All Available Control Technologies. 

Potential PM/PM10 and PM2.5 control technology options for the bin vent filter include bin vent filters, or 

uncontrolled emissions. The most common bin vent filters for this application use fabric filter bags the 

collect entrained PM in a manner essentially the same as a fabric filter baghouse. Other bin vent filters 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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use cartridge filters rather than fabric filters. Regardless of the filter media, the bin vent filter is a passive 

device, and simply exhausts whatever air is being conveyed into the silo. 

8.3 Step 2. Eliminate Technically Infeasible Options. 

The use of a bin vent filter and uncontrolled silo venting are technically feasible control options. 

8.4 Step 3. Rank the Technically Feasible Control Technologies. 

Bin vent filters will achieve a PM/PM10 control efficiency of approximately 99.9% of the inlet grain 

loading, or 0.004 grains per dry standard cubic foot of exhaust gas. In addition, bin vent filters will 

achieve a PM2.5 emission rate of 0.002 grains per dry standard cubic foot of exhaust gas. 

8.5 Step 4. Evaluate the Most Effective Controls. 

The only commercially available or feasible control technology to control PM, PM10, and PM2.5 emissions 

from ash silo bin vent is the addition of vent filters to the silos. Recent permits for similar sources have 

PM and PM10 BACT emission limits for bin vents of 0.004 gr/dscf. Based on this analysis, we have 

concluded that the bin vents can achieve a PM and PM10 outlet grain loading of 0.004 gr/dscf, and a PM2.5

outlet grain loading of 0.002 gr/dscf. 

8.6 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies has concluded that the use of a bin vent filter represents the best 

available control technology for the control of PM, PM10, and PM2.5 emissions from the CFB boiler bed 

material silo bin vent, Process P131, and the ash silo bin vent, Process P132. We Energies proposes the 

following limits as BACT for these processes: 

(4) Particulate matter (PM), PM10, and PM2.5 emissions from the 

CFB boiler bed material silo bin vent, Process P131, and the ash 

silo bin vent, Process P132, shall be controlled using a bin vent 

filter as the best available control technology. 

(5) PM and PM10 emissions shall be limited to 0.004 grains per dry 

standard cubic foot of exhaust gas. 

(6) PM2.5 emissions shall be limited to 0.002 grains per dry standard 

cubic foot of exhaust gas. 
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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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Chapter 9. Control Technology Review for 

Process P141: Cooling Tower. 

9.1 Emission Unit Description. 

We Energies 50 MW Biomass Fuels Cogeneration Facility will require a new mechanical draft cooling 

tower which will be designated as Process P141. This cooling tower will be a plume abated tower which 

will use additional air to desaturate the plume leaving the cooling tower to reduce visible plume issues 

and the potential for icing and fogging. The specifications for the new cooling tower are summarized in 

Table 9-1. 

TABLE 9-1. Specifications for the new plume abated mechanical draft cooling tower, Process P141. 

Cooling Tower Water Design Parameters 

Total Circulating Water Flow to Cooling Tower, gpm 22,000 

Number of Cells 8 

Total Dissolved Solids, ppm 1,600 

Design Drift Loss, % 0.0005% 

Cooling Tower Physical Design Parameters 

Release Height, feet 70 

Tower Enclosure Height, feet 58 

Exit Diameter per cell, feet 25 

Cooling Tower Gas Flow Design Parameters 

Volumetric flow rate per cell, actual cubic feet per minute 528,000 

Volumetric flow rate, entire tower, actual cubic feet per minute 4,227,000 

9.2 Cooling Tower Emissions. 

In a mechanical draft cooling tower, the circulating cooling water is introduced into the top of the tower. 

As the water falls through the tower, an air flow is induced in a countercurrent flow using an induced 

draft fan. A portion of the circulating water evaporates, cooling the remaining water. A small amount of 

the water is entrained in the induced air flow in the form of liquid phase droplets or mist. Demisters are 

used at the outlet of cooling towers to reduce the amount of water droplets entrained in the air. The water 

droplets that pass through the demisters and are emitted to the atmosphere are called drift loss. When 

these droplets evaporate, the dissolved solids in the droplet become particulate matter. Therefore, 

cooling towers are sources of PM, PM10, and PM2.5 emissions. 

Cooling tower PM emissions are calculated based on the circulating water flow rate, the total dissolved 

solids (TDS) in the circulating water, and the design drift loss according to the following equation: 
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50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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⎥

⎦

⎤ ⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡ = 100

%DL

10

C E (60 min/hr)(8.345 lb water/gal) 6

TDS kQ

Where, E = Particulate matter emissions, pounds per hour 

 Q = Circulating water flow rate, gallons per minute = 22,000 gpm 

 CTDS = Circulating water total dissolved solids, parts per million = 1,600 ppm 

 DL = Drift loss, % = 0.0005% 

 k = particle size multiplier, dimensionless 

The value of the particle size multiplier (k) is based on the distribution of water droplet size in the cooling 

tower drift loss. The diameter of the airborne particle that would be produced by the evaporation of the 

liquid water from a drift droplet is given by the following equation2

: 

 Where, ddroplet = Maximum diameter of the drift droplet that would produce a dry particle 

size of dparticle or smaller 

 dparticle = Dry particle (particulate matter) particle size, microns

 ρsalt = Density of particle = 2.5 g/cm3

 ρwater = Density of water = 1.0 g/cm3

 CTDS = Circulating water total dissolved solids, parts per million, ppm 

Size Distribution for Cooling Tower Particulate Emissions * 

EPRI Droplet Diameter, 

um 

EPRI % Mass Smaller EPRI Droplet Diameter, 

um 

EPRI % Mass Smaller 

10 0.00 180 91.03 

20 0.20 210 92.47 

30 0.23 240 94.09 

40 0.51 270 94.69 

50 1.82 300 96.29 

60 5.70 350 97.01 

70 21.35 400 98.34 

90 49.81 450 99.07 

110 70.51 500 99.07 

130 82.02 600 100.00 

150 88.01 150 88.01 

* Methodology and EPRI droplet diameter and % mass smaller values from Reisman, J. and Frisbie, G., 

"Calculating Realistic PM10 Emissions from Cooling Towers." 

The above table is the drift loss droplet size distribution for a large cooling tower. For a circulating water 

TDS level of 1,600 ppm, the drift loss droplet size would need to be smaller than 116 microns to form 

 

2

 From the paper Cooling Tower Emissions Quantification Using the Cooling Technology Institute Test Code ATC40, Cooling Technology Institute, Paper No. TP03-08, K. Hennon, D. Wheeler, Power Generation Technologies. 

1/3 6 10 ⎥

⎦

⎤ ⎢

⎣

⎡ =

water TDS

salt

droplet particle C

d d

ρ

ρ
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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PM10 emissions, and less than 29 microns to form PM2.5. From this table, 82% of the cooling tower drift 

loss (i.e., droplet particle sizes less than 130 microns), would result in PM10 emissions, and 0.23% of the 

cooling tower drift loss would result in PM2.5 emissions. 

TABLE 9-2. Potential emissions for the new mechanical draft cooling tower, Process P141. 

Flowrate CTDS Drift Loss k Emission Rate POLLUTANT 

gal/min ppm % lb/hr ton/yr

Particulate Matter PM 22,000 1,600 0.0005% 1.00 0.088 0.386

Particulate Matter PM10 22,000 1,600 0.0005% 0.82 0.072 0.317

Particulate Matter PM2.5 22,000 1,600 0.0005% 0.0023 0.00020 0.00087

9.3 BACT Baseline. 

There are no specific state implementation plan (SIP) requirements or new source performance standards 

for this cooling tower. 

9.4 Step 1. Identify all available control technologies. 

In a review of recently issued permits for new power plants equipped with cooling towers, demisters are 

the only identified control technology to limit PM emissions. Demisters can be designed for various 

levels of drift loss control. The cooling tower drift loss control requirements representing BACT for 

recently permitted power plants are summarized in Table 9-3. From Table 9-3, the required drift loss 

control requirements for permits issued since 2007 range from 0.0005% to 0.002%. To reduce drift loss, 

additional layers of demisters must be installed in the cooling tower. This makes the cooling tower taller 

and increases the fan horsepower and auxiliary power requirements. 

9.5 Step 2. Identify the technically feasible control options. 

The only technically feasible control option for this mechanical draft cooling tower is the use of high 

efficiency drift eliminators. 

9.6 Step 3. Rank the technically feasible control options. 

The only technically feasible control option for this mechanical draft cooling tower is the use of high 

efficiency drift eliminators. Therefore, high efficiency drift eliminators are the top ranked control option. 

The highest level of control commercially available is 0.0005%. 
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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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9.7 Step 4. Evaluate the most effective controls. 

The only feasible control technology for this mechanical draft cooling tower is high efficiency drift 

eliminators. From Table 9-3, the required drift loss control requirements for permits issued in 2007 

ranged from 0.0005% to 0.002%. The highest level of control commercially available is 0.0005%. 

TABLE 9-3. Cooling tower BACT requirements for recently permitted power plants. 

Facility Capacity, 

MW Date State Drift Loss Required 

Consumers Energy Karn Weadock 930 December, 2009 MI 0.0005% 

AEP John W. Turk, Jr. Power Plant 600 November, 2008 AR 0.0005% 

American Municipal Power 550 February, 2008 OH 0.00086% 

Santee Cooper - Pee Dee Station 660 December-07 SC 0.0005% 

Nelson Dewey Unit 3 330 (draft permit) WI 0.0005% 

Seminole Electric - Palatka Unit 3 750 August-07 FL 0.0005% 

Deseret Power Coop - Bonanza 110 August-07 UT 0.001% 

LS Power - Longleaf Energy Center 600 May-07 GA 0.001% 

Southern Montana Electric-Highwood 250 May-07 MT 0.002% 

Wisconsin Public Service – Weston 4 400 March-07 WI 0.0005% 

Western Farmers Electric - Hugo 2 750 February-07 OK 0.0005% 

Thoroughbred Generating Station 750 April-06 KY 0.002% 

Western Green Brier, LLC 85 April-06 WV 0.0005% 

Louisville Gas & Electric - Trimble 2 750 January-06 KY 0.0005% 

Rocky Mountain Power - Hardin 116 January-06 MT 0.001% 

Prairie State Generating Co. 750 April-05 IL 0.0005% 

Longview Power, LLC 600 March-04 WV 0.002% 

9.8 Step 5. Propose BACT. 

Based on this analysis, We Energies has concluded that the use of high efficiency drift eliminators is the 

best available control technology (BACT) for the control of PM, PM10, and PM2.5 emissions from the 

mechanical draft cooling tower, Process P141. Based on this analysis, We Energies proposes the 

following limits as BACT for the control of PM, PM10, and PM2.5 emissions from the mechanical draft 

cooling tower, Process P141. 

(1) Particulate matter (PM), PM10, and PM2.5 emissions from the 

mechanical draft cooling tower, Process P141, shall be controlled using 

high efficiency drift eliminators as the best available control 

technology. 

(2) The cooling tower drift eliminators shall be designed for a drift loss of 

no more than 0.0005% of the total circulating water flow. 

 
We Energies - Air Pollution Control Construction Permit Application for a 

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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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Chapter 10. Control Technology Review for 

Process P151: Emergency Feed Water Pump. 

As part of this Project, We Energies is proposing to install a new diesel (compression ignition) engine 

driven feed water pump. The new diesel (compression ignition or CI) engine driven feed water pump will 

be an emergency diesel engine with 6 cylinders and a total displacement of 8.1 liters, or 1.35 liters per 

cylinder. This engine will be rated at 400 horsepower, and will be subject to the Standards of 

Performance for Stationary Compression Ignition Internal Combustion Engines, 40 CFR Part 60, Subpart 

IIII. There are two possible applicable standards for this new diesel engine in 40 CFR § 60.4205 

depending on whether or not the engine is considered a fire pump: 

§ 60.4205 What emission standards must meet for 

emergency engines if I am an owner or operator of a 

stationary CI internal combustion engine? 

 (b) Owners and operators of 2007 model year and later 

emergency stationary CI ICE with a displacement of less than 

30 liters per cylinder that are not fire pump engines must 

comply with the emission standards for new nonroad CI 

engines in § 60.4202, for all pollutants, for the same model 

year and maximum engine power for their 2007 model year 

and later emergency stationary CI ICE. 

(c) Owners and operators of fire pump engines with a 

displacement of less than 30 liters per cylinder must comply 

with the emission standards in table 4 to this 

subpart, for all pollutants. 

The applicable standards for new nonroad CI engines in § 60.4202(a)(2) states that or engines with a 

maximum engine power greater than or equal to 50 HP, the engine must meet the certification emission 

standards for new nonroad CI engines for the same model year and maximum engine power in 40 CFR 

89.112 and 40 CFR 89.113 for all pollutants beginning in model year 2007. The applicable emission 

standards in 40 CFR 89.112 for Tier 3 engines with Model 2006 and later include: 

NOx + NMHC ...................... 3.0 g/hp-hr 

CO....................................... 2.61 g/hp-hr 

PM....................................... 0.15 g/hp-hr 

The requirements in 40 CFR Part 60, Subpart IIII, Table 4 include the following for model year 2009 and 

later stationary fire pump engines with maximum engine power between 300 and 600 horsepower: 

NOx + NMHC ...................... 3.0 g/hp-hr 

CO...................................................... n/a 

PM....................................... 0.15 g/hp-hr 
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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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TABLE 10-1. Potential emissions for the diesel engine driven feed water pump based on limiting 

operation to 100 hours per year. 

Emission 

Factor 

Engine 

Output Potential to Emit Pollutant 

g/hp-hr hp lb/hr tons/year 

Carbon Monoxide CO 2.61 400 2.30 0.11

Nitrogen Oxides NOx 3.00 400 2.64 0.13

Particulate Matter PM/PM10 0.15 400 0.132 0.0066

Particulate Matter PM2.5 0.12 400 0.106 0.0053

Sulfur Dioxide SO2 0.0057 400 0.0050 0.0003

Volatile Organic Compounds VOC 3.00 400 2.64 0.13

Lead Pb 0.000034 400 0.000030 0.000002

Mercury Hg 0.000011 400 0.000010 0.000001

Fluorides HF 0.0010 400 0.00090 0.000045

Sulfuric Acid Mist H2SO4 0.00057 400 0.00050 0.000025

 

Footnotes 

1. NOx, PM, and PM10, emission factors are the NSPS standards in 40 CFR Part 60, Subpart IIII, Table 4 

for model year 2009 and later stationary fire pump engines between 175 and 300 horsepower. 

2. SO2 emissions are based on 0.0015% sulfur fuel oil and a maximum oil consumption of 15.0 gph: 

Emissions = (0.0015 lb S/100 lb oil)x(2.0 lb SO2/lb S)x(15 gal oil/hr)x(7.0 lb oil/gal) 

Emissions = 0.0032 lb/hr 

3. Lead and mercury emissions are based on the emission factors for distillate oil combustion from the 

U.S. EPA's Compilation of Air Pollutant Emission Factors, AP-42, Table 1.3-10. For example, the lead 

emission factor is 9 pounds of lead per 1012 Btu of fuel oil: 

Emissions = (9.0 x 10-12 lb Pb/Btu) x (15 gal/hr) x (140,000 Btu/gal) = 0.000019 lb/hr 

4. Fluoride emissions are based on the emission factor for No. 6 oil combustion from the U.S. EPA's AP42, Table 1.3-11. The fluoride emission factor is 0.0373 lb per 1,000 gallons of oil: 

Emissions = (0.0373 lb F/1,000 gallons oil) x (15 gal/hr) = 0.00056 lb/hr 

6. Sulfuric acid emissions are estimated at 10% of the total sulfur dioxide emissions. 
We Energies - Air Pollution Control Construction Permit Application for a 

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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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10.1 Carbon Monoxide (CO) Control Technology Review. 

10.1.1 Step 1. Identify All Available Control Technologies. 

Available controls for CO emissions from diesel engines include good combustion practices based on 

engine design, diesel oxidation catalysts (DOC), and catalytically coated diesel particulate filters (DPF). 

10.1.2 Step 2. Eliminate Technically Infeasible Options. 

Good combustion practices, DOCs, and DPFs are technically feasible control options. However, there are 

potential reliability concerns with respect to the use of DOCs and DPFs on emergency engines. These 

filters can build up soot, causing high engine back pressure which may prevent the engine from starting. 

10.1.3 Step 3. Rank the Technically Feasible Control Technologies. 

DOCs and DPFs are post combustion controls and would be used in combination with good combustion 

practices or engine design. Both DOCs and DPFs are expected to achieve a 75% reduction in CO 

emissions. Based on the operational limit of 200 hours per year, and the an emission rate of 2.61 g/hp-hr, 

the diesel engine design would have CO emissions of 0.14 ton per year. The use of a DOC or DPF 

system is expected to reduce CO emissions by 75% and 0.11 ton/yr, to 0.04 ton/yr. 

10.1.4 Step 4. Evaluate the Most Effective Controls. 

A DOC for this engine is expected to cost about $5,000 per engine; a DPF is expected to cost about 

$10,000 per engine. The cost effectiveness of the DOC and DPF would be approximately $35,000 - 

$70,000 per ton of CO controlled, based on first year costs. For a service life of 5 years and an interest 

rate of 7%, the cost effectiveness would be approximately $8,600 - $17,000 per ton of CO reduced. 

These are very high costs, indicating that the use of diesel particulate filters and oxidation catalysts on this 

limited use diesel feed water pump is not an economically feasible control technology. 

10.1.5 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies proposes to utilize a diesel feed water pump which complies with the 

applicable New Source Performance Standards in 40 CFR § 60.4205, Table 4, combined with limited 

hours of operation, and the use of ultra low sulfur diesel fuel as the best available control technology 

(BACT) for the control of CO emissions. We Energies proposes the following limits: 

 (1) CO emissions may not exceed 2.61 grams per horsepower hour. 

(2) The sulfur content of the distillate fuel oil may not exceed 0.0015%. 

(3) The diesel engine feed water pump may not be operated more than 

200 hours in any consecutive 12-month period. 
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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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10.2 Nitrogen Oxides (NOx) Control Technology Review. 

10.2.1 Step 1. Identify All Available Control Technologies. 

Available controls for NOx emissions from diesel engines include good combustion practices based on 

engine design, and selective catalytic reduction (SCR). 

10.2.2 Step 2. Eliminate Technically Infeasible Options. 

Good combustion practices based on engine design is technically feasible. While SCR is available for 

diesel engines, we are not aware of SCR systems applied to emergency diesel engines. SCR systems 

cannot operate until the SCR catalyst is sufficiently preheated to achieve NOx reduction. Because 

emergency diesel engines typically operate for short periods of time, SCR is not an effective control 

option. Therefore, SCR is not a technically feasible control option for this engine. 

10.2.3 Step 3. Rank the Technically Feasible Control Technologies. 

The only feasible control option is good combustion practices based on the use of a diesel engine which 

complies with the applicable New Source Performance Standards in 40 CFR § 60.4205, Table 4. The 

engine design would have potential NOx emissions of 3.0 grams per horsepower hour and 0.17 ton per 

year. 

10.2.4 Step 4. Evaluate the Most Effective Controls. 

Because the only feasible control option is good combustion practices based on engine design, no 

evaluation is necessary. 

10.2.5 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies proposes to utilize a diesel feed water pump which complies with 

the applicable New Source Performance Standards in 40 CFR § 60.4205, Table 4, combined with limited 

hours of operation, and the use of ultra low sulfur diesel fuel as the best available control technology 

(BACT) for the control of NOx emissions. We Energies proposes the following limits: 

(1) NOx emissions may not exceed 3.0 grams per horsepower hour. 

(2) The diesel engine feed water pump may not be operated more than 

200 hours in any consecutive 12-month period. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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10.3 PM, PM10, and PM2.5 Control Technology Review. 

10.3.1 Step 1. Identify All Available Control Technologies. 

Available controls for PM, PM10, and PM2.5 emissions from diesel engine includes good combustion 

practices (GCP), diesel particulate filters (DPF), and diesel oxidation catalysts (DOC). 

10.3.2 Step 2. Eliminate Technically Infeasible Options. 

Good combustion practices, DOCs, and DPFs are technically feasible control options. However, there are 

potential reliability concerns with respect to the use of DOCs and DPFs on emergency engines. These 

filters can build up soot, causing high engine back pressure which may prevent the engine from starting. 

10.3.3 Step 3. Rank the Technically Feasible Control Technologies. 

DOCs and DPFs are post combustion controls and would be used in combination with good combustion 

practices or engine design. Both DOCs and DPFs are expected to achieve a 90% reduction in PM 

emissions. Based on the operational limit of 200 hours per year, the engine design would have PM, PM10, 

and PM2.5 emissions of 0.0083, 0.0083, and 0.0067 tons per year, respectively. The use of a DOC or DPF 

system is expected to reduce emissions by 90%, to 0.0008, 0.0008, and 0.0007 tons per year, respectively. 

10.3.4 Step 4. Evaluate the Most Effective Controls. 

A DOC for this engine is expected to cost about $5,000 per engine; a DPF is expected to cost about 

$10,000 per engine. The cost effectiveness of the DOC and DPF for the control of PM emissions would 

be in excess of $1,000,000 per ton of PM controlled, based on first year costs. For a service life of 5 

years and an interest rate of 7%, the cost effectiveness would be approximately $150,000 - $300,000 per 

ton of PM reduced. These are very high costs, indicating that the use of diesel particulate filters and 

oxidation catalysts on this limited use diesel generator is not an economically feasible control technology 

for the control of PM, PM10, and PM2.5 emissions from this emergency diesel feed water pump. 

10.3.5 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies proposes to utilize a diesel feed water pump which complies with the 

applicable New Source Performance Standards in 40 CFR § 60.4205, Table 4, combined with limited 

hours of operation, and the use of ultra low sulfur diesel fuel as the best available control technology 

(BACT) for the control of PM, PM10, and PM2.5 emissions. We Energies proposes the following limits: 

 (1) PM, PM10, and PM2.5 emissions may not exceed 0.15 grams per 

horsepower hour. 

(2) The sulfur content of the distillate fuel oil may not exceed 0.0015%. 

(3) The diesel engine feed water pump may not be operated more than 

200 hours in any consecutive 12-month period. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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10.4 Sulfur Dioxide (SO2) Control Technology Review. 

10.4.1 Step 1. Identify All Available Control Technologies. 

Sulfur dioxide (SO2) emissions result from the oxidation of sulfur in the fuel being combusted. The only 

available SO2 control technology for this emergency diesel engine is the use of low sulfur fuels. Other 

technologies used for other combustion sources include flue gas desulfurization (FGD) systems. 

10.4.2 Step 2. Eliminate Technically Infeasible Options. 

The only commercially available SO2 control technology for diesel engines is the use of low sulfur fuels. 

Because FGD systems are not commercially available for diesel engines, FGD is not a technically feasible 

control technology for this diesel engine. 

10.4.3 Step 3. Rank the Technically Feasible Control Technologies. 

The only technically feasible SO2 control option is the use of low sulfur fuels. The lowest fuel oil sulfur 

content available is transportation grade diesel fuel oil which is currently 0.0015%, or 15 parts per 

million. The use of ultra-low sulfur diesel fuel oil will limit potential SO2 emissions to 0.0003 ton per 

year. 

10.4.4 Step 4. Evaluate the Most Effective Controls. 

Because the only technically feasible SO2 control option is the use of low sulfur fuels, no evaluation is 

necessary. 

10.4.5 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies proposes to utilize a diesel feed water pump which complies with the 

applicable New Source Performance Standards in 40 CFR § 60.4205, Table 4, combined with limited 

hours of operation, and the use of ultra low sulfur diesel fuel as the best available control technology 

(BACT) for the control of SO2 emissions. We Energies proposes the following limits: 

(1) The sulfur content of the distillate fuel oil may not exceed 0.0015%. 

(2) The diesel engine feed water pump may not be operated more than 

200 hours in any consecutive 12-month period. 
We Energies - Air Pollution Control Construction Permit Application for a 

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Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

- 41 -

10.5 Volatile Organic Compound (VOC) Control Technology Review. 

10.5.1 Step 1. Identify All Available Control Technologies. 

Available controls for VOC emissions from diesel engines include good combustion practices based on 

engine design, diesel oxidation catalysts (DOC), and catalytically coated diesel particulate filters (DPF). 

10.5.2 Step 2. Eliminate Technically Infeasible Options. 

Good combustion practices, DOCs, and DPFs are technically feasible control options. However, there are 

potential reliability concerns with respect to the use of DOCs and DPFs on emergency engines. These 

filters can build up soot, causing high engine back pressure which may prevent the engine from starting. 

10.5.3 Step 3. Rank the Technically Feasible Control Technologies. 

DOCs and DPFs are post combustion controls and would be used in combination with good combustion 

practices or engine design. Both DOCs and DPFs are expected to achieve a 50% reduction in VOC 

emissions. Based on the operational limit of 200 hours per year, the diesel engine design would have 

VOC emissions of 0.17 ton per year. The use of a DOC or DPF system is expected to reduce VOC 

emissions by 50% and 0.09 ton/yr, to 0.08 ton/yr. 

10.5.4 Step 4. Evaluate the Most Effective Controls. 

A DOC for this engine is expected to cost about $5,000 per engine; a DPF is expected to cost about 

$10,000 per engine. The cost effectiveness of the DOC and DPF would be approximately $56,000 - 

$110,000 per ton of VOC controlled, based on first year costs. For a service life of 5 years and an interest 

rate of 7%, the cost effectiveness would be approximately $13,000 - $27,000 per ton of VOC reduced. 

These are very high costs, indicating that the use of diesel particulate filters and oxidation catalysts on this 

limited use diesel generator is not an economically feasible control technology. 

10.5.5 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies proposes to utilize a diesel feed water pump which complies with the 

applicable New Source Performance Standards in 40 CFR § 60.4205, Table 4, combined with limited 

hours of operation, and the use of ultra low sulfur diesel fuel as the best available control technology 

(BACT) for the control of VOC emissions. We Energies proposes the following limits: 

(1) VOC emissions may not exceed 3.0 grams per horsepower hour. 

(2) The sulfur content of the distillate fuel oil may not exceed 0.0015%. 

(3) The diesel engine feed water pump may not be operated more than 

200 hours in any consecutive 12-month period. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

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10.6 Fluorides (as HF) Control Technology Review. 

Fluorine (F) is a trace element in diesel fuel. When diesel fuel is burned, fluorine may be emitted as 

hydrogen fluoride or hydrofluoric acid (HF), or as fluorine compounds, such as sodium fluoride (NaF) 

and calcium fluoride (CaF2). 

10.6.1 Step 1. Identify All Available Control Technologies. 

The only commercially available control technology for fluoride emissions from diesel engines is the use 

of diesel fuel which has very low fluorine concentrations. Other potential controls include diesel 

particulate filters (DPF), and flue gas desulfurization systems for the control of hydrogen fluoride (HF). 

10.6.2 Step 2. Eliminate Technically Infeasible Options. 

The use of diesel fuel which has very low quantities of fluorine is technically feasible. While DPFs are 

technically feasible, we are not aware of data indicating their effectiveness in controlling fluoride 

emissions. Therefore, DPFs are not considered a technically feasible control option for fluoride emissions 

from this engine. Because FGD systems are not commercially available for diesel engines, FGD is not a 

technically feasible control technology for this engine. 

10.6.3 Step 3. Rank the Technically Feasible Control Technologies. 

The only technically feasible fluorides control technology for this diesel engine is the use of ultra low 

sulfur fuel oil. 

10.6.4 Step 4. Evaluate the Most Effective Controls. 

Because the only technically feasible fluorides control technology for this diesel engine is the use of ultra 

low sulfur fuel oil, further evaluation is unnecessary. The use of ultra-low sulfur fuel oil will limit 

fluoride emissions to 0.000056 ton (0.1 pounds) per year. 

10.6.5 Step 5. Proposed BACT Requirements. 

Based on this analysis, We Energies proposes to utilize a diesel feed water pump which complies with the 

applicable New Source Performance Standards in 40 CFR § 60.4205, Table 4, combined with limited 

hours of operation, and the use of ultra low sulfur diesel fuel as the best available control technology 

(BACT) for the control of HF emissions. We Energies proposes the following limits: 

(1) The sulfur content of the distillate fuel oil may not exceed 0.0015%. 

(2) The diesel engine feed water pump may not be operated more than 

200 hours in any consecutive 12-month period. 
Prevention of Significant Deterioration 

Air Pollution Control Construction Permit Application 

Appendix D. 

Case-by-Case Maximum Achievable Control 

Technology (MACT) Analysis for the Biomass-Fired 

Boiler, and Natural Gas-Fired Boiler under Section 

112(g) of the Clean Air Act. 

50 MW Biomass-Fueled Cogeneration Facility to be Located 

at the Domtar – Rothschild Mill.

March, 2010 

Prepared for: 

We Energies 

231 W. Michigan St. 

Milwaukee, WI 53203 

Prepared By: 

 

RTP ENVIRONMENTAL ASSOCIATES INC.® 

903 Superior Avenue, Suite 6 

Tomah, WI 54660 

Air Pollution Control Construction Permit Application 

We Energies – 50 MW Biomass-Fired Cogeneration Facility RTP Environmental Associates, Inc. 

Appendix D: Case-by-Case MACT Analysis Under Section 112(g) of the CAA March, 2010

- i - 

Executive Summary 

Section 112 of the 1990 Clean Air Act Amendments requires the U.S. EPA to develop standards to 

control emissions from major sources of hazardous air pollutants (HAPs) in source categories on the 

112(c) list to levels consistent with the lowest emitting facilities in similar source categories. These 

National Emissions Standards for Hazardous Air Pollutants (NESHAPs) require the application of the 

maximum achievable control technology (MACT). Section 112(g)(2) of the CAA requires a “case-bycase” MACT determination for new major sources in source categories on the 112(c) list where EPA has 

not established a NESHAP. Because the U.S. EPA has not established MACT standards for new 

industrial boilers, We Energies has prepared this case-by-case MACT analysis for the biomass-fueled and 

natural gas-fueled boilers. 

HAPs emitted from biomass-fueled boilers may be classified in four categories: 1) Inorganic, solid phase 

HAPs, 2) Inorganic, acid gas HAPs including hydrogen chloride (HCl) and hydrogen fluoride (HF), 3) 

Organic HAPs, and 4) Mercury. The proposed emission standards representing the case-by-case MACT 

for these HAP categories are summarized in Table ES-1. The limits in Table ES-1 reflect the combustion 

of biomass fuels and natural gas in an advanced circulating fluidized bed boiler, in combination with a 

fabric filter baghouse. These control technologies are similar to those used on the best performing similar 

units reviewed in this analysis. 

TABLE ES-1. Proposed emission standards representing MACT. 

HAP CATEGORY PROPOSED EMISSION LIMIT 

Inorganic, solid 

phase HAPs 

Inorganic, solid phase HAP emissions from the circulating fluidized bed 

boiler shall be controlled using a fabric filter baghouse as MACT. 

The proposed PM, PM10, and PM2.5 BACT emission limits represent MACT. 

Organic HAPs Organic HAP emissions from the biomass fuels-fired circulating fluidized bed 

boiler shall be controlled using good combustion practices as MACT. 

The proposed CO and VOC BACT emission limits represent MACT. 

Hydrogen Chloride 

(HCl) 

Hydrogen chloride (HCl) emissions from the circulating fluidized bed boiler 

shall be controlled using biomass fuels in combination with a fabric filter 

baghouse as MACT. 

Hydrogen chloride (HCl) emissions may not exceed 0.018 lb/mmBtu. 

Hydrogen Fluoride 

(HF) 

Hydrogen fluoride (HF) emissions from the circulating fluidized bed boiler 

shall be controlled using biomass fuels in combination with a fabric filter 

baghouse as MACT. 

Mercury Mercury emissions from the biomass fuels-fired circulating fluidized bed 

boiler shall be controlled using biomass fuels in combination with a fabric 

filter baghouse as MACT. 

Mercury emissions may not exceed 2.9 pounds per trillion Btu. 
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Inorganic, Solid Phase HAPs. 

Inorganic, solid phase HAPs are controlled by particulate matter (PM) control systems. Based on this 

case-by-case MACT analysis, We Energies has concluded that the proposed fabric filter baghouse 

represents the best available control technology (BACT) for PM, PM10, and PM2.5 emissions, and also 

represents MACT for this HAP category. The best performing similar units employ this technology. 

Organic HAPs. 

Organic HAPs are emitted from biomass combustion as a result of incomplete combustion. The only 

technically feasible control method used to control organic HAP emissions from similar circulating 

fluidized bed boilers is the use of good combustion practices to limit organic HAP formation. Good 

combustion practices can be monitored using carbon monoxide (CO) as a measure of combustion 

efficiency, and the U.S. EPA has concluded that the monitoring of CO emissions can be used as a 

surrogate for the control of organic HAPs. Based on this case-by-case MACT analysis, We Energies has 

concluded that the proposed BACT CO emission limits also represent the MACT for organic HAPs. The 

best performing similar units employ this technology. 

Inorganic, Gas Phase HAPs. 

Inorganic, gas phase HAPs include hydrogen chloride and hydrogen fluoride. These acid gases are 

formed during combustion from chlorine and fluorine in biomass fuels. These gases are effectively 

controlled by the highly alkaline ash from biomass combustion in combination with a fabric filter 

baghouse. Based on this analysis, We Energies has concluded that using low chlorine containing biomass 

fuels in combination with a fabric filter baghouse represents MACT for HCl emissions. The best 

performing similar units also employ similar controls. We Energies is also proposing an HCl limit of 

0.018 lb/mmBtu. 

Based on the available information and permits reviewed, no biomass-fueled boilers were identified with 

a specific HF emission limit. Based on this case-by-case MACT analysis, We Energies has concluded 

that using low fluorine containing biomass fuels in combination with a fabric filter baghouse represents 

MACT for HF emissions. The best performing similar units also employ similar controls. 

In the beyond the floor MACT analysis, flue gas desulfurization (FGD) systems, including dry sorbent 

injection, were evaluated as a potential HCl and HF control technologies. However, the continuous 

reduction of HCl emissions from biomass combustion by the use of FGD systems and sorbent injection is 

not demonstrated in practice. Because biomass combustion has high levels of alkali substances in the ash, 

the additional injection of sorbent may not achieve emission reductions. Even these controls could further 

reduce HCl emissions, the costs of control would be extremely high, with an average cost effectiveness 

for the dry sorbent injection system of $40,000 per ton of HCl controlled. Finally, the use of sorbent 

injection may adversely impact the reuse of this ash, which would have substantial environmental impacts 

and additional economic impacts. 
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Mercury. 

Mercury (Hg) is a trace element in biomass. When biomass is burned, mercury exits the boiler at 

extremely low concentrations, on the order of parts per billion. The proposed fuels for this boiler, 

including natural gas and biomass fuels, have inherently low mercury concentrations. Based the upon 

available information, the only mercury control used on similar, biomass-fueled boilers is the use of low 

mercury containing biomass fuels combined with the use of PM control systems. Permitted emission 

limits for similar biomass-fueled boilers range from 2.27 to 25 pounds per trillion Btu of heat input. 

Based on the available data, we concluded that the MACT floor for mercury emissions from this biomassfueled boiler is the use of biomass fuels and a fabric filter baghouse. The resulting MACT floor mercury 

emission rate is 2.9 lb/trillion Btu of heat input. This emission rate represents a reasonable estimate of the 

performance of the “best controlled similar unit” under the worst reasonably foreseeable circumstances. 

In making a case-by-case MACT determination, the permitting authority is expected to look beyond the 

MACT floor, to evaluate whether a greater degree of reduction in emissions is achievable, taking into 

consideration the cost of achieving such emission reductions, and any non-air quality health and 

environmental impacts and energy requirements. In the beyond the floor mercury MACT analysis, we 

identified the use of activated carbon injection as a feasible mercury control. While we are not aware of 

the use of activated carbon injection on any biomass-fueled boiler, based on the current coal-fired utility 

boiler and municipal waste combustor experience, activated carbon injection is a technically feasible 

mercury control alternative for this biomass-fueled boiler. However, because the concentration of 

mercury in biomass is expected to be much lower than in coal or municipal solid waste, the use of 

activated carbon injection will have limited ability to control mercury. Based on this review and the fact 

that activated carbon injection has not been demonstrated on similar biomass-fueled boilers, we have 

concluded that the level of mercury emissions with activated carbon injection will be the same as the level 

of control when firing low mercury containing biomass fuels and the use of a fabric filter baghouse. 

Even if activated carbon injection could reduce mercury emissions, the cost effectiveness of the activated 

carbon injection system, based only on the capital investment of the sorbent injection system, would be at 

least $21,000 per pound of mercury controlled. Further, the use of activated carbon injection may also 

adversely impact the potential reuse of the boiler flyash which could have substantial environmental 

impacts and additional economic costs. Based on the potential impact to ash disposal, the use of activated 

carbon injection could have an economic cost of $85,000 per pound of mercury controlled. This is an 

extremely high cost, especially since there is no evidence that this level of control could actually be 

achieved in practice. 

Based on this analysis, We Energies has concluded that the case-by-case MACT for the control of 

mercury emissions from this biomass-fueled boiler is the use of low mercury containing biomass fuels, 

combined with the use of a fabric filter baghouse. Based on this analysis, We Energies proposes a caseby-case MACT emission limit for mercury emissions from this boiler of 2.9 pounds per trillion Btu of 

heat input. 

 
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Natural Gas-Fueled Boiler. 

The proposed natural gas-fueled boiler is also a potential source of HAP emissions. However, because 

this is a natural gas-fueled boiler, total potential HAP emissions for this boiler will be less than 2,000 

pounds per year. As a result, this boiler will be a minor source of HAP emissions and the Section 112(g) 

case-by-case MACT requirements are not applicable. 61 Fed. Reg. 68,384, 68,388 (December 27, 1996; 

sources that take enforceable limits resulting in emissions below the major source threshold do not meet 

the definition of “construct a major source” under Section 112(g)). 

Although We Energies believes Section 112(g) of the CAA is not applicable to this natural gas-fueled 

boiler, a case-by-case MACT evaluation was preformed in the event that Section 112(g) is considered 

applicable. Table ES-2 is a summary of the proposed case-by-case MACT requirements for the control of 

HAP emissions from the natural gas-fueled boiler. These emission limits are based on the best 

performing similar units. To limit mercury emissions from similar sources, the U.S. EPA has restricted 

the allowable fuels to only natural gas – a low mercury containing fuel. The use of only natural gas will 

limit potential mercury emissions from this boiler to 0.25 pounds per year. 

TABLE ES-2. Proposed emission limits representing MACT for the natural gas-fueled boiler. 

HAP CATEGORY PROPOSED EMISSION LIMIT 

Inorganic, solid Proposed PM and PM10 BACT emission limits represent MACT. 

Organic Proposed CO and VOC BACT emission limits represent MACT. 

Inorganic, acid gas HCl emissions shall be controlled by firing only natural gas. 

HF emissions shall be controlled by firing only natural gas. 

Mercury Mercury emissions shall be controlled by firing only natural gas. 
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Table of Contents 

 Chapter 1. Introduction. ........................................................................................8

1.1 Application Requirements for a Case-by-Case MACT Determination. .......................................... 8

Chapter 2. Case-by-Case MACT Analysis Methodology. ................................10

2.1 Maximum Achievable Control Technology Definition. ................................................................ 10

Chapter 3. Biomass-Fueled Boiler Case-by-Case MACT Analysis. ................13

3.1 Hazardous Air Pollutant Emissions. .............................................................................................. 13

Chapter 4. Inorganic Solid Phase Hazardous Air Pollutants...........................15

4.1 U.S. EPA Proposed MACT Standards........................................................................................... 15

4.2 MACT Floor Analysis for Inorganic Solid Phase HAPs. .............................................................. 15

4.3 Beyond the Floor Inorganic, Solid Phase HAP MACT Analysis. ................................................. 17

4.4 Proposed Case-by-Case MACT Limit for Inorganic, Solid Phase HAPs...................................... 18

Chapter 5. Inorganic, Acid Gas HAPs................................................................19

5.1 U.S. EPA Proposed MACT Standards........................................................................................... 19

5.2 MACT Floor Analysis for Hydrogen Chloride (HCl). .................................................................. 19

5.2.1 HCl Fuel Analysis and Emission Data.............................................................................. 20

5.3 Beyond the Floor MACT Analysis for Hydrogen Chloride (HCl). ............................................... 23

5.4 Proposed Case-by-Case MACT for Hydrogen Chloride (HCl). .................................................... 24

5.5 MACT Floor Analysis for Hydrogen Fluoride (HF). .................................................................... 25

5.5.1 HF Fuel Analysis and Emission Data. .............................................................................. 25

5.6 Beyond the Floor MACT Analysis for Hydrogen Fluoride (HF). ................................................. 27

5.7 Proposed Case-by-Case MACT for Hydrogen Fluoride (HF). ...................................................... 28

Chapter 6. Organic HAPs....................................................................................29

6.1 U.S. EPA Proposed MACT Standards........................................................................................... 29

6.2 MACT Floor Analysis for Organic HAPs. .................................................................................... 29

6.3 Beyond the Floor Organic HAP MACT Analysis. ........................................................................ 31

6.4 Proposed Case-by-Case MACT Limit for Organic HAPs. ............................................................ 31

Chapter 7. Mercury..............................................................................................32
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7.1 U.S. EPA Proposed MACT Standards........................................................................................... 32

7.2 State of Wisconsin Mercury Rule.................................................................................................. 32

7.3 MACT Floor Analysis for Mercury............................................................................................... 32

7.3.1 Mercury Concentrations in Biomass................................................................................. 33

7.4 Beyond-the-Floor Analysis for Mercury........................................................................................ 35

7.4.1 Potential Mercury Control Technologies.......................................................................... 35

7.4.2 Technically Feasible Mercury Control Technologies....................................................... 36

7.4.3 Rank of the Technically Feasible Control Technologies. ................................................. 40

7.4.4 Evaluate the Most Effective Controls. .............................................................................. 41

7.4.5 Beyond the Floor MACT Mercury Conclusion. ............................................................... 41

7.5 Proposed Case-by-Case MACT Limit for Mercury....................................................................... 42

Chapter 8. Natural Gas-Fueled Boiler Case-by-Case MACT Analysis. .........43

8.1 Hazardous Air Pollutant Emissions. .............................................................................................. 43

8.2 U.S. EPA Proposed MACT Standards........................................................................................... 43

8.3 Inorganic Solid Phase HAPs.......................................................................................................... 45

8.3.1 Beyond the Floor Inorganic Solid Phase HAP MACT Analysis. ..................................... 45

8.3.2 Proposed Case-by-Case MACT for Inorganic, Solid Phase HAPs................................... 45

8.4 Inorganic Acid Gas HAPs.............................................................................................................. 45

8.4.1 Beyond the Floor HCl MACT Analysis. .......................................................................... 46

8.4.2 Proposed Case-by-Case MACT HCl Emission Limit....................................................... 46

8.4.3 Hydrogen Fluoride............................................................................................................ 46

8.4.4 Beyond the Floor HF MACT Analysis............................................................................. 46

8.4.5 Proposed Case-by-Case MACT HF Emission Limit. ....................................................... 46

8.5 Organic HAPs. ............................................................................................................................... 46

8.5.1 Beyond the Floor Organic HAP MACT Analysis. ........................................................... 47

8.5.2 Proposed Case-by-Case MACT Limit for Organic HAPs. ............................................... 48

8.6 Mercury .................................................................................................................................. 48

8.6.1 Beyond the Floor Mercury MACT Analysis. ................................................................... 48

8.6.2 Proposed Case-by-Case MACT Mercury Emission Limit. .............................................. 48
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Tables 

TABLE 1. Summary of HAP Emissions from the biomass-fired boiler by HAP Category. 

TABLE 2. Biomass-fueled boiler particulate matter and PM10 BACT emission limits. 

TABLE 3. Biomass-fueled boiler HCl emission limits representing MACT. 

TABLE 4. Wood fuels analyses data and uncontrolled hydrogen chloride (HCl) emission rate. 

TABLE 5. Carbon monoxide (CO) BACT emission limits for biomass fuel-fueled boilers. 

TABLE 6. Biomass-fueled boiler mercury emission limits representing MACT. 

TABLE 7. Short term activated carbon injection field test projects. Data from “Control of Mercury 

Emissions from Coal Fired Electric Utility Boilers: An Update”, Table 5. 

TABLE 8. Ranking of the technically feasible mercury control technologies. 

TABLE 9. Potential hazardous air pollutant emissions for the natural gas-fueled package boiler. 

Figures 

FIGURE 1. Hydrogen chloride (HCl) fuel sampling and analysis and emission test data for biomass 

combustion from the U.S. EPA’s industrial boiler ICR

FIGURE 2. Hydrogen fluoride (HF) fuel sampling and analysis and emission test data for biomass 

combustion from the U.S. EPA’s industrial boiler ICR

FIGURE 3. Mercury (Hg) fuel sampling and analysis and emission test data for biomass combustion 

from the U.S. EPA’s industrial boiler ICR

FIGURE 4. Depiction of the flue gas flow through the fabric filter baghouse filter cake showing the 

mechanism for particulate collection and mercury control

Attachments 

Attachment 1. Potential hazardous air pollutant emissions for the biomass-fired boiler B01 (2 pages). 

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Chapter 1. Introduction. 

We Energies’ proposed 50 MW Biomass-Fueled Cogeneration Facility will include a new combined heat 

and power steam generating unit that will use a subcritical pressure, advanced circulating fluidized bed 

boiler to generate steam to power a nominal 50 MW steam turbine generator1

 and to provide process 

steam to the Domtar facility. Depending on energy requirements, the boiler will operate at full load for 

the majority of its operating hours; the unit will also be capable of partial load operation. Associated 

equipment will include fuel and ash handling systems, cooling towers, one natural gas-fueled package 

boiler and a diesel feed water pump. Based on the control technology review or BACT analysis and 

proposed BACT requirements, this boiler will utilize a Selective Non-Catalytic Reduction system 

(SNCR) for the control of nitrogen oxides (NOx), a fabric filter baghouse for the control of particulate 

matter, and PM10, felted fabric media in the baghouse for the control of direct PM2.5, the use low sulfur 

containing fuels including biomass fuels and natural gas for sulfur dioxide (SO2) control, and the use low 

fluorine containing fuels including biomass fuels and natural gas for fluorides (as HF) control. 

This document is We Energies’ case-by-case maximum achievable control technology (MACT) § 112(g) 

analysis for this Project. 

1.1 Application Requirements for a Case-by-Case MACT 

Determination. 

The requirements for a case-by-case MACT analysis are described in 40 CFR § 63.43(e). Under this 

section, an application for a MACT determination shall specify a control technology selected by the 

owner or operator that, if properly operated and maintained, will meet the MACT emission limit or 

standard as determined according to the principles set forth in 40 CFR § 63.43(d). 

If the MACT determination concludes that a constructed major source would require additional control 

technology or a change in control technology, the application for a MACT determination must contain the 

following information, to the extent needed to determine MACT. Note that much of the required 

information is included in the air permit application and control technology review(s) for this project. The 

remaining information is included in this report. As a result, all of the required information is included in 

either the PSD application or in this analysis. 

 

1

 Actual net unit capacity will be determined during detailed design. Ambient conditions including air temperature, 

humidity, and water temperature will vary and impact plant operating capacity. Final design with specific 

equipment by manufacturer and the integration of this equipment, such as the boiler, turbine, generator, fans and air 

quality control systems will impact the final combined capabilities, auxiliary power requirements and resulting plant 

capacity. Daily operating conditions including fuel heat content, fuel moisture content, emissions control operations 

along with boiler and-or turbine fouling will also have impacts on capacity. 
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Application requirements for a Case-by-Case MACT determination as described in 40 CFR § 

63.43(e). 

(i) The name and address of the major source; Application 

(ii) A brief description of the major source and identification of any listed 

source category or categories in which it is included; 

Application 

(iii) The expected commencement date for the construction; Application 

(iv) The expected completion date for construction; Application 

(v) The anticipated date of start-up; Application 

(vi) The HAP(s) emitted by the source, and the estimated emission rate for 

each such HAP; 

Application and this 

MACT Analysis 

(vii) Any federally enforceable emission limitations applicable to the 

constructed major source; 

Application 

(viii) The maximum and expected utilization of the source, and the 

associated uncontrolled emission rates for that source; 

Application 

(ix) The controlled emissions for the source in tons/yr at expected and 

maximum utilization; 

Application and this 

MACT Analysis 

(x) A recommended emission limitation for the constructed or 

reconstructed major source consistent with the principles set forth in 

paragraph (d) of this section; 

This MACT Analysis 

(xi) The selected control technology to meet the recommended MACT 

emission limitation; 

This MACT Analysis 

(xii) Supporting documentation including identification of alternative 

control technologies considered by the applicant to meet the emission 

limitation; and 

This MACT Analysis 

(xiii) Any other relevant information required pursuant to subpart A. This MACT Analysis 
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Chapter 2. Case-by-Case MACT 

Analysis Methodology. 

2.1 Maximum Achievable Control Technology Definition. 

The definition of MACT for new sources is found in section 112(d)(2) and (3) of the Clean Air Act: 

(2) STANDARDS AND METHODS.—Emissions standards promulgated under this 

subsection and applicable to new or existing sources of hazardous air pollutants shall require 

the maximum degree of reduction in emissions of the hazardous air pollutants subject to this 

section (including a prohibition on such emissions, where achievable) that the Administrator, 

taking into consideration the cost of achieving such emission reduction, and any non-air quality 

health and environmental impacts and energy requirements, determines is achievable for new 

or existing sources in the category or subcategory to which such emission standard applies, 

through application of measures, processes, methods, systems or techniques including, but not 

limited to, measures which— 

(A) reduce the volume of, or eliminate emissions of, such pollutants through process changes, 

substitution of materials or other modifications, 

(B) enclose systems or processes to eliminate emissions, 

(C) collect, capture or treat such pollutants when released from a process, stack, storage or 

fugitive emissions point, 

(D) are design, equipment, work practice, or operational standards (including requirements for 

operator training or certification) as provided in subsection (h), or 

(E) are a combination of the above. 

None of the measures described in subparagraphs (A) through (D) shall, consistent with the 

provisions of section 114(c), in any way compromise any United States patent or United States 

trademark right, or any confidential business information, or any trade secret or any other 

intellectual property right. 

 (3) NEW AND EXISTING SOURCES.—The maximum degree of reduction in emissions that 

is deemed achievable for new sources in a category or subcategory shall not be less stringent 

than the emission control that is achieved in practice by the best controlled similar source, as 

determined by the Administrator. 

MACT is generally a two-step process: establishing the MACT floor (the emission limit achieved in 

practice by the best-controlled similar source) and then performing a beyond the floor evaluation (whether 

stricter controls are achievable in light of costs, non-air quality health and environmental impacts and 

energy requirements). MACT for new sources is defined in 40 CFR § 63.41 as: 
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Maximum achievable control technology (MACT) emission limitation for new sources means 

the emission limitation which is not less stringent that the emission limitation achieved in 

practice by the best controlled similar source, and which reflects the maximum degree of 

deduction in emissions that the permitting authority, taking into consideration the cost of 

achieving such emission reduction, and any non-air quality health and environmental 

impacts and energy requirements, determines is achievable by the constructed or 

reconstructed major source. 

The principles of case-by-case MACT have been codified in 40 CFR § 63.43(d): 

(d) Principles of MACT determinations. 

The following general principles shall govern preparation by the owner or operator of each 

permit application or other application requiring a case-by-case MACT determination 

concerning construction or reconstruction of a major source, and all subsequent review of 

and actions taken concerning such an application by the permitting authority: 

(1) The MACT emission limitation or MACT requirements recommended by the applicant 

and approved by the permitting authority shall not be less stringent than the emission control 

which is achieved in practice by the best controlled similar source, as determined by the 

permitting authority. 

(2) Based upon available information, as defined in this subpart, the MACT emission 

limitation and control technology (including any requirements under paragraph (d)(3) of this 

section) recommended by the applicant and approved by the permitting authority shall 

achieve the maximum degree of reduction in emissions of HAP which can be achieved by 

utilizing those control technologies that can be identified from the available information, 

taking into consideration the costs of achieving such emission reduction and any non-air 

quality health and environmental impacts and energy requirements associated with the 

emission reduction. 

(3) The applicant may recommend a specific design, equipment, work practice, or 

operational standard, or a combination thereof, and the permitting authority may approve 

such a standard if the permitting authority specifically determines that it is not feasible to 

prescribe or enforce an emission limitation under the criteria set forth in section 112(h)(2) of 

the Act. 

(4) If the Administrator has either proposed a relevant emission standard pursuant to section 

112(d) or section 112(h) of the Act or adopted a presumptive MACT determination for the 

source category which includes the constructed or reconstructed major source, then the 

MACT requirements applied to the constructed or reconstructed major source shall have 

considered those MACT emission limitations and requirements of the proposed standard or 

presumptive MACT determination. 

The guiding principle for new sources under section 112(d)(3) of the CAA and 40 CFR § 63.43(d)(1) is: 

“[t]he maximum degree of reduction in emissions that is deemed achievable for new sources in a category 

or subcategory shall not be less stringent than the emission control that is achieved in practice by the best 

controlled similar source.” When a standard must be achievable, it must be achievable under most adverse 

circumstances which can reasonably be expected to recur. Thus, the MACT standard should be set at a 
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level that is a reasonable estimate the performance of the best controlled similar unit under the worst 

reasonably foreseeable circumstances. 

The guiding principle for new sources under section 112(d)(3) of the CAA and 40 CFR § 63.43(d)(1) is: 

“[t]he maximum degree of reduction in emissions that is deemed achievable for new sources in a category 

or subcategory shall not be less stringent than the emission control that is achieved in practice by the best 

controlled similar source.” While this sentence is relatively straightforward, it can be difficult to follow in 

practice. The stumbling block for review agencies has often been the phrase, “achieved in practice”. How 

is “achieved in practice” determined? 

The D.C. Circuit Court has ruled that where the law requires a standard be achievable, “it must be 

achievable under most adverse circumstances which can reasonably be expected to recur.” With respect 

to implementing section 112(d)(3), the D.C. Court has ruled that EPA is justified in setting the standard at 

a level that is a reasonable estimate of the performance of the “best controlled similar unit” under the 

worst reasonably foreseeable circumstances. 

Therefore, this case-by-case MACT analysis is based on first identifying the "best performing" similar 

unit. Then, to account for variability, this MACT analysis includes an objective, engineering analysis to 

reasonably estimate the performance of the best controlled similar unit under the worst reasonably 

foreseeable circumstances. 

This Project meets the definition of “construct a major source” pursuant to 40 CFR § 63.41(2). It is a new 

process or production unit that will be constructed at an existing facility and will be a major source of 

HAP emissions in and of itself. Section 112(g) of the CAA applies to the proposed boilers, but not to the 

existing Domtar Mill. See 61 Fed. Reg. 68,384, 68,385 and 68,390 (December 27, 1996) (A new process 

or production unit at an existing major source must itself be inherently emitting- the entire plant site is not 

the process or production unit) subject to the 112(g) review. See also EPA document dated March 13, 

1997, Questions and Answers on 112(g) Final Rule, Q9, A9 (when a new major process unit is added to 

an existing facility, only a new major process unit is subject to review under 112(g), not the entire 

facility.) Based upon the definition of “construct a major source” within 40 CFR § 63.41 the biomassfueled CFB boiler should be the exclusive process or production unit subject to Section 112(g), since it is 

the only process or production unit associated with this Project that would itself be a major source of 

HAPs. 

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Chapter 3. Biomass-Fueled Boiler 

Case-by-Case MACT Analysis. 

3.1 Hazardous Air Pollutant Emissions. 

Hazardous air pollutants (HAP) emitted from biomass-fueled boilers may be classified in 4 categories: 

CATEGORY EXAMPLES 

1. Inorganic, solid phase HAPs. Arsenic, Cadmium, Chromium 

2. Inorganic, acid gas HAPs. Hydrochloric acid and Hydrofluoric acid 

3.Organic HAPs. Formaldehyde, 2,3,7,8 TCDD (dioxin) 

4.Mercury 

Emission rates are influenced by the chemical characteristics of the fuels, a complex interaction between 

the various constituents in the fuels, the effectiveness of the combustion process itself, and the emission 

control technologies employed. Inorganic, solid phase HAPs occur as trace substances in all fuels, 

including biomass fuels and natural gas. These substances are emitted in solid form, and are effectively 

controlled by high efficiency particulate matter control systems. 

Inorganic, acid gas HAPs include hydrochloric acid and hydrofluoric acid. These acid gases are formed 

from chlorine and fluorine in the fuels. Hydrochloric acid and hydrofluoric acid are strong acids and are 

therefore highly reactive. These acid gases are effectively controlled by the highly alkaline ash from 

biomass combustion in the advanced circulating fluidized bed boiler and in the fabric filter baghouse. 

Organic HAPs are emitted from boilers as a result of incomplete combustion. These HAP emissions are 

best controlled through good combustion practices. 

Mercury is a unique pollutant. Biomass fuels contain very small amounts of mercury. Multi-pollutant 

control systems, including fabric filter baghouse particulate matter control systems are also effective 

mercury control systems. Mercury specific controls including sorbent injection, oxidation catalysts, and 

fuel additives are being developed. 

Table 1 is a summary of the potential HAP emissions from the biomass-fueled boiler. Detailed HAP 

emission calculations are included in Attachment 1 to this case-by-case MACT analysis. The HAPs 

included in this analysis are those HAPs that were identified in U.S. EPA’s AP-42, 5th Edition, Wood 

Residue Combustion, Tables 1.6-3 and 1.6-4 for uncontrolled wood residue combustion, and that are 

listed as a federal HAP. 
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TABLE 1. Summary of HAP Emissions from the biomass-fired boiler by HAP Category. 

Potential to Emit 

Pollutant Category 

tons/yr % of Total 

1 Inorganic, Solid-Phase (20 HAPs) 6.2 8% 

2 Inorganic Acid Gases (2 HAPs) 66.6 52% 

3 Organic (85 HAPs) 49.4 39% 

4 Mercury 0.01 0.008% 

 TOTAL 122.2 100% 
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Chapter 4. Inorganic Solid 

Phase Hazardous Air Pollutants. 

Inorganic, solid phase HAPs occur as trace substances in the biomass fuels. From Table 2, there are 20 

inorganic, solid phase HAPs including antimony, arsenic, beryllium, cadmium, chromium, chromium VI, 

cobalt, lead, manganese, nickel, and selenium. During combustion, these substances may be volatilized 

and then re-condense into solid particulate matter as the flue gas cools. These substances are emitted in 

solid form, and are effectively controlled by modern, high efficiency PM control devices such as the 

proposed fabric filter baghouse. The Control Technology Review for PM contained in Appendix A of the 

permit application includes a detailed discussion on PM control from biomass-fueled boilers. These 

HAPs tend to be enriched on fine PM. Because fabric filter baghouses are more efficient at removing fine 

PM than other PM control systems, baghouses have higher inorganic, solid phase HAP control 

efficiencies than other PM, PM10, and PM2.5 control systems. 

4.1 U.S. EPA Vacated Industrial Boiler MACT Standards. 

Pursuant to 40 C.F.R. § 63.43(d), an applicant must consider any proposed § 112(d) MACT standard in a 

§ 112(g) case-by-case MACT determination. Under the vacated National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters, 40 

CFR Part 63, Subpart DDDDD, Table 1, particulate matter emissions from new or reconstructed large 

solid-fuel units are limited to 0.025 lb/mmBtu. This requirement was based on Reference Method 5 or 

17, i.e., front half emissions only. 

4.2 MACT Floor Analysis for Inorganic Solid Phase HAPs. 

Table 2 is a summary of the required BACT or MACT PM emission limits for new biomass-fueled 

boilers. Because the boilers in Table 2 are new or modified boilers, these boilers represent the best 

performing similar units for the control of PM emissions and inorganic, solid-phase HAPs. Based on the 

information reviewed, the PM emission limits for new biomass-fueled boilers and which have made an 

initial compliance demonstration range from 0.02 to 0.1 lb/mmBtu, measured as the total filterable and 

condensable PM. In some cases, the actual emissions are well below these limits. However, MACT for 

new sources is the maximum degree of reduction that is deemed achievable and shall not be less stringent 

than the emission control that is achieved in practice by the best controlled similar source. For a standard 

to be considered achievable, it must be achievable under the most adverse circumstances which can 

reasonably be expected to occur. Thus, the MACT standard must be set at a level that is a reasonable 

estimate of the performance of the best controlled similar unit under the worst reasonably foreseeable 

circumstances. 
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TABLE 2. Biomass-fueled boiler particulate matter and PM10 BACT emission limits. 

Limit, 

Facility State lb/mmBtu Permit 

Date 

Capacity, 

mmBtu/hr 

Primary 

Fuel 

Control 

System3

PM PM10

Yellow Pine Energy Company GA May-09 1,529 Wood FFB 0.01 0.018 

South Point Biomass Generation OH Apr-06 318 Wood FFB 0.012 None 

Mancelona Renewable MI Nov-09 565 Wood FFB 0.012 0.025 

Northern Michigan University MI Nov-09 210 Wood FFB 0.0125 0.025 

Nacogdoches Power, LLC TX Mar-07 1,374 Wood FFB 0.015 0.032 

Darrington Energy Cogeneration 

Power Plant WA Feb-05 403 Wood / Bark ESP None 0.02 

Skagit County Lumber Mill WA Jan-06 430 Wood / 

Bark ESP None 0.02 

Fibrominn Biomass Power Plant MN Oct-02 792 Poultry 

Litter FFB 0.02 Test2

Pub Service of New Hampshire - 

Schiller Station NH Oct-04 720 Wood FFB 0.025 None 

Virginia PWC - Laurention Energy 

Authority MN Aug-05 230 Wood ESP 0.025 0.025 

Hillman Power MI Jul-02 300 Wood / 

TDF ESP 0.026 None 

District Energy St. Paul, Inc. MN Nov-01 550 Wood ESP 0.03 0.03 

S.D. Warren Co. - Skowhegan, Me ME Nov-01 1,300 Wood ESP 0.03 

Boralex Stratton Energy, LP ME 672 Wood ESP 0.03 

Wheelabrator Sherman Energy 

Company ME Apr-99 315 Wood ESP 0.036 

Koda Energy MN Aug-07 308 Wood / 

NG ESP 0.037 0.01 

Stoneman Power Plant WI Jan-09 340 Wood ESP 0.06 0.06 

Northern Sun ND May-06 100 Wood / 

Hulls ESP 0.08 

Meadwestvaco Kentucky, Inc. KY Feb-02 631 Wood ESP 0.10 

Footnotes 

1. The first limit is for PM or front half emissions; the second limit is for total PM10 emissions or the combined 

front and backhalf emissions. Note that many permits only specify the front half emissions. 

2. For the Fibrominn biomass-fueled boiler, the permit requires the permittee to conduct performance tests for total 

condensable PM emissions and propose a limit based on the test results. 

3. “FFB” means fabric filter baghouse. “ESP” means electrostatic precipitator. 

4. The Schiller Station netted out of PSD review. The limits of 0.025 lb/mmBtu and 0.01 lb/mmBtu on a 24-hour 

average were established as MACT limits. Compliance is based on Reference Method 5 only. 

5. The first limit for the Hillman Power Company is the BACT limit, and is expressed as 7.8 lb/hr. A second limit 

of 0.1 lb/mmBtu is the MACT limit. The test methods are not specified. 

6. For Koda Energy, the first limit is for PM10 emissions from biomass; the second limit is for natural gas. 
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In the control technology review, We Energies has proposed the use of a fabric filter baghouse to attain a 

best available control technology front-half, filterable PM emission limit of 0.015 lb/mmBtu, and a total 

PM emission limit, including condensable PM, of 0.03 lb/mmBtu. These proposed BACT emission limits 

are reflected in the limits for the best performing similar units in Table 2. There are many factors that 

affect the PM emission rates of the best performing units identified in Table 3. While some of the actual 

performance data indicates that the fabric filter baghouse may achieve lower emission rates during initial 

performance testing, the MACT limit must be achievable under the most adverse circumstances which 

can reasonably be expected to occur. Because the solid phase HAPs are controlled in the same manner as 

PM, the proposed fabric filter baghouse and the PM BACT emission limits also represent the maximum 

degree of reduction in HAP emissions which can be achieved for this source category. A fabric filter 

baghouse is the technology used by the lowest emitting sources of inorganic solid phase HAPs. 

Therefore, we have concluded that the use of PM emissions as a surrogate for emissions of inorganic, 

solid phase HAP’s represents the case-by-case MACT floor for inorganic, solid phase HAPs. 

4.3 Beyond the Floor Inorganic, Solid Phase HAP MACT Analysis. 

In making a case-by-case MACT determination, the permitting authority is expected to look beyond the 

MACT floor, to evaluate whether a greater degree of reduction in emissions is achievable, taking into 

consideration the cost of achieving such emission reductions, and any non-air quality health and 

environmental impacts and energy requirements. The best control method, based upon information 

reviewed, used to control inorganic, solid phase HAP emissions from similar biomass fuel-fueled boilers 

is advanced PM control systems. The most stringent limits achieved in practice result from the use of a 

fabric filter baghouse. As a result, We Energies has concluded that further control beyond a fabric filter 

baghouse is not technically feasible. 

Note that this case-by-case MACT analysis is based on restricting the biomass fuels used in this boiler to 

clean biomass fuels. We Energies proposes that the allowable biomass fuels be defined as follows: 

“Biomass fuels” means a resource that derives energy from wood or plant material or residue, 

clean solid wood waste and crops grown for use as a resource. Fuel sources may include the 

following and other qualifying clean sources: 

• logging residue 

• discarded woody material from primary manufacturing facilities such as paper mills, 

sawmills, or chip mills 

• on-site pulp & paper wastewater treatment plant residue 

• leftover woody material from secondary manufacturers such as door, window, cabinet 

manufacturers 

• woody biomass from municipality wood waste, tree services, and construction companies 

• clean solid wood waste from discarded wood packaging such as pallets/crating and from 

construction and demolition activities 
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• woody biomass plantations, energy crops and agricultural residues 

“Biomass fuels” excludes edible portions of food crops, refuse derived fuel, treated wood, 

municipal solid waste, sewerage sludge, and animal waste. 

4.4 Proposed Case-by-Case MACT Limit for Inorganic, Solid Phase 

HAPs. 

Based on this analysis, We Energies has concluded that the proposed BACT PM emission limits and 

fabric filter baghouse also represent the maximum achievable control technology for solid phase, 

inorganic HAPs from this boiler. We Energies has also concluded that that the BACT compliance 

demonstration requirements for PM also demonstrate compliance with the MACT requirements for this 

boiler, so that no other requirements are necessary for this HAP category. Note that this conclusion is 

consistent with the MACT determinations made by the Department in the air pollution control 

construction permit for Weston Unit 4, Permit No. 03-RV-248, condition I.A.12.a.(1), and in the air 

pollution control construction permit for the Elm Road Generating Station, Permit No. 03-RV-166, 

condition I.A.12.a.(1). 
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Chapter 5. Inorganic, Acid Gas 

HAPs. 

Inorganic, vapor phase acid gas HAPs include hydrochloric and hydrofluoric acids. They are formed 

from chlorine and fluorine contained in the biomass fuels. Hydrochloric acid (HCl) and hydrofluoric acid 

(HF) are strong acids which are water soluble and highly reactive with alkaline components of biomass 

fuels. As a result, these acids are effectively controlled as a part of the biomass fuel combustion process, 

and in the fabric filter baghouses. When the fuel fired produces highly alkaline ash as is the case for 

biomass fuels, most of the chlorine and fluorine is converted as salts, such as sodium chloride, rather than 

being emitted as the inorganic acid gases. 

5.1 U.S. EPA Vacated Industrial Boiler MACT Standards. 

Pursuant to 40 C.F.R. § 63.43(d), an applicant must consider any proposed § 112(d) MACT standard in a 

§ 112(g) case-by-case MACT determination. Under the vacated National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters, 40 

CFR Part 63, Subpart DDDDD, Table 1, HCl emissions from new or reconstructed large solid-fuel units 

are limited to 0.02 lb/mmBtu. There was no specific MACT limit for HF emissions. 

5.2 MACT Floor Analysis for Hydrogen Chloride (HCl). 

Based on information reviewed and summarized in Table 4, the most stringent HCl emission limit 

identified for any biomass boiler and which has made an initial compliance demonstration is the limit of 

0.02 lb per million Btu heat of input for Public Service of New Hampshire - Schiller Station. This limit 

apparently reflects the vacated NESHAP limit for new solid fuel-fired boilers in 40 CFR Part 63, Subpart 

DDDDD, although the limit is stated as a case-by-case MACT limit. Please note, however, that the 

allowable fuels for the Schiller Station includes wood and coal. The Schiller Station has a circulating 

fluidized bed (CFB) boiler. The permit requires the use of sorbent (limestone) injection to the CFB boiler 

for SO2 and HCl control. However, the use of sorbent injection is not required to demonstrate compliance 

with the MACT limit. When demonstrating compliance with the MACT limit, the permit states “(The 

permittee) may demonstrate compliance with applicable emissions rates for HCl, and/or mercury using 

fuel analysis if the emission rates calculated ... are less than the applicable emission limit”. 

The most stringent HCl emission limit in any permit reviewed is 0.006 lb/mmBtu for the Yellow Pine 

Energy Company, Georgia. The permit for this facility also allows the use of tire derived fuel, and 

requires the use of a dry sorbent injection system for the control of SO2 emissions. 
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Appendix D: Case-by-Case MACT Analysis Under Section 112(g) of the CAA March, 2010

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TABLE 3. Biomass-fueled boiler HCl emission limits representing MACT. 

Facility State Permit 

Date Primary Fuel Control Systema Limit, lb/mmBtu 

Operating 

Facility? 

Yellow Pine Energy Company GA May-09 Wood / TDF FFB / SI 0.006 NO 

South Point Biomass Generation OH Apr-06 Wood FFB / SI 0.0095 NO 

Northern Michigan University MI Nov-09 Biomass FFB 0.01 NO 

Nacogdoches Power, LLC TX Mar-07 Wood FFB 0.0213 NO 

Fibrominn Biomass Power Plant MN Oct-02 Poultry Litter FFB 0.034b YES 

Pub Service of NH - Schiller NH Oct-04 Wood / Coal FSI / FFB 0.02c YES 

Virginia PWC - Laurention Energy MN Aug-05 Wood ESP 0.02 YES 

Darrington Energy Cogeneration WA Feb-05 Wood ESP No Limit YES 

Hillman Power Company MI Jul-02 Wood / TDF ESP No Limit YES 

District Energy St. Paul, Inc. MN Nov-01 Wood ESP No Limit YES 

Koda Energy MN Aug-07 Wood / NG ESP Syn. Minor YES 

Stoneman Power Plant WI Jan-09 Wood ESP 0.284d YES 

Footnotes 

a

 “FFB” means fabric filter baghouse; “ESP” means electrostatic precipitator; “SI” means sorbent injection; “FSI” 

means “furnace sorbent injection” and refers to limestone injection into the fluidized bed boiler. 

b

 The limit for the Fibrominn Plant is 95% reduction when emissions are greater than 0.034 lb/mmBtu. 

c

 The case-by-case MACT limit for the Public Service of New Hampshire - Schiller Station includes coal 

combustion. Compliance with this limit may be based on fuel analysis data only. 

d

 The limit for the Stoneman Plant is not a MACT limit, but rather a limit under NR 445, Wis. Adm. Code. 

5.2.1 HCl Fuel Analysis and Emission Data. 

The National Council for Air and Stream Improvement, Inc. (NCASI) evaluated chlorine levels in bark 

and stemwood in Technical Bulletin No. 0875, Nationwide Evaluation of Mercury and Chlorine Levels in 

Bark and Stemwood, 2004. A four-week sampling program was carried out at 30 pulp and paper and 

wood products manufacturing facilities across the country. According to this report, the chlorine content 

of the bark samples ranged from less than 40 to 274 ppm on an oven dry basis, with an average of 90 

ppm. The chlorine concentration of stemwood ranged from 50 to 162 ppm, with an average of 70 ppm. 

Assuming all chlorine is emitted as HCl, the average HCl emission rate was 0.011 and 0.007 lb/mmBtu 

for bark and stemwood, respectively, with a 95th percentile of 0.014 lb/mmBtu. 

According to NCASI Technical Bulletin No. 0837, Emissions of Sulfuric, Hydrochloric, and Hydrofluoric 

Acids from Combination Bark Boilers, HCl emissions ranged from 0.016 to 0.058 lb/mmBtu for the 

coal/bark boilers and from 0.00025 to 0.00045 lb/mmBtu for the oil/bark boilers. Four coal/bark boilers 

and two residual oil/bark boilers were tested during this study. Two of the four coal/bark boilers were 

equipped with dry ESPs and two were equipped with venturi scrubbers. One of the two residual oil/bark 

boilers was equipped with a dry gravel scrubber while the other was equipped with an ESP. The much 
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lower measured emissions indicate that HCl is being captured in the combustion process and in the PM 

control systems as salts, rather than being emitted as the acid gas. 

Data from the U.S. EPA Report, Wood Products in the Waste Stream - Characterization and Combustion 

Emissions, EPA Report EPA-600/R-96-119a, indicates higher chloride and uncontrolled HCl emissions. 

The data is summarized in Table 4. This data indicates an average uncontrolled HCl emission rate of 

0.084 lb/mmBtu, with a 95th percentile of 0.161 lb/mmBtu. The emission factor for HCl emissions from 

waste wood combustion in the U.S. EPA’s AP-42, Compilation of Air Pollutant Emission Factors, 5th

Edition, Wood Residue Combustion, Tables 1.6-3, is 0.0192 lb/mmBtu. 

TABLE 4. Wood fuels analyses data and uncontrolled hydrogen chloride (HCl) emission rate.

Wood Analyses, dry 

basis, weight % Site 1 Site 2 Site 3 Site 4 Site 6 Site 7 Average 90th Percentile 

 Carbon 50.28 50.55 52.90 45.38 50.11 50.45 49.95 

 Hydrogen 5.92 5.95 5.85 5.17 5.87 5.86 5.77 

 Nitrogen 0.46 0.53 0.51 0.73 0.52 0.62 0.56 

 Sulfur 0.12 0.06 0.08 0.05 0.15 0.10 0.09 

 Ash 5.16 7.38 3.87 15.99 5.15 6.40 7.33 

 Oxygen 38.07 35.54 36.79 32.69 38.20 36.57 36.31 

 Chlorine 0.08 0.03 0.16 0.06 0.03 0.05 0.07 

Heat Content, Btu/lb 8,238 8,599 8,795 7,543 8,353 8,437 8,327 

HCl Combustion 

Concentration, lb/mmBtu 0.100 0.036 0.187 0.082 0.037 0.061 0.084 0.135 

Footnotes 

Data is from the U.S. EPA Report, Wood Products in the Waste Stream - - Characterization and Combustion 

Emissions, EPA Report EPA-600/R-96-119a. 

In January, 2010, a preliminary database of emission test data, continuous emission monitoring system 

(CEMS) data, and fuel analysis data for boilers and process heaters at major sources of HAP was made 

available at http://www2.ergweb.com/projects/combustion/combustiontesting.html. This data includes 

standardized emission data from both the U.S. EPA’s Phase I survey Information Collection Request 

(ICR No. 2286.01) and the Phase II test plan (ICR No. 2286.03). The database included both fuel 

sampling and analysis data for HCl, as well as emission test data for HCl from biomass-fueled boilers. 

The HCl fuel sampling and analysis data included over 500 samples for biomass fuels (with descriptions 

including wood, bark, plywood, particleboard, hog fuel, paper and paper residues, and biomass). The HCl 

fuel sampling and analysis data ranged from 5.5 x 10-7 lb/mmBtu to more than 0.5 lb/mmBtu. The 

database also included HCl emission test data using U.S. EPA Reference Method 26. The HCl emission 

test data included 78 tests on biomass-fueled boilers, with emission rates ranging from 0.0002 lb/mmBtu 

to 0.072 lb/mmBtu. Several of the emission test results indicated HCl emissions below the detection limit 

of the test. This ICR data is plotted in Figure 1 as probability distributions for each data set. The 90% 

probability distribution for the HCl emission rate, based on fuel sampling and analysis, is 0.13 lb/mmBtu, 
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while the 90% probability distribution for the HCl emission rate, based on emission testing, is 0.018 

lb/mmBtu. This data suggests that the actual HCl emissions are reduced by approximately 85% as 

compared to the uncontrolled, fuel input or potential combustion concentration for HCl. 

This outcome seems logical because of the high levels of calcium and potassium in typical biomass fuels. 

Ash mineral analysis data from the U.S. EPA Report, Wood Products in the Waste Stream -

Characterization and Combustion Emissions, EPA Report EPA-600/R-96-119a, Table 7-32 indicates that 

the evaluated fuels in the report had calcium oxide (CaO) levels of 15.3%. The fuel had an average ash 

content of 7.8%. From these values, the fuel had a CaO level of 1.19 lb CaO/100 lb dry fuel, or 0.0213 

moles of calcium per 100 lb dry fuel. The fuel also had a chlorine content of 0.07%, equal to 0.002 moles 

of chlorine per 100 lb dry fuel. Therefore, the effective calcium to chlorine ratio in the boiler when firing 

this typical biomass fuel is more than ten to one (10:1). This high level of reactive CaO would be 

expected to react with HCl in the flue gas to form calcium chloride. 

Based on the available data, we have concluded that the MACT floor for HCl emissions from this 

biomass-fueled boiler is 0.018 lb/mmBtu. This emission rate represents a reasonable estimate of the 

performance of the “best controlled similar unit” under the worst reasonably foreseeable circumstances. 

FIGURE 1. Hydrogen chloride (HCl) fuel sampling and analysis and emission test data for biomass 

combustion from the U.S. EPA’s industrial boiler ICR. 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0.0001 0.0010 0.0100 0.1000 1.0000

HCl Emission Rate, lb/million Btu

Probability Density

HCl Emission Test Data

HCl Fuel Sampling Data

90% Probability, 

0.018 lb/mmBtu

90% Probability, 

0.13 lb/mmBtu
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5.3 Beyond the Floor MACT Analysis for Hydrogen Chloride (HCl). 

Based upon the information reviewed, the most common method used to control HCl emissions from 

biomass fueled-boilers is the use of biomass fuels with inherently low chloride concentrations, combined 

with the use of a fabric filter baghouse or electrostatic precipitator. This combination of controls 

effectively control these acid gas emissions through the reaction of the acid gas with the alkaline ash. In 

addition, several facilities are required to use dry sorbent injection systems. However, all of the facilities 

that were identified with MACT limits may demonstrate compliance with the MACT limit without the 

requirement to operate sorbent injection systems. Further, of the five facilities identified with MACT 

limits, 3 facilities are allowed to fire solid fuels including tire derived fuel (TDF), and coal. Therefore, 

while the use of FGD systems may also control HCl and HF emissions, the use of FGD systems is not 

necessary to achieve very low HCl and HF emission rates when firing biomass fuels. 

The actual control of HCl emissions by the reaction of the flyash with the acid gas is difficult to predict. 

For coal combustion, the EPRI report, Emission Factors Handbook: Guidelines for Estimating Trace 

Substance Emissions from Fossil fuel Steam Electric Plants, Final Report, April, 2002, indicates that the 

expected HCl and HF control efficiency for subbituminous coal combustion (which has a highly alkaline 

ash) of 80% and 50%, respectively. However, the continuous reduction of HCl emissions from biomass 

combustion by the use of FGD systems including sorbent injection is not well understood or demonstrated 

in practice. Because biomass combustion already results in high levels of calcium oxide (CaO) and 

potassium oxide (K2O) in the ash, the additional injection of sorbent may not achieve substantial emission 

reductions. 

Even if the use of FGD systems or sorbent injection could further reduce HCl emissions, the costs of 

control would be extremely high. The lowest cost option, a dry sorbent injection system, would have a 

total capital cost of $3.3 million, annual O&M costs of $860,000, and a total annual cost of $1.2 million 

(refer to the control technology review for fluoride emissions). If the sorbent injection system could 

reduce HCl emissions by 50%, from an emission rate of 0.018 lb/mmBtu and 63.1 tons per year, to 0.009 

lb/mmBtu and 31.6 tons per year, the average cost effectiveness for the dry sorbent injection system 

would be $38,000 per ton of HCl controlled. This is an extremely high cost which does not represent 

MACT for the control of HCl emissions. 

In addition, the use of sorbent injection may adversely impact the reuse of this ash which would have 

substantial environmental costs and additional economic impacts. The biomass-fueled boiler is expected 

to consume approximately 48 tons per hour of bone-dry biomass fuels, or 416,000 tons per year of bonedry biomass fuels. At a typical ash content of 7%, the combustion of these fuels would produce about 

29,100 tons per year of ash. This ash will be derived from biomass fuels, and is anticipated to have value 

as a soil amendment or fertilizer. However, if sorbent injection were to adversely impact the reuse of this 

ash, the ash may need to be disposed of in a landfill. Not only would this have environmental 

consequences, but this could also lead to much higher costs. 

 
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5.4 Proposed Case-by-Case MACT for Hydrogen Chloride (HCl). 

This case-by-case MACT analysis found that the most stringent limit achieved in practice for HCl 

emissions from any biomass-fueled boiler is 0.02 lb/mmBtu. The most stringent HCl emission limit in 

any permit reviewed is 0.006 lb/mmBtu for the Yellow Pine Energy Company, Georgia. Data from the 

U.S. EPA’s Information Collection Request for biomass-fired industrial boilers indicates a 90% 

probability for the HCl emission rate, based on actual emission testing, of 0.018 lb/mmBtu. This is the 

case-by-case MACT floor for HCl emissions from this boiler. 

In the beyond the floor MACT analysis, flue gas desulfurization (FGD) systems, including dry sorbent 

injection, were evaluated as a potential control technology for HCl emissions from biomass combustion. 

However, the continuous reduction of HCl emissions from biomass combustion by the use of FGD 

systems and sorbent injection is not demonstrated in practice. Because biomass combustion already 

results in high levels of calcium oxide (CaO) and potassium oxide (K2O) in the ash, the additional 

injection of sorbent may not achieve substantial emission reductions. Even if the use of FGD systems or 

sorbent injection could further reduce HCl emissions, the costs of control would be extremely high, with 

an average cost effectiveness for the dry sorbent injection system of $38,000 per ton of HCl controlled. 

In addition, the use of sorbent injection may adversely impact the reuse of this ash which would have 

substantial environmental costs and additional economic impacts. 

Based on this analysis, We Energies has concluded that the use of biomass fuels in combination with a 

fabric filter baghouse represents MACT for the control of HCl emissions from this boiler. We Energies 

proposes the following emission limits as MACT for HCl emissions. 

1. Hydrogen chloride (HCl) emissions from the circulating fluidized bed boiler 

shall be controlled using biomass fuels in combination with a fabric filter 

baghouse as MACT. 

2. Hydrogen chloride (HCl) emissions may not exceed 0.018 lb/mmBtu. 

3. Compliance with this emission limit shall be demonstrated using U.S. 

Reference Methods 26 or 26A, or another method approved in writing by 

the Department. 
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5.5 MACT Floor Analysis for Hydrogen Fluoride (HF). 

Based on the permits and information available, We Energies did not identify any biomass-fueled boiler 

with a hydrogen fluoride (HF) emission limit. As noted above, the U.S. EPA did not include a specific 

MACT emission limit or standard under the now vacated National Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters, 40 CFR Part 63, 

Subpart DDDDD. 

5.5.1 HF Fuel Analysis and Emission Data. 

There has been a very limited amount of information available on fluoride levels in biomass fuels. 

According to NCASI Technical Bulletin No. 0837, Emissions of Sulfuric, Hydrochloric, and Hydrofluoric 

Acids from Combination Bark Boilers, HF emissions ranged from 0.00023 to 0.0011 lb/mmBtu for the 

coal/bark boilers and from 0.000016 to 0.000074 lb/mmBtu for the oil/bark boilers. 

According to the U.S. EPA’s MACT database emission factors from the U.S. EPA memorandum from 

Christy Burlew and Roy Oommen, to Jim Eddinger, U.S. Environmental Protection Agency, OAQPS 

(C439-01), dated October, 2002, Development of Average Emission Factors and Baseline Emission 

Estimates for the Industrial, Commercial, and Institutional Boilers and Process Heaters National 

Emission Standard for Hazardous Air Pollutants, the emission factor for HF emissions from wood-fueled 

boilers is 0.0081 lb/mmBtu. 

The U.S. EPA’s AP-42, Compilation of Air Pollutant Emission Factors, 5th Edition, Wood Residue 

Combustion, does not list an emission factor for HF emissions. In Switzerland, the combustion 

requirements for wood limit HF emissions to 2 mg/m3

, equal to 0.0011 lb/mmBtu. 

In January, 2010, a preliminary database of emission test data, continuous emission monitoring system 

(CEMS) data, and fuel analysis data for boilers and process heaters at major sources of HAP was made 

available at http://www2.ergweb.com/projects/combustion/combustiontesting.html. This data includes 

standardized emission data from both the U.S. EPA’s Phase I survey Information Collection Request 

(ICR No. 2286.01) and the Phase II test plan (ICR No. 2286.03). The database included both fuel 

sampling and analysis data for HF, as well as emission test data for HF from biomass-fueled boilers. The 

HF fuel sampling and analysis data included over 350 samples for biomass fuels (with descriptions 

including wood, bark, plywood, particleboard, hog fuel, and biomass). The HF fuel sampling and 

analysis data ranged from 1.1 x 10-6 lb/mmBtu to 0.033 lb/mmBtu. The database also included HF 

emission test data using U.S. EPA Reference Method 26. The HF emission test data included 34 tests on 

biomass-fueled boilers, with emission rates ranging from 0.000003 lb/mmBtu to 0.0012 lb/mmBtu. 

Nineteen (19) of the emission test results indicated HF emissions below the detection limit of the test. 

This ICR data is plotted in Figure 2 as probability distributions for each data set. The 90% probability for 

the HF emission rate, based on fuel sampling and analysis, is 0.006 lb/mmBtu, while the 90% probability 

distribution for the HF emission rate, based on emission testing, is 0.0007 lb/mmBtu. This data suggests 

that the actual HF emissions are reduced by almost 90% as compared to the uncontrolled, fuel input or 

potential combustion concentration for HF. 
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Appendix D: Case-by-Case MACT Analysis Under Section 112(g) of the CAA March, 2010

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As discussed with respect to HCl emissions, this outcome seems logical because of the high levels of 

calcium and potassium in typical biomass fuels. Typical biomass fuels have a CaO level of 1.19 lb 

CaO/100 lb dry fuel, or 0.0213 moles of calcium per 100 lb dry fuel. From the TCR fuel sampling 

database, the biomass fuels have a typical fluorine content of well below 100 mg per kg, or 0.01%. A 

fluorine content of 0.01% is equal to 0.0005 moles of fluorine per 100 lb dry fuel. Therefore, the 

effective calcium to fluorine ratio in the boiler when firing this typical biomass fuel is more than forty to 

one (40:1). This high level of reactive CaO would be expected to react with HF in the flue gas to form 

calcium fluoride. 

Based on the available data, we have concluded that the MACT floor for HF emissions from this 

biomass-fueled boiler is the use of biomass fuels and a fabric filter baghouse. The resulting emission rate 

is expected to be less than 0.001 lb/mmBtu. The use of biomass fuels and a fabric filter baghouse 

represents a reasonable estimate of the performance of the “best controlled similar unit” under the worst 

reasonably foreseeable circumstances. 

FIGURE 2. Hydrogen fluoride (HF) fuel sampling and analysis and emission test data for biomass 

combustion from the U.S. EPA’s industrial boiler ICR. 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0.00001 0.00010 0.00100 0.01000 0.10000

HF Emission Rate, lb/million Btu

Probability Density

HF Emission Test Data

HF Fuel Sampling Data

90% Probability, 

0.0007 

90% Probability, 

0.006 lb/mmBtu
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5.6 Beyond the Floor MACT Analysis for Hydrogen Fluoride (HF). 

Based upon information reviewed, the most common control method used to control HF emissions from 

biomass fueled-boilers is the use of biomass fuels with inherently low fluoride concentrations, combined 

with the use of a fabric filter baghouse or electrostatic precipitator. This combination of controls 

effectively control these acid gas emissions through the reaction of the acid gas with the alkaline ash. In 

addition, several facilities are required to use dry sorbent injection systems. However, all of the facilities 

that were identified with MACT limits may demonstrate compliance with the MACT limit without the 

requirement to operate the sorbent injection system. Based on the permits and information available, We 

Energies did not identify any biomass-fueled boiler with a hydrogen fluoride (HF) emission limit. 

The actual control of HF emissions by the reaction of the flyash with the acid gas is difficult to predict. 

For coal combustion, the EPRI report, Emission Factors Handbook: Guidelines for Estimating Trace 

Substance Emissions from Fossil fuel Steam Electric Plants, Final Report, April, 2002, indicates that the 

expected HF control efficiency for subbituminous coal combustion (which has a highly alkaline ash) of 

50%. However, the continuous reduction of HF emissions from biomass combustion by the use of FGD 

systems including sorbent injection is not demonstrated in practice. Because biomass combustion already 

results in high levels of calcium oxide (CaO) and potassium oxide (K2O) in the ash, the additional 

injection of sorbent may not achieve substantial emission reductions. 

As with the control of HCl emissions, even if the use of FGD systems or sorbent injection could further 

reduce HF emissions, the costs of control would be extremely high. The lowest cost option, a dry sorbent 

injection system, would have a total capital cost of $3.3 million, annual O&M costs of $860,000, and a 

total annual cost of $1.2 million (refer to the control technology review for fluoride emissions). If the 

sorbent injection system could reduce HF emissions by 50%, from an emission rate of 0.001 lb/mmBtu 

and 3.5 tons per year, to 0.0005 lb/mmBtu and 1.8 tons per year, the average cost effectiveness for the dry 

sorbent injection system would be more than $700,000 per ton of HF controlled. This is an extremely 

high cost which does not represent MACT for the control of HF emissions. 

In addition, the use of sorbent injection may adversely impact the reuse of this ash which would have 

substantial environmental costs and additional economic impacts. The combustion of biomass fuels 

would produce about 29,100 tons per year of ash. This ash will be derived from biomass fuels, and is 

anticipated to have value as a soil amendment or fertilizer. However, if sorbent injection were to 

adversely impact the reuse of this ash, the ash may need to be disposed of in a landfill. Not only would 

this have environmental consequences, but this could also lead to much higher costs. 

 
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5.7 Proposed Case-by-Case MACT for Hydrogen Fluoride (HF). 

Based on the permits and information available, We Energies did not identify any biomass-fueled boiler 

with a hydrogen fluoride (HF) emission limit. Based on the available data, we have concluded that the 

MACT floor for HF emissions from this biomass-fueled boiler is the use of biomass fuels and a fabric 

filter baghouse. The resulting emission rate is expected to be less than 0.001 lb/mmBtu. 

In the beyond the floor MACT analysis, flue gas desulfurization (FGD) systems, including dry sorbent 

injection, were evaluated as a potential control technology for HF emissions from biomass combustion. 

However, the continuous reduction of HF emissions from biomass combustion by the use of FGD 

systems and sorbent injection is not demonstrated in practice. Because biomass combustion already 

results in high levels of calcium oxide (CaO) and potassium oxide (K2O) in the ash, the additional 

injection of sorbent may not achieve substantial emission reductions. Even if the use of FGD systems or 

sorbent injection could further reduce HF emissions, the costs of control would be extremely high, with 

an average cost effectiveness for the dry sorbent injection system of more than $700,000 per ton of HF 

controlled. In addition, the use of sorbent injection may adversely impact the reuse of this ash which 

would have substantial environmental costs and additional economic impacts. 

Based on this analysis, We Energies has concluded that the use of biomass fuels in combination with a 

fabric filter baghouse represents MACT for the control of HF emissions from this boiler. The principles 

of case-by-case MACT in 40 CFR § 63.43(d)(3) states: 

(d) Principles of MACT determinations. 

(3) The applicant may recommend a specific design, equipment, work practice, or 

operational standard, or a combination thereof, and the permitting authority may approve 

such a standard if the permitting authority specifically determines that it is not feasible to 

prescribe or enforce an emission limitation under the criteria set forth in section 112(h)(2) of 

the Act. 

Because HF emissions from biomass combustion are very small, it is not feasible to prescribe or enforce 

an emission limitation for HF emissions. Therefore, We Energies proposes the following emission limits 

as MACT for HF emissions. 

1. Hydrogen fluoride (HF) emissions from the circulating fluidized bed boiler 

shall be controlled using biomass fuels and natural gas in combination with 

a fabric filter baghouse as MACT. 
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Chapter 6. Organic HAPs. 

Organic HAPs are emitted from biomass combustion as a result of incomplete combustion. A detailed 

discussion of control options for other products of incomplete combustion including carbon monoxide 

(CO) and volatile organic compound (VOC) emissions is included in the control technology review. 

Potential organic HAPs resulting from biomass combustion include a wide range of organic compounds, 

including polycyclic aromatic compounds, dioxins, furans, and formaldehyde. These HAPs may be 

considered as a subset of the general class of organic compounds referred to VOC. As a result, 

minimizing VOC (and CO) emissions will also minimize organic HAP emissions. 

The use of CO or VOC emissions as a surrogate for the control of organic HAP emissions is consistent 

with the U.S. EPA’s practice when establishing MACT standards for combustion source categories 

emitting organic HAP’s. For example, in the preamble for the “National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters.” 69 

Fed. Reg. 55218, September 13, 2004, the U.S. EPA stated: “Because CO is a good indicator of 

incomplete combustion, there is a direct correlation between CO emissions and the formation of organic 

HAP emissions. Monitoring equipment for CO is readily available, which is not the case for organic 

HAP. Also, it is significantly easier and less expensive to measure and monitor CO emissions than to 

measure and monitor emissions of each individual organic HAP. Therefore, using CO as a surrogate for 

organic HAP is a reasonable approach because minimizing CO emissions will result in minimizing 

organic HAP emissions.” 

6.1 U.S. EPA Vacated Industrial Boiler MACT Standards. 

Pursuant to 40 C.F.R. § 63.43(d), an applicant must consider any proposed § 112(d) MACT standard in a 

§ 112(g) case-by-case MACT determination. Under the vacated National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters, 40 

CFR Part 63, Subpart DDDDD, Table 1, CO emissions from new or reconstructed large solid-fuel units 

larger than 100 mmBtu/hr are limited to 400 ppm by volume on a dry basis corrected to 7% oxygen, on a 

30-day rolling average. This emission rate is equal to 0.44 lb/mmBtu. In the control technology review 

for this biomass boiler, We Energies has proposed a CO BACT emission limit of 0.20 lb/mmBtu on a 30-

day rolling average basis. 

6.2 MACT Floor Analysis for Organic HAPs. 

Table 5 is a summary of new biomass-fueled boilers which have commenced initial operation, the 

allowable fuels, and the CO emission limit which represents BACT. Because these are new units, or 

existing units with new controls, these units represent the best performing similar units for the control of 
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CO emissions and organic HAPs. Note that from Table 5, of the top 6 ranked facilities, i.e., the Public 

Service of NH - Schiller Station, South Point Biomass Generation, Yellow Pine Energy Company, 

Nacogdoches Power, LLC, Mancelona Renewable, and Northern Michigan University, only the South 

Point Biomass boiler is a stoker boiler. The other boilers are fluidized bed boilers. Based on the 

information reviewed, the CO emission limits for new biomass-fueled boilers and which have made an 

initial compliance demonstration range from 0.10 to 0.63 lb/mmBtu. We Energies has proposed a best 

available control technology CO emission limit of 0.20 lb/mmBtu, achieved through good combustion 

practices. Because the organic HAPs are controlled in the same manner as CO emissions, the proposed 

use of good combustion practices and the CO BACT emission limit represents the maximum degree of 

reduction in organic HAP emissions which can be achieved by utilizing this control technology for any 

biomass-fueled boiler. This analysis indicates that the use of CO emissions as a surrogate for emissions 

of organic HAP’s represents the case-by-case MACT floor for organic HAP emissions from this boiler. 

TABLE 5. Carbon monoxide (CO) BACT emission limits for biomass fuel-fueled boilers. 

Facility State Permit 

Date 

Capacity, 

mmBtu/hr Primary Fuel Limit, lb/mmBtu 

Pub. Service of NH - Schiller Station NH Oct-04 720 Wood 0.10 

South Point Biomass Generation OH Apr-06 318 Wood 0.10 

Yellow Pine Energy Company GA May-09 1,529 Wood 0.15 

Nacogdoches Power, LLC TX Mar-07 1,374 Wood 0.15 

Mancelona Renewable MI Nov-09 565 Wood/Biomass 0.17 

Northern Michigan University MI Nov-09 210 Wood/Biomass 0.17 

Fibrominn Biomass Power MN Oct-02 792 Poultry Litter 0.24 

Virginia PWC - Laurention Energy MN Aug-05 230 Wood 0.30 

District Energy St. Paul, Inc. MN Nov-01 550 Wood 0.30 

Sierra Pacific Aberdeen facility WA Oct-02 310 Waste Wood 0.35 

S.D. Warren Company ME Nov-01 1,300 Wood 0.40 

Stoneman Power Plant WI Jan-09 340 Wood 0.40 

Koda Energy MN Aug-07 308 Wood / Nat. Gas 0.43 

Martinsville Thermal LLC VA Sep-03 120 Wood 0.44 

Wheelabrator Sherman Energy ME Apr-99 315 Wood 0.45 

Northern Sun ND May-06 100 Wood / Hulls 0.63 

Skagit County Lumber Mill WA Jan-06 430 Wood 0.93 

Sierra Pacific Industries CA Dec-02 245 Wood 1.15 
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6.3 Beyond the Floor Organic HAP MACT Analysis. 

The only control methods, based upon available information, actually used to control organic HAP 

emissions from biomass-fueled boilers is good combustion practices. One facility, the South Point 

Biomass Generation Facility in Ohio, is also required to use an oxidation catalyst for the control of CO 

emissions. However, this facility has not yet commenced operation. There are significant technical 

questions regarding the ability of oxidation catalysts to control organic HAP emissions from biomassfueled boilers. Because of the serious technical questions regarding the use of oxidation catalysts on 

circulating fluidized bed biomass-fueled boilers, We Energies has concluded that further control beyond 

the use of good combustion practices is not technically feasible. 

6.4 Proposed Case-by-Case MACT Limit for Organic HAPs. 

Based on this analysis, We Energies has concluded that the proposed BACT CO emission limits and use 

of good combustion practices also represent the maximum achievable control technology for organic 

HAPs from this biomass-fueled boiler, so that no other requirements are necessary for this HAP category. 

Note that this conclusion is consistent with the case-by-case MACT determinations for organic HAP 

emissions made by the Department in the air pollution control construction permit for Weston Unit 4, 

Permit No. 03-RV-248, condition I.A.12.a.(3), and in the air pollution control construction permit for the 

Elm Road Generating Station, Permit No. 03-RV-166, condition I.A.12.a.(3). 

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Chapter 7. Mercury. 

Mercury is a trace element in biomass fuels. Mercury is an unusual metal because it boils at a very low 

temperature of 675 o

F. When fuel is burned, the high combustion temperatures vaporize mercury to form 

elemental mercury (Hg0

). This gaseous form of mercury may then react with other substances in the flue 

gas to form oxidized mercury (Hg+2). Some mercury may be adsorbed onto particulate matter, called 

particle bound mercury (Hgp). The total mercury in the flue gas (HgT) is the sum of Hgp, Hg+2, and Hg0

. 

Mercury is present at varying concentrations in biomass. When biomass is burned, mercury exits the 

boiler at extremely low concentrations, on the order of parts per billion. 

7.1 U.S. EPA Vacated Industrial Boiler MACT Standards. 

Pursuant to 40 C.F.R. § 63.43(d), an applicant must consider any proposed § 112(d) MACT standard in a 

§ 112(g) case-by-case MACT determination. Under the vacated National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters, 40 

CFR Part 63, Subpart DDDDD, Table 1, mercury emissions from new or reconstructed large solid-fuel 

units are limited to 0.000003 lb/mmBtu, or 3.0 pounds per trillion Btu of heat input. 

7.2 State of Wisconsin Mercury Rule 

Under NR 446.03(2)(a), Wis. Adm. Code, new sources with allowable mercury emissions of 10 pounds 

per year or more must control mercury emissions to a level which is the best available control technology. 

However, under s. NR 446.03(2)(b), Wis. Adm. Code, units that are subject to an emission limit required 

for mercury under sections 111 or 112 of the Clean Air Act are exempt from this requirement. Because 

this § 112(g) MACT determination will result in a mercury emission limit required under CAA § 112, this 

unit is exempt from the requirements of NR 446, Wis. Adm. Code. 

7.3 MACT Floor Analysis for Mercury. 

Table 6 is a summary of new biomass-fueled boilers which have commenced initial operation, and the 

mercury emission limit which represents MACT. Because these are new units, or existing units with new 

controls, these units represent the best performing similar units for the control of mercury emissions. 

Based on the information reviewed, the mercury emission limits for new biomass-fueled boilers and

which have made an initial compliance demonstration is 3.0 pounds per trillion Btu of heat input. Other 

emission limits range from 9.0 to 25.0 lb/TBtu. All of the permits with a MACT limit required initial 

compliance demonstration by stack testing. No sources were required to install mercury specific controls. 
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TABLE 6. Biomass-fueled boiler mercury emission limits representing MACT. 

Facility State Permit 

Date Primary Fuel Control Systema Limit, lb/TBtuB

Operating 

Facility? 

Northern Michigan University MI Nov-09 Wood FFB 2.27 NO 

Pub Service of NH - Schiller NH Oct-04 Wood / Coal FFB 3.0 YES 

Virginia PWC - Laurention Energy MN Aug-05 Wood ESP 3.0 YES 

South Point Biomass Generation OH Apr-06 Wood FFB 9.0 NO 

Yellow Pine Energy Company GA May-09 Wood FFB 25.0 NO 

Nacogdoches Power, LLC TX Mar-07 Wood FFB No Limit 0.17 

Mancelona Renewable MI Nov-09 565 FFB No Limit 

Fibrominn Biomass Power Plant MN Oct-02 Poultry Litter FFB No Limit YES 

Darrington Energy Cogeneration WA Feb-05 Wood ESP No Limit YES 

Hillman Power Company MI Jul-02 Wood / TDF ESP No Limit YES 

District Energy St. Paul, Inc. MN Nov-01 Wood ESP No Limit YES 

S.D. Warren Co. - Skowhegan, Me ME Nov-01 Wood ESP No Limit YES 

Koda Energy MN Aug-07 Wood / NG ESP Syn Minor YES 

Stoneman Power Plant WI Jan-09 Wood ESP No Limit YES 

Footnotes 

a

 “FFB” means fabric filter baghouse. “ESP” means electrostatic precipitator. 

b

 “TBtu” means trillion Btu or 1012 Btu. 

7.3.1 Mercury Concentrations in Biomass. 

The National Council for Air and Stream Improvement, Inc. (NCASI) evaluated mercury levels in bark 

and stemwood in Technical Bulletin No. 0875, Nationwide Evaluation of Mercury and Chlorine Levels in 

Bark and Stemwood, 2004. A four-week bark and stemwood sampling program was carried out at 30 

pulp and paper and wood products manufacturing facilities across the country. According to this report, 

the mercury content of the bark samples ranged from less than 1.0 to 37.4 parts per billion (ppb) on an 

oven dry basis, with an average of 12.5 ppb. For stemwood, the mercury concentration ranged from 1.0 to 

10.4 ppb, with an average of 2.7 ppb. Assuming all mercury in the fuel would be emitted, the average 

uncontrolled mercury emission rate was 1.42 pounds per trillion Btu (lb/TBtu) and 0.28 lb/TBtu for bark 

and stemwood, respectively. The 90th percentile value was 2.0 lb/TBtu. Note that a mercury emission 

rate of 1.42 lb/TBtu is equal to a mercury flue gas concentration of 0.2 parts per billion or 2.4 micrograms 

per dry standard cubic meter (ug/dscm). 

Data from the U.S. EPA Report, Wood Products in the Waste Stream - - Characterization and 

Combustion Emissions, EPA Report EPA-600/R-96-119a, indicate much higher biomass fuel mercury 
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concentrations. According to Tables 7-32 and 7-33 of this report, wood fuel analyses from 6 processors 

and 41 total samples indicates an average wood fuel heat content of 8,260 Btu/pound, and an average 

mercury concentration of 0.10 parts per million, equal to an uncontrolled mercury emission rate of 12.0 

lb/TBtu. In Table 8-3 of this same EPA report, the measured mercury emission rate from biomass-fueled 

spreader stokers (15 points total) had an average of 0.33 ug/dscm, a median of 0.48 ug/dscm, and a 

maximum of 1.01 ug/dscm. In Table 8-5 of this EPA report, the measured mercury emission rate from 

biomass-fueled fluidized bed boilers (3 points total) had an average of 0.26 ug/dscm, and a maximum of 

0.27 ug/dscm. An emission rate of 1.0 ug/dscm is equal to an emission rate of approximately 0.6 pounds 

per trillion Btu. 

The emission factor for mercury emissions from waste wood combustion in the U.S. EPA’s AP-42, 

Compilation of Air Pollutant Emission Factors, 5th Edition, Wood Residue Combustion, Tables 1.6-4, is 

3.5 lb/TBtu, and is given an A rating. This emission factor is also in the U.S. EPA’s FIRE database. 

In January, 2010, a preliminary database of emission test data, continuous emission monitoring system 

(CEMS) data, and fuel analysis data for boilers and process heaters at major sources of HAP was made 

available at http://www2.ergweb.com/projects/combustion/combustiontesting.html. This data includes 

standardized emission data from both the U.S. EPA’s Phase I survey Information Collection Request 

(ICR No. 2286.01) and the Phase II test plan (ICR No. 2286.03). The database included both fuel 

sampling and analysis data for mercury, as well as emission test data for mercury from biomass-fueled 

boilers. The mercury fuel sampling and analysis data included over 500 samples for biomass fuels (with 

descriptions including wood, bark, plywood, particleboard, hog fuel, and biomass). The mercury fuel 

sampling and analysis data ranged from 0.06 lb/trillion Btu to 60 lb/trillion Btu. The database also 

included mercury emission test data. The mercury emission test data included 77 tests on biomass-fueled 

boilers, with emission rates ranging from 0.03 lb/trillion Btu to 5.5 lb/trillion Btu. Eighteen (18) of the 

emission test results indicated mercury emissions below the detection limit of the test. This ICR data is 

plotted in Figure 3 as probability distributions for each data set. The 90% probability for the mercury 

emission rate, based on fuel sampling and analysis, is 6.8 lb/trillion Btu. The 90% probability distribution 

for the mercury emission rate, based on emission testing, is 2.9 lb/trillion Btu. This data suggests that the 

actual mercury emissions are reduced by almost 60% as compared to the uncontrolled, fuel input or 

potential combustion concentration for mercury. 

Based on the available data, we have concluded that the MACT floor for mercury emissions from this 

biomass-fueled boiler is the use of biomass fuels, natural gas, and a fabric filter baghouse. Biomass fuels 

generally have very low mercury levels, with typical mercury in fuel levels of 0.3 to 3.0 pounds per 

trillion Btu of heat input. The resulting emission rate is expected to be 2.9 lb/trillion Btu of heat input, 

equal to 5 micrograms per dry standard cubic meter of exhaust gas. This emission rate represents a 

reasonable estimate of the performance of the “best controlled similar unit” under the worst reasonably 

foreseeable circumstances. 
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FIGURE 3. Mercury (Hg) fuel sampling and analysis and emission test data for biomass 

combustion from the U.S. EPA’s industrial boiler ICR. 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0.0 0.1 1.0 10.0 100.0

Mercury Emission Rate, lb/trillion Btu (lb/TBtu)

Probability Density

Mercury Emission Test Data

Mercury Fuel Sampling Data

90% Probability, 

2.9 lb/TBtu

90% Probability, 

6.8 lb/TBtu

7.4 Beyond-the-Floor Analysis for Mercury. 

In making a case-by-case MACT determination, the permitting authority is expected to look beyond the 

MACT floor, to evaluate whether a greater degree of reduction in emissions is achievable, taking into 

consideration the cost of achieving such emission reductions, and any non-air quality health and 

environmental impacts and energy requirements. The following represents a beyond the floor MACT 

analysis for mercury emissions from this biomass-fueled boiler. 

7.4.1 Potential Mercury Control Technologies. 

As discussed above, biomass fuels generally have very low mercury levels, with typical mercury in fuel 

levels of 0.3 to 3.0 pounds per trillion Btu of heat input. Therefore, mercury emissions from biomassfueled boilers are effectively controlled by the use of these low mercury containing biomass fuels 

combined with the co-benefits of the particulate matter control systems. Although we are not aware of 

any biomass-fueled boiler using post combustion mercury control systems, mercury emissions from 

municipal waste combustors and coal-fueled electric utility steam generating units may also be controlled 
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through mercury-specific control technologies. Based upon available information, mercury specific 

controls include activated carbon injection (ACI), mercury oxidation catalysts, and other controls, 

including halogen injection into the boiler. Development of halogenated powdered activated carbon 

(PAC) sorbents, including brominated PAC, is also underway to improve mercury control performance. 

Both the mercury oxidation catalysts and activated carbon injection systems may be installed upstream of 

the particulate matter control system to enhance mercury capture and control. 

7.4.2 Technically Feasible Mercury Control Technologies. 

7.4.2.1 PM Control Systems and Mercury Control. 

Based on a review of the available information, there is little information on the level of control which 

may be expected from the PM control systems for biomass-fueled boilers. However, there is available 

information for mercury control for coal combustion. According to the U.S. EPA report “Control of 

Mercury Emissions from Coal-Fired Electric Utility Boilers” published in February, 2004, and “Control 

of Mercury Emissions from Coal Fired Electric Utility Boilers: An Update”, published February, 2005, 

emission tests indicated that mercury control efficiencies for coal-fired electric generating units equipped 

with only fabric filter baghouse PM controls averaged 72% and 90% for subbituminous and bituminous 

coal combustion, respectively. By comparison, coal-fired electric generating units equipped with only 

electrostatic precipitator PM controls averaged 3% and 36% for subbituminous and bituminous coal 

combustion, respectively. 

The improved mercury control efficiency for coal-fired boilers using fabric filter baghouses as compared 

to those using electrostatic precipitators is probably due to the increased contact that the flue gas 

experiences with fly ash and unburned carbon on the filter cake of the fabric filter. Figure 4 is a depiction 

of the flue gas flow through the fabric filter bag. The filter cake acts like a fixed-bed reactor, contributing 

to greater mercury oxidation and adsorption. Mercury capture is also related to the levels of halogens in 

the fuel. Higher levels of especially chlorine and bromine in fuels appears to enhance mercury oxidation 

and improve mercury control in PM control systems. 
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FIGURE 4. Depiction of the flue gas flow through the fabric filter baghouse filter cake showing the 

mechanism for particulate collection and mercury control. 

Dust Laden 

Flue Gas

Cleaned Flue Gas 

to Atmosphere

Bag Fabric Layer of Collected 

Ash or "Filter Cake"

RTP Environmental Associates, Inc.

7.4.2.2 Sorbent Injection. 

Mercury emissions from coal-fired boilers and municipal waste combustors may be controlled through 

the injection of mercury sorbents into the flue gas. The most common mercury sorbent system is activated 

carbon injection (ACI). ACI involves the injection of powdered activated carbon (PAC) into the flue gas 

upstream of a PM control system. The sorbent may be injected into the flue gas upstream of the primary 

PM control system, or it may be injected downstream of the primary PM control system and upstream of 

a separate PM control system, usually a pulse jet baghouse, to collect the mercury sorbent separately from 

the fly ash. In this latter arrangement, a system called a Compact Hybrid Particle Collector 

(COHPACTM) may be used. When a COHPAC is combined with sorbent injection, it is called Toxic 

Emission Control (TOXECONTM). 

From 2001 to 2003, the Department of Energy’s National Energy Technology Lab, the Electric Power 

Research Institute (EPRI) and a group of utility companies conducted field test projects with test periods 

of five to ten days to evaluate ACI. The results of these tests are summarized in Table 7. 

Several factors affect the mercury control performance of ACI, including the uncontrolled mercury 

emission rate or concentration, the sorbent injection rate, the flue gas temperature, and the sorbent 

characteristics. Other factors also affect mercury removal, including fabric filter baghouse and bag 

design, and baghouse operation. For ACI, the sorbent injection rate is typically expressed in pounds of 
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sorbent used for each million actual cubic feet of flue gas, or lb/mmACF. For a 50 MW boiler, a sorbent 

injection rate of 1.0 lb/mmACF will correspond to approximately 12 pounds per hour. Flue gas 

temperature is also critical to ACI performance. At temperatures above 350 °F, the mercury capture of 

PAC drops off rapidly. At Salem Harbor, increasing the ESP inlet temperature from 300 to 350°F reduced 

mercury removal from approximately 90% to approximately 10% to 20%. 

TABLE 7. Short term activated carbon injection field test projects. Data from “Control of Mercury 

Emissions from Coal Fired Electric Utility Boilers: An Update”, Table 5. 

Unit Fuel PM Control System Mercury Capture, % 

Baseline With ACI 

PG&E Brayton Point Bituminous Coal Two CS-ESPs in series 90.8% 94.5% 

PG&E Salem Harbor Bituminous Coal CS-ESP 90.0% 94.0% 

WEPCO - Pleasant Prairie Subbituminous Coal CS-ESP 5% 65% 

Alabama Power - Gaston Bituminous Coal HS-ESP + COHPACTM 0 25 – 90% 

Univ. of Illinois - Abbott Bituminous Coal CS-ESP 0 73% 

Finally, the sorbent characteristics can have a significant impact on mercury control performance in coalfired boiler applications. From the above table, the mercury removal performance of plain powdered 

activated carbon is variable, and can be low on low chlorine (or total halogen) containing fuels such as 

subbituminous coal. Adequate halogens in the flue gas appears to improve mercury capture by activated 

carbon injection. This finding has lead to the development of halogenated PAC sorbents. Halogenated 

PACs using bromine or iodine, such as brominated (B-PAC), offer several potential benefits, including 

the potential for lower PAC injection rates and better performance. Longer term, full scale tests on coalfired units indicate mercury removal efficiencies of 70% to 95% at sorbent injection rates ranging from 

0.5 to 6.4 pounds per million cubic feet of flue gas2

. 

While we are not aware of the use of activated carbon injection on any biomass-fueled boiler, based on 

the current coal-fired utility boiler and municipal waste combustor experience, activated carbon injection 

is a technically feasible mercury control alternative for biomass-fueled boilers. However, several factors 

may severely limit the ability of ACI to actually reduce mercury emissions from biomass-fueled boilers. 

The concentration of mercury in biomass is much lower than in coal, municipal solid waste, or refuse 

derived fuel, which means the concentration of mercury in the flue gas will also be much lower. The 

kinetics of the chemical reaction in which activated carbon removes mercury from the flue gas limits the 

ability to control mercury, and limits the ultimate controlled mercury emission rates which may be 

achieved in practice. As the mercury concentration in the flue gas decreases, more carbon is needed to 

 

2

 Longer term, full scale test data is from “Control of Mercury Emissions from Coal Fired Electric Utility Boilers: 

An Update”, Table 7, and “Accumulated Power-Plant Mercury-Removal Experience with Brominated PAC 

Injection”, S. Nelson Jr., R. Landreth, Q. Zhou, and J. Miller, Sorbent Technologies Corporation. Presented at the 

Combined Power Plant Air Pollutant Control Mega Symposium Washington, DC, Aug. 30 – Sept. 2, 2004. 
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remove the diminishing amounts of mercury. For example, the uncontrolled mercury concentrations at 

municipal waste combustors have historically been at 100 μg/dscm and higher (60 lb/trillion Btu); 

uncontrolled mercury at coal fired boilers are at 5 to 20 μg/dscm (3 – 12 lb/trillion Btu). Activated carbon 

is injected at MWCs at a ratio of about 100 parts of carbon to 1 part mercury to achieve 85% removal. 

Due to the lower concentrations and the potential for differing mercury species from biomass combustion, 

far more activated carbon would be required on a molar basis to achieve similar mercury removal 

efficiencies– perhaps as much as 10 times more. This can result in control costs which increase 

exponentially, or it may simply mean that ACI would have little effect in reducing mercury emission 

rates. 

7.4.2.3 Mercury-Specific Catalysts. 

Mercury specific catalysts have been investigated primarily as a method for enhancing mercury capture 

by wet FGD systems in coal-fired electric generating units. These catalysts are intended to oxidize 

elemental mercury to Hg+2 which is soluble in water. Research is underway to evaluate catalysts or 

injection of oxidizing chemicals upstream of wet FGD systems. These approaches are undergoing fullscale evaluation. However, the sulfur dioxide control technology review for this biomass-fueled boiler 

concluded that a wet FGD system is not an economically feasible control technology and does not 

represent BACT for this boiler. Therefore, mercury specific oxidation systems are not technically 

feasible for this boiler. 

7.4.2.4 Addition of Mercury Oxidizing Chemicals. 

As noted in the U.S. EPA report “Control of Mercury Emissions from Coal Fired Electric Utility 

Boilers: An Update”, the addition of chlorine or bromine to the fuel or flue gas is another approach being 

tested for enhancing the capture of mercury in PM and SO2 control systems. However, we are not aware 

of the demonstration of the use of the addition of oxidizing chemicals on any biomass-fueled boiler. 

Because no data or experience is available for biomass-fueled boilers, the addition of oxidizing chemicals 

is not a demonstrated, technically feasible mercury control option. 
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7.4.3 Rank of the Technically Feasible Control Technologies. 

Based upon available information, the only mercury control used on similar, biomass-fueled boilers is the 

use of low mercury containing biomass fuels combined with the use of PM control systems. We are not 

aware of the use of mercury specific controls on any biomass-fueled boilers. Based upon research, 

testing, and experience at coal-fired power plants and municipal waste combustors, mercury emissions 

may also be controlled through mercury-specific control technologies including activated carbon injection 

(ACI), mercury oxidation catalysts, and the addition of mercury oxidizing chemicals in the boiler. Based 

on this analysis, mercury oxidation catalysts and mercury oxidizing chemicals are not technically feasible 

control alternatives. 

7.4.3.1 PM Control Systems and Mercury Control. 

Based upon the mercury MACT floor analysis, biomass fuels generally have very low mercury levels, 

The use of low mercury containing biomass fuels combined with the use of a fabric filter baghouse is 

expected to control mercury emissions to 2.9 lb/trillion Btu of heat input. 

7.4.3.2 Activated Carbon Injection. 

As noted above, we are not aware of the use of activated carbon injection on any biomass-fueled boiler. 

Because the concentration of mercury in biomass is expected to be much lower than in coal, municipal 

solid waste, or refuse derived fuel, the reaction kinetics of the chemical reaction in which activated carbon 

removes mercury from the flue gas will limit the ability of ACI to control mercury. This can result in 

control costs which increase exponentially, or it simply may mean that ACI would have little effect in 

reducing mercury emission rates. 

Based on this review and the fact that activated carbon injection has not been demonstrated on similar 

biomass-fueled boilers, We Energies has concluded that the level of mercury emissions with activated 

carbon injection will be the same as the level of control when firing low mercury containing biomass 

fuels and the use of a fabric filter baghouse. This ranking is summarized in Table 8. 

TABLE 8. Ranking of the technically feasible mercury control technologies. 

Control System Expected Emission Rate, lb/TBtu 

Biomass-Fueled Boiler with Fabric Filter Baghouse 2.9 

Biomass-Fueled Boiler with Fabric Filter Baghouse and 

Activated Carbon Injection 2.9 
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7.4.4 Evaluate the Most Effective Controls. 

From Table 8, we have concluded that based on the available information, the level of mercury emissions 

with activated carbon injection will be the same as the level of control when firing low mercury 

containing biomass fuels and the use of a fabric filter baghouse. Even if we could conclude otherwise, the 

use of activated carbon injection does not represent the case-by-case MACT for this boiler. 

From a cost perspective, the use of an activated carbon injection system would have a capital cost of $40 

– $60 per kW of installed capacity, or $2.0 to $3.0 million for this biomass-fueled boiler3

. Based on a 15 

year project life and an interest rate of 7%, this capital investment would have an annual capital cost of 

more than $200,000 per year. Even if this control system could reduce mercury emissions by 50%, from 

20.3 pounds per year, to 10.2 pounds per year, the cost effectiveness of the activated carbon injection 

system, based only on the capital investment, would be at least $20,500 per pound of mercury controlled. 

This is an extremely high cost, especially since there is no evidence that this level of control could 

actually be achieved. 

The use of activated carbon injection may also adversely impact the potential reuse of the boiler flyash 

which could have substantial environmental impacts and additional economic costs. The biomass-fueled 

boiler is expected to produce about 29,200 tons per year of ash. This ash will be derived from biomass 

fuels, and is anticipated to have value as a soil amendment or fertilizer. However, if sorbent injection 

were to adversely impact the reuse of this ash, the ash may need to be disposed of in a landfill. If the 

avoided landfill cost is $30 per ton of ash, the potential disposal of the ash could increase operating costs 

by $876,000 per year. This increased cost would be in addition to the sorbent injection capital cost. 

Based on the potential impact to ash disposal, the use of activated carbon injection could have an 

economic cost of $86,000 per pound of mercury controlled. 

7.4.5 Beyond the Floor MACT Mercury Conclusion. 

Based upon available information, the only mercury control used on similar, biomass-fueled boilers is the 

use of low mercury containing biomass fuels combined with the use of PM control systems. We are not 

aware of the use of mercury specific controls on any biomass-fueled boilers. While we are not aware of 

the use of activated carbon injection on any biomass-fueled boiler, based on the current coal-fired utility 

boiler and municipal waste combustor experience, activated carbon injection is a technically feasible 

mercury control alternative for biomass-fueled boilers. However, because the concentration of mercury 

in biomass is expected to be much lower than in coal, municipal solid waste, or refuse derived fuel, the 

reaction kinetics of the chemical reaction in which activated carbon removes mercury from the flue gas 

will limit the ability of ACI to control mercury. This can result in control costs which increase 

exponentially, or it simply may mean that ACI would have little effect in reducing mercury emission 

rates. Based on this review and the fact that activated carbon injection has not been demonstrated on 

 

3

 The installed cost for PAC injection is from the U.S. EPA Report, Performance and Cost of Mercury and 

Multipollutant Emission Control Technology Applications on Electric Utility Boilers, EPA-600/R-03/110 October 

2003, page 83, Figure 
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similar biomass-fueled boilers, we have concluded that the level of mercury emissions with activated 

carbon injection will be the same as the level of control when firing low mercury containing biomass 

fuels and the use of a fabric filter baghouse. 

Even if activated carbon injection could reduce mercury emissions by 50%, the cost effectiveness of the 

activated carbon injection system, based only on the capital investment, would be at least $20,500 per 

pound of mercury controlled. Further, the use of activated carbon injection may also adversely impact 

the potential reuse of the boiler flyash which could have substantial environmental impacts and additional 

economic costs. Based on the potential impact to ash disposal, the use of activated carbon injection could 

have an economic cost of $86,000 per pound of mercury controlled. This is an extremely high cost, 

especially since there is no evidence that this level of control could actually be achieved. 

Based on this analysis, we have concluded that the case-by-case MACT for the control of mercury 

emissions from this biomass-fueled boiler is the use of low mercury containing biomass fuels, combined 

with the use of a fabric filter baghouse. 

7.5 Proposed Case-by-Case MACT Limit for Mercury. 

Based on this analysis, We Energies has concluded that the use of biomass fuels and natural gas in 

combination with a fabric filter baghouse represents MACT for the control of mercury emissions from 

this boiler. We Energies proposes the following emission limits as MACT for mercury emissions. 

1. Mercury (Hg) emissions from the circulating fluidized bed boiler shall be 

controlled using biomass fuels in combination with a fabric filter baghouse 

as MACT. 

2. Mercury (Hg) emissions may not exceed 2.9 pounds per trillion Btu of heat 

input.. 

3. Compliance with this emission limit shall be demonstrated using U.S. 

Reference Method 29, or another method approved in writing by the 

Department. 

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Chapter 8. Natural Gas-Fueled 

Boiler Case-by-Case MACT 

Analysis. 

A new natural gas-fueled package boiler will be placed in service as part of this project. This package 

boiler will also be a source of hazardous air pollutants. The package boiler will have a maximum heat 

input capacity of 350 mmBtu/hr. Because the operation of this boiler is normally only required when the 

main CFB boiler is offline, the operation of this boiler is expected to be infrequent. 

8.1 Hazardous Air Pollutant Emissions. 

As with the biomass-fueled boiler, hazardous air pollutants (HAP) emitted from natural gas-fueled boilers 

may be classified in 4 broad categories, including inorganic, solid phase HAPs, inorganic, acid gas HAPs, 

organic HAPs, and mercury. However, potential HAP emissions are much smaller than for the biomassfueled boiler. The potential HAP emissions are summarized in Table 9. Note that total potential HAP 

emissions for this boiler is only 1,844 pounds per year (0.92 tons per year). The HAPs included in the 

analysis are those HAPs that were identified in U.S. EPA’s AP-42, 5th Edition, Natural Gas Combustion, 

Tables 1.4-3 and 1.4-4. 

8.2 U.S. EPA Vacated Industrial Boiler MACT Standards. 

This natural gas-fueled package boiler is generally encompassed within a source category of the Industrial 

Boiler MACT (NESHAP Subpart DDDDD – Industrial, Commercial, and Institutional Boilers and 

Process Heaters), which was promulgated on September 13, 2004. Based on the design heat input rating 

and proposed capacity factor, this boiler would have been considered a new or reconstructed large 

gaseous fuel-fired boiler under this MACT. This subcategory included the following limits: 

Carbon Monoxide.............. 400 ppm by volume on a dry basis corrected to 3% O2 

 (30-day rolling average for units 100 MMBtu/hr or greater) 

On June 8, 2007, the United States Court of Appeals for the District of Columbia Circuit (DC Circuit) 

vacated the Boiler MACT in its entirety. 
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TABLE 9. Potential hazardous air pollutant emissions for the natural gas-fueled package boiler.

Emission Factor Heat Input Potential to Emit Pollutant CAS No. 

lb/106 scf lb/mmBtu mmBtu/hr lb/hr ton/yr 

2-Methylnaphthalene 91-57-6 2.40E-05 2.40E-08 175 0.000004 0.00001 

3-Methylchloranthrene 56-49-5 1.80E-06 1.80E-09 175 0.000000 0.00000 

7,12 Dimethylbenz(a)anthracene 1.60E-05 1.60E-08 175 0.000003 0.00001 

Acenaphthene 83-32-9 1.80E-06 1.80E-09 175 0.000000 0.00000 

Acenaphthylene 203-96-8 1.80E-06 1.80E-09 175 0.000000 0.00000 

Anthracene 120-12-7 2.40E-06 2.40E-09 175 0.000000 0.00000 

Benz(a)anthracene 56-55-3 1.80E-06 1.80E-09 175 0.000000 0.00000 

Benzene 71-43-2 2.10E-03 2.10E-06 175 0.000368 0.00114 

Benzo(a)pyrene 50-32-8 1.20E-06 1.20E-09 175 0.000000 0.00000 

Benzo(b)fluoranthene 205-99-2 1.80E-06 1.80E-09 175 0.000000 0.00000 

Benzo(g,h,i)perylene 191-24-2 1.20E-06 1.20E-09 175 0.000000 0.00000 

Benzo(k)fluoranthene 205-82-3 1.80E-06 1.80E-09 175 0.000000 0.00000 

Chrysene 218-01-9 1.80E-06 1.80E-09 175 0.000000 0.00000 

Dibenzo(a,h)anthracene 53-70-3 1.20E-06 1.20E-09 175 0.000000 0.00000 

Dichlorobenzene 25321-22-6 1.20E-03 1.20E-06 175 0.000210 0.00065 

Fluoranthene 206-44-0 3.00E-06 3.00E-09 175 0.000001 0.00000 

Fluorene 86-73-7 2.80E-06 2.80E-09 175 0.000000 0.00000 

Formaldehyde 50-00-0 7.50E-02 7.50E-05 175 0.013125 0.04069 

Hexane 110-54-3 1.80E+00 1.80E-03 175 0.315000 0.97650 

Indeno(1,2,3-cd)pyrene 193-39-5 1.80E-06 1.80E-09 175 0.000000 0.00000 

Naphthalene 91-20-3 6.10E-04 6.10E-07 175 0.000107 0.00033 

Phenanathrene 85-01-8 1.70E-05 1.70E-08 175 0.000003 0.00001 

Pyrene 129-00-0 5.00E-06 5.00E-09 175 0.000001 0.00000 

Toluene 108-88-3 3.40E-03 3.40E-06 175 0.000595 0.00184 

Hydrogen chloride 1.24E-05 175 0.002170 0.00673 

Arsenic 7440-38-2 2.00E-04 2.00E-07 175 0.000035 0.00011 

Barium 7440-39-3 4.40E-03 4.40E-06 175 0.000770 0.00239 

Beryllium 7440-41-7 1.20E-05 1.20E-08 175 0.000002 0.00001 

Cadmium 7440-43-9 1.10E-03 1.10E-06 175 0.000193 0.00060 

Chromium 7440-47-3 1.40E-03 1.40E-06 175 0.000245 0.00076 

Cobalt 7440-48-4 8.40E-05 8.40E-08 175 0.000015 0.00005 

Copper 7440-50-8 8.50E-04 8.50E-07 175 0.000149 0.00046 

Manganese 7439-96-5 3.80E-04 3.80E-07 175 0.000067 0.00021 

Mercury 7439-97-6 2.60E-04 2.60E-07 175 0.000046 0.00014 

Molybdenum 7439-98-7 1.10E-03 1.10E-06 175 0.000193 0.00060 

Nickel 7440-02-0 2.10E-03 2.10E-06 175 0.000368 0.00114 

Selenium 7782-49-2 2.40E-05 2.40E-08 175 0.000004 0.00001 

Vanadium 7440-62-2 2.30E-03 2.30E-06 175 0.000403 0.00125 

TOTAL, All HAPs, pounds per year 1.04 

Footnotes 

The emission factors are for natural gas combustion in the U.S. EPA’s AP-42, Compilation of Air Pollutant 

Emission Factors, 5th Edition, Natural Gas Combustion, Tables 1.4-3 and 1.4-4 
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8.3 Inorganic Solid Phase HAPs. 

Inorganic, solid phase HAP emissions occur from natural gas combustion as trace substances in the fuel. 

From Table 9, inorganic, solid phase HAPs include arsenic, beryllium, cadmium, chromium, copper, lead, 

manganese, nickel, selenium, and vanadium. These substances are emitted in solid form. The amount of 

ash, and the amount of these trace inorganic substances in natural gas are extremely small. The Control 

Technology Review for PM and PM10 for this boiler includes a detailed discussion on PM control for this 

boiler. We Energies has proposed a particulate matter and PM10 emission limit for the auxiliary boiler of 

0.0075 pounds per million Btu of heat input, averaged over any 3-hour period. This limit is more 

stringent than the now vacated applicable PM/PM10 of 0.03 lb/mmBtu for new, large liquid fuel boilers 

and limited use liquid fuel boilers of 0.03 lb/mmBtu. There are no PM standards for natural gas-fueled 

boilers. Based on this analysis, the use of PM10 emissions as a surrogate for emissions of inorganic 

HAP’s represents the case-by-case MACT floor for inorganic, solid phase HAP emissions from the 

natural gas-fueled boiler. 

8.3.1 Beyond the Floor Inorganic Solid Phase HAP MACT Analysis. 

The best control method, based upon available information, used to control inorganic, solid phase HAP 

emissions from natural gas-fueled industrial boilers is limiting fuels to gaseous fuels. As a result, We 

Energies has concluded that further control beyond the use of natural gas is not technically feasible. 

8.3.2 Proposed Case-by-Case MACT for Inorganic, Solid Phase HAPs. 

Based on this analysis, We Energies has concluded that the use of natural gas and the proposed BACT 

PM10 emission limit represent the maximum achievable control technology for solid phase, inorganic 

HAPs from the natural gas-fueled package boiler. We Energies proposes that the BACT compliance 

demonstration requirements for PM10 will also demonstrate compliance with the MACT requirements for 

this unit, so that no other requirements are necessary for this HAP category. 

8.4 Inorganic Acid Gas HAPs. 

Inorganic, vapor phase HAPs including hydrochloric and hydrofluoric acids are formed from chlorine and 

fluorine in the fuel. From the memo from Christy Burlew and Roy Oommen, Eastern Research Group to 

Jim Eddinger, U.S. EPA, OAQPS, October, 2002, Development of Average Emission Factors and 

Baseline Emission Estimates for the Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standard for Hazardous Air Pollutants, Appendix A, the HCl emission factor 

for natural gas combustion is 1.24 x 10-5 lb/mmBtu. This emission rate is about 1 percent of the (now 

vacated) HCl MACT limit for new, large liquid fuel boilers of 0.0009 lb/mmBtu. Potential HCl 

emissions are only 16.3 pounds (0.008 tons) per year. 
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8.4.1 Beyond the Floor HCl MACT Analysis. 

The only known control method, based upon available information, used to control acid gas emissions 

from natural gas-fueled boilers is the use of natural gas as a fuel. Based on the information reviewed, flue 

gas desulfurization systems have never been used on natural gas or distillate fuel oil-fired boilers. Even if 

FGD was used, there is no data or information to suggest that HCl emissions could be reduced below the 

expected emission rate of 0.0000124 lb/MMBtu. Therefore, We Energies has concluded that the further 

control beyond the use of natural gas is not technically feasible. 

8.4.2 Proposed Case-by-Case MACT HCl Emission Limit. 

This package boiler will fire only natural gas. Restricting the fuels used in these boilers to only natural 

gas represents MACT for HCl emissions. Therefore, We Energies proposes restricting fuels used in this 

boiler to only natural gas as the case-by-case MACT limit for HCl emissions. 

8.4.3 Hydrogen Fluoride 

Hydrogen fluoride emissions from natural gas combustion are expected to be extremely small. We 

Energies was not able to identify actual fluoride emissions data for distillate fuel oil or natural gas 

combustion. 

8.4.4 Beyond the Floor HF MACT Analysis. 

As with HCl emissions, the only known control method used to control acid gas emissions from natural 

gas-fueled boilers is the use of natural gas as the fuel. We Energies has concluded that the further control 

beyond the use of natural gas is not technically feasible. 

8.4.5 Proposed Case-by-Case MACT HF Emission Limit. 

This package boiler will fire only natural gas. Restricting the fuels used in this boiler to only natural gas 

represents MACT for HF emissions. Therefore, We Energies proposes restricting fuels used in this boiler 

to only natural gas as the case-by-case MACT limit for HF emissions. 

8.5 Organic HAPs. 

Organic HAPs are emitted from natural gas combustion as a result of incomplete combustion. A detailed 

discussion of control options for CO and volatile organic compound (VOC) emissions is included in the 

control technology review. According to the U.S. EPA’s AP-42, potential organic HAPs resulting from 

natural gas combustion include 24 organic compounds, including polycyclic aromatic compounds, 

formaldehyde, hexane, and toluene. Hexane actually accounts for approximately 94% of all HAP 

emissions from natural gas combustion. These organic HAPs may be considered as a subset of the 

general class of organic compounds referred to VOC. As a result, minimizing VOC emissions will also 

minimize organic HAP emissions. 

The use of CO or VOC emissions as a surrogate for the control of organic HAP emissions is consistent 

with the U.S. EPA’s practice when establishing MACT standards for combustion source categories 
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emitting organic HAP’s. For example, in the preamble for the “National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters.” 69 

Fed. Reg. 55218, September 13, 2004, the U.S. EPA stated: “Because CO is a good indicator of 

incomplete combustion, there is a direct correlation between CO emissions and the formation of organic 

HAP emissions. Monitoring equipment for CO is readily available, which is not the case for organic 

HAP. Also, it is significantly easier and less expensive to measure and monitor CO emissions than to 

measure and monitor emissions of each individual organic HAP. Therefore, using CO as a surrogate for 

organic HAP is a reasonable approach because minimizing CO emissions will result in minimizing 

organic HAP emissions.” 

For this natural gas-fueled package boiler, We Energies has proposed a best available control technology 

CO emission limit of 0.0375 lb/mmBtu, and a VOC emission limit of 0.005 lb/MMBtu, achieved through 

good combustion practices. Because the organic HAPs are controlled in the same manner as CO and 

VOC emissions, the proposed use of good combustion practices and the CO (or VOC) BACT emission 

limit represents the maximum degree of reduction in HAP emissions which can be achieved by utilizing 

this control technology for a natural gas-fueled boiler. This analysis indicates that the use of CO or VOC 

emissions as a surrogate for emissions of organic HAP’s represents the case-by-case MACT floor for 

organic HAP emissions from this boiler. 

8.5.1 Beyond the Floor Organic HAP MACT Analysis. 

The only known control method, based upon available information, to control organic HAP emissions 

from natural gas-fueled boilers is good combustion practices. Based on the information available to We 

Energies, no post combustion controls have been required as MACT for similar boilers. While no other 

controls have been required for similar boilers, other potential VOC control systems include oxidation 

catalysts and thermal oxidation. 

8.5.1.1 Oxidation Catalysts. 

While oxidation catalysts are feasible for reducing CO emissions from natural gas-fueled boilers, there is 

limited data available on the potential to reduce HAP emissions using oxidation catalysts in natural gasfueled boilers. The low excess oxygen levels and low temperatures of the flue gas make oxidation 

catalysts less effective than in combustion turbine applications which have high gas temperatures and 3 – 

5 times higher excess oxygen levels. 

8.5.1.2 Thermal Oxidation 

Based on the information reviewed, thermal oxidation has never been required or used on a natural gasfueled boiler, and its ability to reduce HAP emissions is questionable. Thermal oxidation would involve 

injecting additional air into the flue gas and heating the mixture to approximately 1,500 o

F to oxidize 

organic HAPs to carbon dioxide. However, since the combustion of the reheat fuel would also result in 

HAP emissions in the same manner as the combustion of the primary fuel creates organic HAPs, there is 

no evidence that thermal oxidation would result in any reduction in HAP emissions. Since thermal 

oxidation has never been demonstrated on an Gas-fired boiler, and because there is no evidence that it 
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could reduce HAP emissions, thermal oxidation is not technically feasible for the control of HAP 

emissions from this package boiler. 

Based on this review, We Energies has concluded that further control beyond the use of good combustion 

practices is not technically feasible. 

8.5.2 Proposed Case-by-Case MACT Limit for Organic HAPs. 

Based on this analysis, We Energies has concluded that the proposed BACT CO emission limits and use 

of good combustion practices also represent MACT for organic HAPs from the natural gas-fueled 

package boiler, so that no other requirements are necessary for this HAP category. 

8.6 Mercury 

Mercury emissions from natural gas combustion are also expected to be very small. From the U.S. EPA 

document AP-42, Compilation of Air Pollutant Emission Factors, 5th Edition, Table 1.4-4, mercury 

emissions from natural gas combustion are expected to be 0.26 pounds per trillion Btu. This appears to 

be a conservative (high) emission factor which results in potential mercury emissions of 0.34 pounds per 

year. 

Our review of the U.S. EPA’s RACT/BACT /LAER Clearinghouse to determine the best performing 

similar units did not show any similar natural gas-fueled boilers with specific mercury emission limits. 

To limit mercury emissions from similar sources, regulatory agencies have restricted the allowable fuels 

to only natural gas and distillate fuel oil – low mercury containing fuels. Therefore, the use of only 

natural gas represents the MACT floor for mercury. 

8.6.1 Beyond the Floor Mercury MACT Analysis. 

The only known control method, based upon available information, used to control mercury emissions 

from natural gas-fueled boilers is the use of these low mercury containing fuels. We Energies has 

concluded that the further control beyond the use of natural gas as a fuel is not technically feasible. 

8.6.2 Proposed Case-by-Case MACT Mercury Emission Limit. 

This package boiler will fire only natural gas. Restricting the fuels used in this boiler to only natural gas 

represents MACT for mercury emissions. Therefore, We Energies proposes restricting fuels used in this 

boiler to only natural gas as the case-by-case MACT limit for mercury emissions from this package 

boiler. 
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Appendix D: Case-by-Case MACT Analysis Under Section 112(g) of the CAA March, 2010

- 49 - 

Attachment 1. 

TABLE 1. Potential hazardous air pollutant emissions for the biomass-fired boiler B01 (2 pages). 

Emission 

Factor 

Heat Input 

Capacity HAP Potential to Emit 

Category Hazardous Air Pollutant 

lb/mmBtu mmBtu/hr lb/hr ton/yr 

Antimony 7.9E-06 800 0.006 0.028 

Arsenic 2.2E-05 800 0.018 0.077 

Beryllium 1.1E-06 800 0.001 0.004 

Cadmium 4.1E-06 800 0.003 0.014 

Chromium, total 2.1E-05 800 0.017 0.074 

Chromium, hexavalent 3.5E-06 800 0.003 0.012 

Cobalt 6.5E-06 800 0.005 0.023 

Lead 4.8E-05 800 0.038 0.168 

Manganese 1.6E-03 800 1.280 5.606 

Nickel 3.3E-05 800 0.026 0.116 

Phosphorus 2.7E-05 800 0.022 0.095 

Inorganic, Solid Phase 

Selenium 2.8E-06 800 0.002 0.010 

Inorganic Hydrogen chloride 0.018 800 14.4 63.1 

Acid Gases Hydrogen fluoride 0.001 800 0.8 3.5 

Acetaldehyde 8.3E-04 800 0.664 2.908 

Acetophenone 3.2E-09 800 0.0000 0.000 

Acrolein 7.5E-05 800 0.0601 0.263 

Benzene 4.2E-03 800 3.360 14.717 

Benzo(a)anthracene 6.5E-08 800 0.000052 0.000 

Benzo(a)pyrene 2.6E-06 800 0.002080 0.009 

Benzo(b)fluoranthene 1.0E-07 800 0.000080 0.000 

Benzo(e)pyrene 2.6E-09 800 0.000002 0.000 

Benzo(g,h,i)perylene 9.3E-08 800 0.000074 0.000 

Benzo(j,k)fluoranthene 1.6E-07 800 0.000128 0.001 

Benzo(k)fluoranthene 3.6E-08 800 0.000029 0.000 

bis(2-Ethylhexyl)phthalate 4.7E-08 800 0.000038 0.000 

Bromomethane (Methyl bromide) 1.5E-05 800 0.012 0.053 

2-Butanone (MEK) 5.4E-06 800 0.004 0.019 

Carbon tetrachloride 4.5E-05 800 0.036 0.158 

Chlorine 7.9E-04 800 0.632 2.768 

Chlorobenzene 3.3E-05 800 0.026 0.116 

Chloroform 2.8E-05 800 0.022 0.098 

Chloromethane (Methyl chloride) 2.3E-05 800 0.018 0.081 

Dibenzo(a,h)anthracene 9.1E-09 800 0.000 0.000 

Organic 

1,2-Dibromoethene 5.5E-05 800 0.044 0.193 

 
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Appendix D: Case-by-Case MACT Analysis Under Section 112(g) of the CAA March, 2010

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TABLE 1. Potential hazardous air pollutant emissions for the biomass-fired boiler B01 (2 pages). 

Emission 

Factor 

Heat Input 

Capacity HAP Potential to Emit 

Category Hazardous Air Pollutant 

lb/mmBtu mmBtu/hr lb/hr ton/yr 

Dichlorobiphenyl (PCB) 7.4E-10 800 

Heptachlorobiphenyl (PCB) 6.6E-11 800 

Hexachlorobiphenyl (PCB) 5.5E-10 800 

Monochlorobiphenyl (PCB) 2.2E-10 800 

Pentachlorobiphenyl (PCB) 1.2E-09 800 

Tetrachlorobiphenyl (PCB) 2.5E-09 800 

Trichlorobiphenyl (PCB) 2.6E-09 800 

Total Polychlorinated biphenyls (PCB) 7.9E-09 800 0.000006 0.000 

Total Equiv. 2,3,7,8 TCDD (Dioxins) 3.0e-9 800 0.000002 0.00001 

1,2−Dichloroethane (EDC) 2.9E-05 800 0.023 0.102 

Dichloromethane 2.9E-04 800 0.232 1.016 

1,2-Dichloropropane 3.3E-05 800 0.026 0.116 

2,4-Dinitrophenol 1.8E-07 800 0.000 0.001 

Ethyl benzene 3.1E-05 800 0.025 0.109 

Formaldehyde 4.4E-03 800 3.520 15.418 

Indeno(1,2,3,c,d)pyrene 8.7E-08 800 0.00006960 0.000 

2-Methylnaphthalene 1.6E-07 800 0.00012800 0.001 

Naphthalene 9.7E-05 800 0.078 0.340 

4-Nitrophenol 1.1E-07 800 0.0000880 0.000 

Pentachlorophenol (PCP) 5.1E-08 800 0.0000408 0.000 

Phenol 5.1E-05 800 0.041 0.179 

Propanal (Propionaldehyde) 3.2E-06 800 0.003 0.011 

Propionaldehyde 6.1E-05 800 0.049 0.214 

Styrene 1.9E-03 800 1.520 6.658 

Tetrachloroethene (Perchloroethylene) 3.8E-05 800 0.030 0.133 

Toluene 9.2E-04 800 0.736 3.224 

1,1,1-Trichloroethane 3.1E-05 800 0.025 0.109 

Trichloroethene 3.0E-05 800 0.024 0.105 

Trichlorofluoromethane (CFC−11) 4.1E-05 800 0.033 0.144 

2,4,6-Trichlorophenol 2.2E-08 800 0.000 0.000 

Vinyl Chloride 1.8E-05 800 0.014 0.063 

Organic 

o-Xylene 2.5E-05 800 0.020 0.088 

 Mercury 2.9E-06 800 0.002 0.010 

 TOTAL 122.2 

Footnotes 

1. The emission factors are for waste wood combustion in the U.S. EPA’s AP-42, Compilation of Air Pollutant 

Emission Factors, 5th Edition, Wood Residue Combustion, Tables 1.6-3 and 1.6-4. 
Prevention of Significant Deterioration 

Air Pollution Control Construction Permit Application 

Appendix E. 

Air Quality Impact Analysis. 

 

50 MW Biomass-Fired Cogeneration Facility to be 

Located at the Domtar – Rothschild Mill.

March, 2010 

Prepared for: 

We Energies 

231 W. Michigan St. 

Milwaukee, WI 53203 

Prepared By: 

 

RTP ENVIRONMENTAL ASSOCIATES INC.® 

903 Superior Avenue, Suite 6 

Tomah, WI 54660 

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Appendix E: Air Quality Impact Analysis. March, 2010

2

Executive Summary 

This document is the Prevention of Significant Deterioration (PSD) air quality impact analysis for We 

Energies’ 50 MW Biomass Fuels Cogeneration Facility to be located at the Domtar – Rothschild Mill. 

This Project will involve the installation of a one new biomass-fired boiler and two new natural gas-fired 

package boilers. To support the biomass-fired boiler, the Project will require new biomass fuel handling 

equipment, biomass boiler ash handling equipment, a new cooling tower, and a new diesel engine driven 

feed water pump. Under the Prevention of Significant Deterioration (PSD) program in NR 405.02(22)(a), 

Wis. Adm. Code, the major stationary source threshold for this facility is 100 tons per year. Based on the 

potential emissions, the Project will be a major PSD source and require PSD air quality analyses for 

carbon monoxide (CO), nitrogen oxides (NOX), particulate matter (PM/PM10), particulate matter less than 

2.5 microns in size (PM2.5), and sulfur dioxide (SO2). 

The air quality analysis utilizes air quality dispersion computer models along with monitored background 

air quality data to evaluate compliance with the National Ambient Air Quality Standards (NAAQS), Class 

II and Class I PSD increments, and state of Wisconsin Total Suspended Particulate (TSP) standard. In 

addition, other PSD air analysis requirements include an evaluation of impacts on soils, vegetation, and 

visibility, an associated growth analysis, and if necessary, Class I visibility and air quality related values 

(AQRV) analyses. The procedures used for all air quality impact analyses were consistent with relevant 

EPA and DNR guidance. 

PSD modeling analyses are typically conducted in two steps: a “project-only” significant impact analysis, 

and if required a cumulative impact or “multi-source” analysis. If the “project-only” analysis indicates 

that air impacts are below the Significant Impact Level (“SIL”) for a pollutant, the Project is determined 

to have an insignificant impact and further air quality analysis is not required for that pollutant. If the 

“project-only” impacts exceed a SIL, a cumulative impact analysis is then performed for that pollutant. 

The cumulative impact analysis considering emissions from the proposed Project as well as from other 

nearby existing or permitted sources, and also considers the effect of emissions from natural, distant, and 

unidentified sources through the use of background air quality data. 

The significant impact analysis of the Project emissions indicates that CO, NO2, and the annual SO2

impacts are all below the corresponding SILs. Therefore, no further analysis is necessary for these 

pollutants. Cumulative impact modeling was performed for SO2 3-hr and 24-hr averages, all PM10 and 

PM2.5 averaging periods, and the 24-hr state TSP standard. EPA has not developed 1-hr NO2 SILs to 

determine when a cumulative 1-hr NO2 NAAQS analysis is required. Therefore, even though the annual 

NO2 impacts from the Project are insignificant, a cumulative 1-hr NO2 NAAQS analysis was performed. 

The results of the cumulative NAAQS analysis are summarized in Table ES-1, and the results of the 

cumulative Class II PSD increment analysis are summarized in Table ES-2. These analysis results 

demonstrate that the Project will not cause or contribute to air quality impacts that exceed the NAAQS, 

PSD increments, or the Wisconsin TSP standard. 
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Appendix E: Air Quality Impact Analysis. March, 2010

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TABLE ES-1. Cumulative NAAQS modeling results. 

Pollutant Averaging 

Interval 

Cumulative 

Impact, 

μg/m3 

Background, 

μg/m3

Total, 

μg/m3

NAAQS 

μg/m3 % of NAAQS

NO2 1-hour 61 11.9 73.2 188 39% 

24-hour 249 11.2 260.2 365 71% 

SO2

3-hour 951 11.8 962.8 1300 74% 

PM10 24-hour 41.8 29.4 71.2 150 47% 

Annual 2.3 8.7 11 15 73% 

PM2.5

24-hour 9.0 25.6 34.6 35 99% 

TSP 24-hour 103.6 39.7 143.3 150 96% 

Lead 3 month 0.00066 0.01 0.01066 0.15 7% 

TABLE ES-2. Cumulative PSD Increment Modeling Results. 

Pollutant Averaging 

Interval 

Maximum 

Impact, μg/m3

PSD Increment 

μg/m3

% of PSD 

Increment 

Annual 5.7 17 34% 

PM10

24-hour 21.0 30 70% 

24-hour 86.1 91 95% 

SO2

3-hour 300 512 58% 

The PSD requirements include an analysis of the potential impact the Project on visibility, soils, and 

vegetation, as well as the impact of general commercial, residential, and industrial growth associated with 

the Project. The dispersion modeling analysis demonstrated that the project ambient impacts do not 

exceed the NAAQS nor other EPA screening thresholds, and therefore there are no harmful effects to 

vegetation and soils. A visibility analysis indicates that steam and water plumes may be visible on the 

order of a few hours per year. The Project is not expected to have a measurable effect on residential, 

commercial, or industrial growth because of the current large local population and amount of industrial 

and commercial activity in the Project area. 

Wisconsin has two Class I PSD areas, the Rainbow Lake Area located approximately 200 km distant from 

the Project, and the Forest County Potawatomi Area located approximately 99 km distant. Based on the 

potential emissions of the Project and these distances to the Class I areas, a Class I air quality analysis is 

not required for either of the Wisconsin Class I areas. 
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Appendix E: Air Quality Impact Analysis. March, 2010

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Table of Contents 

Chapter 1. Introduction. ........................................................................................6

Chapter 2. Summary of Modeling Procedures. .................................................12

2.1 Near-field Model Selection............................................................................................................12

2.2 Building Downwash Effects. .........................................................................................................13

2.3 Urban Versus Rural Dispersion .....................................................................................................13

2.4 Meteorological Data.......................................................................................................................14

2.5 Receptor Data. ...............................................................................................................................14

2.6 NO2 Conversion Methodology.......................................................................................................17

2.7 Background Air Quality Data ........................................................................................................17

2.8 Model Design Concentrations........................................................................................................19

Chapter 3. Emission and Stack Data. .................................................................20

3.1 Project Emission and Stack Data. ..................................................................................................20

3.2 Other Nearby Sources for Cumulative Analyses. ..........................................................................20

3.2.1 Domtar Sources................................................................................................................. 23

3.2.2 Lignotech Sources............................................................................................................. 25

3.2.3 Weston Power Plant Boilers. ............................................................................................ 25

3.3 PSD Increment Emissions and Baseline Dates..............................................................................25

Chapter 4. Air Quality Analysis Results. ...........................................................26

4.1 Significant Impact Analysis...........................................................................................................26

4.2 Cumulative NAAQS and PSD Increment Analysis.......................................................................26

4.2.1 Cumulative PSD Increment Analysis. .............................................................................. 28

Chapter 5. Additional Impacts Analysis. ...........................................................29

5.1 Analysis on Soils, Vegetation, and Visibility. ...............................................................................29

5.2 Associated Growth and Secondary Emissions...............................................................................30

Chapter 6. Class I Air Quality Analysis. ............................................................31
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Appendix E: Air Quality Impact Analysis. March, 2010

5

Table of Contents (continued) 

Figures 

FIGURE 1-1. Locus map for We Energies’ proposed 50 MW biomass-fired cogeneration facility. ..........8

FIGURE 1-2. USGS location map for We Energies’ 50 MW biomass-fired cogeneration facility. ...........8

FIGURE 1-3. Artist Rendering of the Facility Layout. .............................................................................10

FIGURE 2-1. Main AERMAP Receptor Grid. ..........................................................................................15

FIGURE 2-2. Close-in PM AERMAP Receptor Grid. ..............................................................................16

FIGURE 3-1. Modeled Layout and 3-Dimension BPIP-PRIME View of the Project...............................22

Tables 

TABLE 1-1. List of Project Emission Units. ...............................................................................................6

TABLE 1-2. Project PSD applicability........................................................................................................7

TABLE 1-3. NAAQS, Significant Impact Levels, and PSD Class II Increment, μg/m3. ........................11

TABLE 2-1. Background Concentration Data, μg/m3. .............................................................................18

TABLE 3-1. Project Stack Parameters and Emission Data. ......................................................................21

TABLE 3-2. Domtar PM2.5 Emission Calculations. ..................................................................................23

TABLE 3-3. Weston PM2.5 Emission Calculations. ..................................................................................25

Appendices 

Appendix A – Summary of Cumulative Source Inventory Emissions and Stack parameters 
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Appendix E: Air Quality Impact Analysis. March, 2010

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Chapter 1. Introduction. 

This document is the air quality impact analysis for We Energies’ 50 MW Biomass Fuels Cogeneration 

Facility (the Project) to be located at the Domtar – Rothschild Mill. The Project will be a combined heat 

and power facility that produce 50 MW of electric power and will also provide process steam to the 

Domtar Mill. The Project will involve the installation of one new biomass-fired boiler and two new 

natural gas-fired package boilers. To support these new boilers, the Project will include new biomass fuel 

handling equipment, biomass boiler ash handling equipment, a new cooling tower, and a new diesel 

engine driven emergency feed water pump. A list of these Project emission units is included in Table 1-1. 

TABLE 1-1. List of Project Emission Units. 

Source 

ID 

Process 

ID Description 

S01 B01 Biomass-fired Circulating Fluidized Bed Boiler 

S02 B02 Natural Gas-Fired Package Boiler (Note B02 and B03 use a common stack) 

S03 B03 Natural Gas-Fired Package Boiler (Note B02 and B03 use a common stack) 

S121 P121 Biomass Fuels Unloading, Screening, Hogging, and Conveying Dust Collector 

S122 F122 Self Unloading Truck Biomass Fuels Unloading 

S123 F123 Biomass Fuels Storage and Reclaim 

S124 P124 Two Boilerhouse Fuel Storage Silos 

S125 F125 Biomass Fuels Delivery Truck Haul Roads (Note combined with F133 emissions 

in modeling analysis) 

S131 P131 CFB Boiler Bed Material Silo 

S132 P132 CFB Boiler Ash Silo 

S133 F133 Boiler Ash Haul Roads (Note that this source was combined with F125 emissions 

in the dispersion modeling analysis.) 

S141 P141 Cooling Tower 

S151 P151 Emergency Diesel Engine Feed Water Pump 
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Appendix E: Air Quality Impact Analysis. March, 2010

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Figure 1-1 is a locus map for the proposed facility. Figure 1-2 shows the location of the facility on the 

USGS 7.5 minute map for the proposed location which is located near the Wisconsin River in Rothschild. 

Figure 1-3 is an artist rendering of the layout of the facility, showing existing structures and the new 

boilerhouse, fuel storage building, conveyors, and cooling towers. 

Table 1-2 is a summary of the potential emissions for the Project based on the proposed control 

technologies and emission limits. Under the Prevention of Significant Deterioration (PSD) program in 

NR 405.02(22)(a), Wis. Adm. Code, the major stationary source threshold for this facility is 100 tons per 

year. Based on the total potential emissions in Table 1-2, the Project will be subject to the PSD program 

for carbon monoxide (CO), nitrogen oxides (NOX), particulate matter (PM/PM10), fine particulate matter 

(PM2.5), sulfur dioxide (SO2), organic compounds (VOC), and fluorides (as HF). 

TABLE 1-2. Project PSD applicability. 

Potential to Emit, ton/year 

 POLLUTANT Boiler 

B01 

Boilers 

B02 & B03

Diesel 

Pump 

Material 

Handling

Cooling 

Tower TOTAL 

PSD 

Significant 

Threshold

OVER?

Carbon Monoxide CO 700.8 65.1 0.11 766 100 YES 

Nitrogen Oxides NOx 350.4 21.7 0.13 372 40 YES 

Particulate Matter PM10 105.1 8.2 0.007 17.1 0.3 131 15 YES 

Particulate Matter PM2.5 80.6 8.2 0.005 8.4 0.0009 97 10 YES 

Sulfur Dioxide SO2 315.4 0.7 0.0003 316 40 YES 

Organic Compounds VOC 59.6 6.5 0.13 66 40 YES 

Lead Pb 0.11 0.0005 0.000002 0.11 1 NO 

Mercury Hg 0.01 0.0003 0.000001 0.01 N/A 

Fluorides (as HF) HF 3.5 0.7 0.000045 4.2 3 YES 

Sulfuric Acid Mist H2SO4 6.3 0.007 0.000025 6.3 7 NO 

Based on this PSD applicability analysis, PSD air quality impact analyses are required for SO2, NOX, 

PM10/PM2.5, and CO. The generation of the regional pollutant ozone is a complex photochemical process, 

and EPA has not approved an air quality model to determine single-source impacts on regional ozone 

concentrations. Therefore, an ozone dispersion modeling analysis is not required. 
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Appendix E: Air Quality Impact Analysis. March, 2010

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FIGURE 1-1. Locus map for We Energies’ proposed 50 MW biomass-fired cogeneration facility. 

We Energies Biomass 

Cogeneration Facility 

NORTH

Scale, miles

5 0 5 10
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Appendix E: Air Quality Impact Analysis. March, 2010

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FIGURE 1-2. USGS location map for We Energies’ 50 MW biomass-fired cogeneration facility.

We Energies Biomass 

Cogeneration Facility 
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Appendix E: Air Quality Impact Analysis. March, 2010

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FIGURE 1-3. Artist Rendering of the Facility Layout.

Biomass Fuels 

Storage Building 

New Boilerhouse 

and Stack S01 

New Cooling 

Tower 

Existing Mill 

Existing Mill 
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Appendix E: Air Quality Impact Analysis. March, 2010

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The air quality impact analysis utilizes air quality dispersion computer models, and monitored 

background air quality data, to evaluate compliance with the National Ambient Air Quality Standards 

(“NAAQS”) and Class II and Class I PSD increments (“increment”). In addition, the PSD requirements 

include analyses of impacts on soils and vegetation, a Class II visibility analysis, an associated growth 

analysis, and if necessary, Class I visibility and air quality related values (AQRV) analyses. The 

applicable NAAQS , increments, and Significant Impact Level (“SIL”) are summarized in Table 1-3. 

TABLE 1-3. NAAQS, Significant Impact Levels, and PSD Class II Increment, μg/m3. 

Pollutant Averaging 

Period NAAQS Class II SIL PSD Class II Increment 

Nitrogen Oxides Annual 100 1 25 

(NO2) 1-hour 188 n/a n/a 

8-hour 10,000 500 n/a Carbon 

Monoxide (CO) 1-hour 40,000 2000 n/a 

Annual 50 1 17 Particulate Matter 

(PM10) 24-hour 150 5 30 

Annual 15 0.3 n/a Particulate Matter 

(PM2.5) 24-hour 35 1.2 n/a 

Total Suspended 

Particulate (TSP) 24-hour 150 n/a n/a 

Annual 80 1 20 

24-hour 365 5 91 Sulfur Dioxide 

(SO2) 

3-hour 1,300 25 512 

3-month 0.15 n/a n/a 

Lead 

Quarterly 1.5 n/a n/a 

Footnotes 

The SILs listed for PM2.5 are the lowest of EPA’s currently proposed values. The state of Wisconsin maintains a 

secondary 24-hr Total Suspended Particulate (TSP) air quality standard. 

 
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Appendix E: Air Quality Impact Analysis. March, 2010

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Chapter 2. Summary of Modeling Procedures. 

EPA guidance for performing PSD air quality analyses is described in Chapter C of EPA’s “New Source 

Review Workshop Manual”, Draft - October 1990, in EPA's "Guideline on Air Quality Models”, 40 CFR 

Part 51 Appendix W (herein referred to as the GAQM), in EPA’s “AERMOD Users Guide” and related 

addendums, and in EPA’s “AERMOD Implementation Guide”, updated March 19, 2009. The Wisconsin 

Department of Natural Resources (DNR) guidance for performing PSD air quality analyses is described in 

the “WDNR Dispersion Modeling Guidelines”, dated July 2009. All modeling procedures used for the 

Project air quality impact analyses are consistent with this EPA and DNR guidance. 

PSD modeling analyses are typically conducted in two steps: a “project-only” significant impact analysis, 

and if required a cumulative impact or “multi-source” analysis. The significant impact analysis first 

estimates ambient impacts resulting from emissions from only the proposed Project (and only for those 

pollutants with Project emission increases above the PSD Significant Emission Rates). When the 

maximum ambient concentrations of a pollutant are below the Significant Impact Level (“SIL”) for all 

averaging periods, the emissions from the proposed source are not expected to have a significant impact 

on ambient air concentrations and further air quality analysis is not required. If the source's ambient 

impacts exceed the SIL for any pollutant and averaging interval, the extent of the geographical area in 

which the source exceeds the SIL is determined (referred to as the Significant Impact Area [SIA]), and a 

cumulative impact analysis is performed for that pollutant, averaging interval, and SIA. The cumulative 

impact analysis expands the significant impact analysis by considering emissions from both the proposed 

source as well as other nearby existing or permitted sources, and also considers the combined effect of 

emissions from natural, distant, and unidentified sources through the use of background air quality data. 

If the cumulative impact analysis demonstrates violations of any NAAQS or PSD increment, the proposed 

source can still be permitted if it can be demonstrated that the emissions from the proposed source do not 

result in ambient impacts that exceed the SIL at the same time and location of any modeled violation. In 

other words, the proposed source must demonstrate that it would not "significantly contribute" to any 

modeled violation. 

2.1 Near-field Model Selection. 

There are two levels of sophistication of atmospheric dispersion computer models that can be used for the 

air quality analysis within 50 km of the facility (i.e., the near-field analysis). The first level consists of 

“screening” models, such as EPA’s SCREEN3 model, that conservatively estimate ambient impacts from 

the modeled source. The second level is referred to as “refined” models. These models, such as EPA’s 

AERMOD model, require more detailed and precise input data, including representative hourly 

meteorological data, and result in more accurate estimates of the source ambient air impacts. 
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Appendix E: Air Quality Impact Analysis. March, 2010

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The latest version of the AERMOD model (version 09292) was used for the air quality analyses, with the 

regulatory default option set. AERMOD is a steady-state plume dispersion model that simulates transport 

and dispersion from multiple point, area, or volume sources based on an up-to-date characterization of the 

atmospheric boundary layer. AERMOD uses Gaussian distributions in the vertical and horizontal for 

stable conditions, and in the horizontal for convective conditions; the vertical distribution for convective 

conditions is based on a bi-Gaussian probability density function of the vertical velocity. For elevated 

terrain AERMOD incorporates the concept of the critical dividing streamline height, in which flow below 

this height remains horizontal, and flow above this height rises up and over terrain. AERMOD also uses 

the advanced PRIME algorithm to account for building wake effects. 

The regulatory DFAULT option requires the use of terrain elevation data, stack-tip downwash, sequential 

date checking, and does not permit the use of the model in the SCREEN mode. In the regulatory default 

mode, pollutant half life or decay options will not be employed. 

The latest version of the supporting program AERMAP (version 09040) was also used to develop the 

model receptor grids. 

2.2 Building Downwash Effects. 

AERMOD can account for building downwash effects. The stack location, stack height, and structure 

locations and dimensions at the Project, as well as at any explicitly modeled nearby emission sources, 

were input to EPA’s “Building Profile Input Program –PRIME” (BPIP-PRIME) computer program. 

BPIP-PRIME processes this data in two steps. The first step determines and reports on whether or not a 

stack meets Good Engineering Practice (GEP) requirements and is subject to wake effects from a 

structure or structures. The second step calculated the “equivalent building dimensions” if a stack is 

influenced by structure wake effects in a format that is accepted by AERMOD. Since some stacks at the 

Project and at other nearby sources are influenced by wake effects, the BPIP-PRIME output for those 

stacks were input to the AERMOD model input file. 

2.3 Urban Versus Rural Dispersion 

AERMOD incorporates both rural and urban processing options, which affect the dispersion rates used in 

calculating ground-level pollutant concentrations. A methodology was developed by the EPA to classify 

an area as either rural or urban for dispersion modeling purposes. The classification is based on average 

heat flux, land use, or population density within a 3-km radius from the modeled facility. Of these 

techniques, the EPA has specified that land use is the most definitive criterion. 

The DNR modeling group conducted a land use analysis in order to identify urban locations within the 

state. The only “Urban” location found in Wisconsin is in the Milwaukee area, therefore this AERMOD 

analysis will use the default rural dispersion algorithm option. 
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Appendix E: Air Quality Impact Analysis. March, 2010

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2.4 Meteorological Data. 

The DNR has extracted, quality assured, and merged raw surface and upper air data from a number of 

meteorological monitoring stations and processed the data using EPA’s AERMET program. DNR has 

determined the various areas of the state for which each of these stations provides representative 

meteorological data. For the Project area in Rothschild, Wisconsin, the DNR recommended 

meteorological data set is the Wausau Municipal Airport data set, using Green Bay upper air sounding 

data. Five years of data (1998 through 2002) from this site were therefore used in the Project modeling 

analysis. 

2.5 Receptor Data. 

The latest version of the AERMAP (version 09040) program was used to develop the model receptor 

grids. USGS National Elevation Data (NED) at 1/3 Arc Second resolution was used as the elevation data 

source for the AERMAP processing. The selection of appropriate receptor locations is an important 

aspect of the dispersion modeling analyses, because the model estimates pollutant concentrations only at 

receptor locations. 

The main receptor network used for the air modeling consisted of 5010 receptors based on "discrete" 

rectangular grids (with UTM "x–y" coordinates and receptor "z" elevations above mean sea level [msl]) 

centered on the project as follows: 

• 25-meter spaced grid on the facility boundary and out to a distance of 25 meters in all directions. 

• 50-meter spaced grid from 25 meters out to a distance of 500 meters in all directions. 

• 100-meter spaced grid from 500 meters out to a distance of 1500 meters in all directions. 

• 250-meter spaced grid from 1500 meters out to a distance of 2500 meters in all directions. 

• 500-meter spaced grid from 2500 meters out to a distance of 4000 meters in all directions. 

• 1000-meter spaced grid from 4000 meters out to a distance of 9000 meters in all directions. 

Because of the long program run times that occur when using this large receptor grid for the PM analyses 

(the PM analyses included 168 emission sources), and because the highest PM impacts were located very 

near the fenceline of the facility, a separate receptor grid was utilized for the PM analyses. This grid 

consisted of 1759 receptors including a 25-meter spaced grid on the facility boundary and out to a 

distance of 75 meters in all directions, followed by a 100-meter spaced grid extending from 75 meters out 

to a distance of approximately 1000 to 3000 meters in all directions (the extent was based upon impact 

isopleths and the presence of terrain features). 

Figures 2-1 and 2-2 present views of the main receptor grid and the PM receptor grid, along with the 

structure layout used for the BPIP-PRIME analyses. 
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FIGURE 2-1. Main AERMAP Receptor Grid. 
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FIGURE 2-2. Close-in PM AERMAP Receptor Grid.
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2.6 NO2 Conversion Methodology 

The majority of NOX emissions from combustion sources are in the form of nitric oxide (NO), whereas 

EPA has established air quality standards for NO2. Therefore, an approved methodology must be used to 

convert model estimates of ambient NO concentrations into equivalent ambient NO2 concentrations. 

EPA's GAQM provides a three-tiered approach to calculating annual average NO2 impacts. The Tier 2 

ARM method was used with the default ratio of 0.75 for the NO2 modeling analyses. 

2.7 Background Air Quality Data 

EPA’s GAQM discusses how background air quality data is combined with modeled concentrations to 

determine the total ambient concentration that is compared to the NAAQS. Background air quality 

includes pollutant concentrations caused by emissions from natural sources, nearby sources other than the 

ones explicitly being included in the dispersion model, and any unidentified sources. 

DNR has developed background concentrations as described in a memorandum titled “Regional 

Background Concentrations”, dated September 15, 2008. DNR evaluated background for two types of 

geographical areas, “high population and industrial activity” areas and “low population and industrial 

activity” areas. The Rothschild area falls into the “low population and industrial activity” category, 

therefore representative background concentrations for that category were used in the Project’s NAAQS 

analysis. Table 2-1 presents the background concentration data. 

EPA has promulgated new PM2.5 and 1-hr NO2 NAAQS, and is in the process of developing 

implementation and modeling guidance for both standards. DNR provided background concentrations 

for PM2.5 and averaging intervals in a draft guidance memorandum, dated October 1, 2009. This is a draft 

update to the September 15, 2008 memorandum. DNR has not tabulated 1-hour NO2 background 

concentrations, therefore the available NO2 monitoring data for Wisconsin (available on EPA’s Airdata 

web site) was evaluated to determine the appropriate 1-hr NO2 background concentration. There are two 

NO2 monitoring stations, one in Milwaukee and one in Two Rivers. The Two Rivers site is more 

representative of the project site, and the calculated 98th percentile value for the years of 2006-2008 is 

11.9 μg/m3. This value was used for the 1-hr NO2 background concentration. The PM2.5 and 1-hr NO2

background concentrations may be revised in the future as EPA issues additional guidance on 

implementation of the two standards. 
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TABLE 2-1. Background Concentration Data, μg/m3. 

Pollutant Averaging Period Background Value 

Annual 8.0 

Nitrogen Oxides (NO2) 

1-hour 11.9 

8-hour 904.7 

Carbon Monoxide (CO) 

1-hour 950.5 

Annual 10.1 

Particulate Matter (PM10) 

24-hour 29.4 

Annual 8.7 

Particulate Matter (PM2.5) 

24-hour 25.6 

Total Suspended Particulate (TSP) 24-hour 39.7 

Annual 5.4 

Sulfur Dioxide (SO2) 24-hour 11.2 

3-hour 11.8 

3-month 0.01 

Lead 

Quarterly 0.01 
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2.8 Model Design Concentrations 

Section 7.2 of the GAQM defines the dispersion model outputs or “design concentrations” that are used to 

assess compliance with the NAAQS and PSD increments. EPA recommends in GAQM Section 8.3.1.2 

that the air quality modeling analyses should be based on certain amounts of meteorological input data 

(e.g., 5 years of National Weather Service data or at least 1 year of site specific data), and the Project 

analyses meet this recommendation (5 years of National Weather Service data are used). Therefore, the 

model design concentrations are based on GAQM Section 7.2 recommendations, as described below: 

• For SO2 NAAQS and PSD increment, the short-term design concentration is the highest, secondhighest concentration from each of the individual years that are modeled, and the annual design 

concentration is the highest of the annual averages, 

• For NO2, the annual average NAAQS and PSD increment design concentration is the highest of the 

annual averages calculated from each of the individual years, 

• For PM10, the 24-hr NAAQS design concentration is the “n+1” highest concentration over the n 

year modeling period (high 6rd highest for the five year meteorological data set), the 24-hr PSD 

increment design concentration is the highest, second-highest concentration calculated from each of 

the individual years that are modeled, and the annual average PSD increment design concentration 

is the highest of the annual averages, 

• For PM2.5, AERMOD model directly calculates the 24-hr and annual design concentrations. For the 

24-hr NAAQS design concentration, AERMOD calculates the eighth-highest concentration at each 

receptor for each year modeled, averages those eighth-highest concentrations across the number of 

years of data, and then selects the highest, across all receptors, of the N-year averaged eighthhighest values (this concentration is listed as the 1ST HIGHEST VALUE in the output table). For 

the annual average NAAQS design concentration, AERMOD calculates the annual PM2.5 design 

concentration based on the highest of the multi-year averaged annual means across the receptor 

domain for multi-year meteorological data input, 

• For the Wisconsin TSP standard, the 24-hr design concentration is the highest, second-highest 

concentration from each of the individual years that are modeled. 

EPA recently promulgated the 1-hr NO2 NAAQS, and is in the process of developing implementation and 

modeling guidance. Because EPA has not yet developed an AERMOD post-processor to calculate the 

modeled concentrations in the exact same form as the NAAQS, a conservative method of reporting the 

highest-8th-high concentration from any individual year in the meteorological data set as the 1-hr NO2

design concentration was used, based on discussions with DNR. 

EPA recently issued preliminary revised guidance for performing PM2.5 analyses. Until EPA finalizes 

this revised guidance, the PM2.5 NAAQS analyses have been performed using the standard design 

concentration calculation procedures that are directly programmed into AERMOD. 
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Chapter 3. Emission and Stack Data. 

3.1 Project Emission and Stack Data. 

The PSD Air Pollution Control Construction Permit application for the Project presents detailed emission 

and stack data for Project emission units, in both the control technology analyses as well as the DNR 

Permit Application forms. 

Because emission rates and stack parameters can vary over a range of operating conditions, the modeling 

analysis also considered operating load scenarios for the boilers, as recommended in EPA’s GAQM. 

Section 9.1.2 of the GAQM recommends that an assessment of both full load and partial load conditions 

for emission units be performed to determine the worst-case source configuration for use in subsequent 

modeling. Stack parameter and emissions vendor data was available for the biomass boiler for 100%, 

80%, 60%, and 40% loads. For the natural gas fired boilers the assumption was made that stack flows 

and emissions varied linearly with load. In order to simplify the modeling analysis and minimize the 

number of potential permit conditions, the lowest stack flow rate and exhaust temperature from any of the 

load scenarios was used with the maximum emission rate for the boilers. The DNR Modeling Guidelines 

recommend, as a conservative first step, that maximum emissions be modeled with “normal” flows and 

stack parameters, and the use of the maximum emissions with the lowest of the normal flows and stack 

parameters meets this guidance. 

Table 3-1 presents the maximum hourly emission rates and the stack parameters that were modeled for 

each of the emission sources. Figure 3-1 presents the modeled layout of the Project, and a 3-dimension 

view of the modeled sources and structures used in the BPIP-PRIME analysis. Even though the gas-fired 

Project boilers are intended to operate only when the biomass boiler is down, both the gas-fired boilers 

and the biomass boiler were modeled as operating simultaneously. This scenario results in maximum 

operating flexibility for Project boilers. 

3.2 Other Nearby Sources for Cumulative Analyses. 

For those pollutants and averaging periods for which the Project impacts are greater than the significance 

levels, cumulative modeling analyses were performed that considered emissions from both the Project 

sources and other nearby sources. 

The Wisconsin DNR provided the cumulative source inventory for other facilities in the impact area, 

which included the nearby Domtar and Lignotech facilities, as well as the main boiler sources at the 

Weston Power Plant. The data was transmitted as ISCST3, AERMOD, and BPIP input data files, so all 

necessary information including locations, stack parameters, nearby structures, and emission rates was 

available. 
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TABLE 3-1. Project Stack Parameters and Emission Data. 

Stack 

ID 

Process 

ID Description Pollutant Emission Rate, lb/hr

UTM 

Easting, 

meters

UTM 

Northing, 

meters 

Discharge 

Type 

Disc

He

f

CO NOX PM PM10 PM2.5 SO2 Pb 

S01 B01 Biomass Fuel-Fired Circulating Fluidized Bed Boiler B01 160.0 80.0 24.0 24.0 18.4 72.0 0.02400 292,337 4,973,906 Vertical 2S02 B02 Natural Gas-Fired Package Boiler B02 10.5 3.5 1.3 1.33 1.33 0.11 0.00008 292,340 4,973,873 Vertical 2S03 B03 Natural Gas-Fired Package Boiler B03 10.5 3.5 1.3 1.33 1.33 0.11 0.00008 292,340 4,973,873 Vertical 2

S121 P121 Biomass Fuels Dust Collector 3.75 3.75 1.87 292,297 4,973,831 Vertical 1S122 F122 Self Unloading Fuels Truck 0.00524 0.00248 0.00038 292,252 4,973,763 Volume S123 F123 Biomass Fuels Storage and Reclaim 0.00043 0.00020 0.00003 292,214 4,973,675 Volume S124 P124 Boilerhouse Fuel Storage Silos (2) 0.0206 0.0206 0.0103 292,307 4,973,882 Vertical 1S125 F125 Fuels Delivery Truck Roads 0.889 0.173 0.026 Various Various Volume S131 P131 CFB Boiler Bed Material Silo 0.034 0.034 0.017 292,325 4,973,900 Vertical 1S132 P132 CFB Boiler Ash Silo 0.034 0.034 0.017 292,367 4,973,932 Vertical 7S133 F133 Boiler Ash Haul Roads 0.178 0.035 0.0051 Various Various Volume S141 P141 Cooling Tower 0.088 0.072 0.000 292,401 4,973,972 Vertical 7S151 P151 Emergency Diesel Engine Feed Water Pump 2.300 2.643 0.132 0.132 0.106 0.0050 0.00003 292,324 4,973,862 Vertical 1

Footnotes 

B02 and B03 are exhausted through a combined single stack, and the stack data listed is for the combined stack. P124 is exhausted through two stacks, S124A and S124B, and the stack data listed is for each stack. 
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FIGURE 3-1. Modeled Layout and 3-Dimension BPIP-PRIME View of the Project. 
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Because the Project boilers are intended to replace the existing Domtar boilers and provide steam to the 

mill, the Domtar boilers will not operate when the Project boilers are operating. Therefore, for the 

cumulative analysis it was assumed that all Domtar emission units would be operating except the four 

Domtar boilers (source IDs S10, S11, S12, and S13). In addition, the Domtar wood chip pile emission 

units (S40 and S43) and the south Domtar haul roads by the wood chip pile were deleted as the Project 

sources and structures will be built in this area. 

The source inventory provided by DNR included CO, NOX, TSP, PM10, and SO2 emission data. Since 

DNR has not yet established allowable PM2.5 emission rates for permitted sources, it was necessary to 

estimate PM2.5 emissions for the cumulative PM2.5 NAAQS analysis (note that PM2.5 emissions have been 

directly calculated for all Project emission units). An initial assumption was made that PM2.5 emissions 

were equal to the allowable PM10 emissions. This was overly conservative for some emission units, and 

so the following refinements were made to the PM2.5 emission rates for the cumulative inventory. 

3.2.1 Domtar Sources 

For the Domtar facility, the refinements made to the estimated PM2.5 emission rates, and some minor 

stack configuration changes, are listed below. 

TABLE 3-2. Domtar PM2.5 Emission Calculations.

Domtar 

Source ID Comments 

S41 

The PM emission rates in DNR’s modeling files did not match the Title V calculated 

emissions rate of 0.123 lb/hr PM for this round wood log pile storage and receiving 

operation. The Project modeling uses the 0.123 lb/hr PM rate as both the PM10 and PM2.5

rates, and these emissions are split between the two area sources. The round wood pile and 

unpaved haul road sources were relocated by small amounts to better match the facility 

layout as documented by National Agriculture Imagery Program (NAIP) 1 meter resolution 

aerial imagery. 

S44 and 

S45 

The wood chip and wood room cyclones PM emission rates were multiplied by a 29.5% 

PM2.5/PM ratio taken from AP-42 Appendix B Section 10.5 for Woodworking Collection 

Operations from belt sanding exhaust cyclones (this is a conservative estimate of the ratio 

for the wood chip and wood room transfer operations, since the expected fraction of fine 

particles is greater for a sanding operation). Also, these two stacks will be converted to 

vertical releases, with heights of 45 feet for S44 and 32 feet for S45. 

S52 

The limestone silo PM10 emissions in the Domtar Title V Renewal application were 

conservatively based on a limestone drop factor equation, without any consideration of the 

baghouse control system on S52. Therefore, refined PM2.5 emissions were calculated by 

multiplying the normal system flow rate (1000 acfm) by a conservative PM2.5 outlet grain 
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Domtar 

Source ID Comments 

loading of 0.01 gr/dscf. The calculated PM2.5 emission rate is 0.0857 lb/hr. 

S56 

The allowable Lime Silo PM10 emissions in the facility Title V permit were based on AP42 Section 8.15. This AP-42 section included both PM and PM2.5 emissions factors, so the 

ratio of the PM2.5 versus PM factors was used to adjust the PM10 rate of 0.72 lb/hr to a 

PM2.5 rate of 0.0384 lb/hr (without consideration of the 60% wet scrubber control 

efficiency). Also, this stack has been converted to a vertical release at a height of 26.5 feet. 

S70 

The starch silo PM10 emissions in the Domtar Title V Renewal application were 

conservatively based on a limestone drop factor equation, without any consideration of the 

bin vent control system on S70. Therefore, refined PM2.5 emissions were calculated by 

multiplying the normal system flow rate (750 acfm) by a conservative PM2.5 outlet grain 

loading of 0.01 gr/dscf. The calculated PM2.5 emission rate is 0.060 lb/hr. 

S90 

The S90 stack was a “virtual” single stack that represented three actual emission releases. 

This single “virtual” stack has been separated into the three physical stacks (S90A, S90B, 

and S90C) for the Pulper Cyclone, Pulper Vent, and Shredder Cyclone emission units. The 

PM2.5 emissions for each stack were calculated by applying the same 29.5% ratio for wood 

handling operations that was used for Domtar source S44 and S45 to the PM emission rates 

listed in Domtar’s Title V Renewal Application for the Pulper Cyclone, Pulper Vent, and 

Shredder Cyclone emission units. All three of these stacks are vertical releases, and the 

heights are 42 feet for S90A, 26 feet for S90B, and 38 feet for S90C. The diameters are 

3.3 feet for S90A, 1.5 feet for S90B, and 3.3 feet for S90C. The exit velocities based on 

normal flows are 26.5 fps for S90A, 29.1 fps for S90B, and 15.3 fps for S90C. 

Haul 

Roads 

The Domtar haul road PM emissions were converted into PM2.5 emissions based on the 

AP-42 paved and unpaved road emission equations. The Domtar Title V Renewal 

application haul road emission calculations used the AP-42 equations and did not subtract 

the factor “C” for exhaust, brake wear and tire wear (which conservatively overestimates 

the PM10 emission rates). Therefore, for both the paved and unpaved road equations, the 

particle size factor “k” is linearly related to the emissions, and the fraction of the calculated 

PM10 emissions that are PM2.5 can be calculated by using the “k” factor ratios. For both 

paved and unpaved roads, the ratio of the “k” factors is 15%. Therefore, the Domtar haul 

road PM10 emissions provided in the DNR cumulative emission inventory modeling files 

were multiplied by 15% to calculate the Domtar haul road PM2.5 emission rates 

In addition to estimating PM2.5 emissions at the Domtar sources, one additional change was made to the 

Domtar source inventory. For S82, the Pulp Mill Lift Station, the modeled SO2 emissions rate was based 

on the maximum theoretical rate of 0.367 lb/hr versus the code allowable rate of 1.63 lb/hr. Also, the 

stack for S82 will be converted from a horizontal release to a vertical release. 
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3.2.2 Lignotech Sources. 

Based on limited stack test data and discussions with the equipment manufacturer, the PM2.5 emission rate 

for source S16, the Spray Dryer #2, were set to 4 lb/hr, which is equal to the Spray Dryer #3 allowable 

PM10 emission rate. For all other emission units, the PM2.5 emissions were conservatively assumed to be 

equal to the allowable PM10 emissions. There were no other refinements made to Ligotech sources. 

3.2.3 Weston Power Plant Boilers. 

DNR provided AERMOD and BPIP-PRIME data files for the four main Weston coal-fired boilers. This 

data included SO2 and PM10 emissions rates. The PM2.5 emission rates for Units 1 - 3 were calculated 

using EPA AP-42 Section 1.1 emission factors for 2.5 micron and smaller filterable particulates, plus 

condensable particulate matter, , based on the combustion of Powder River Basin (PRB) coal. The PM2.5

emission rate for unit 4 was set equal to the allowable PM10 emission rate. The following table presents 

the PM2.5 emission rates modeled for Weston units 1 through 4. The final modeled cumulative inventory, 

including emission rates and stack parameters, is presented in Appendix A of this report. 

TABLE 3-3. Weston PM2.5 Emission Calculations. 

Parameter/Unit # 1 2 3 4 

Controls ESP ESP FF FF/FGD 

Current PM10 emission rates lb/hr 87.8 100 390.6 103.5 

Size mmBtu/hr 858 1000 3423 5173 

Calculated PM10 lb/mmBtu 0.102 0.100 0.114 0.020 

Condensable lb/mmBtu 0.020 0.020 0.020 included 

PM10 Filterable lb/mmBtu 0.082 0.080 0.094 n/a 

PM10 Filterable Size Fraction 67 67 92 n/a 

PM2.5 Filterable Size fraction 29 29 53 n/a 

PM2.5 Filterable lb/mmBtu 0.036 0.035 0.054 included 

Total PM2.5 lb/mmBtu 

(Filterable and Condensable) 0.056 0.055 0.074 0.020 

Modeled PM2.5 rate lb/hr 47.7 54.6 254.0 103.5 

3.3 PSD Increment Emissions and Baseline Dates 

For the PSD increment cumulative impact analysis, the appropriate sources and emissions that are 

modeled are those sources that have changed since the applicable baseline date. The Project is located in 

Marathon County, and the PSD baseline for Marathon County has been set at various times for PM10, 

SO2, and NOX. The SO2 and PM10 baseline dates were established in December 27, 1987, and the NOX

baseline date was established as of September 2, 1993. 

The nearby source inventory that DNR provided included the PSD increment consuming SO2, PM10, and 

NOX emissions for the Domtar, Ligotech, and Weston facilities, and these rates were modeled as 

necessary in the cumulative PSD increment analyses. In addition, all of the Project emission sources were 

modeled as increment consuming emission sources. 
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Chapter 4. Air Quality Analysis Results. 

4.1 Significant Impact Analysis. 

In this dispersion modeling analysis, a significant impact analysis was first performed to determine the 

increases in ambient air concentrations due only to the proposed Project sources for those pollutants with 

emissions that exceed the significant emission levels. When the maximum ambient concentrations of a 

pollutant are below the significant impact level (“SIL”) for all averaging periods, the emissions from the 

proposed source are not expected to have a significant impact on ambient air concentrations and further 

air quality analysis is not required. If the source's ambient impacts exceed the SIL for any pollutant and 

averaging interval, the extent of the geographical area in which the source exceeds the SIL is determined, 

and a cumulative impact analysis is performed for that pollutant and averaging interval. Note that the 

highest short-term modeled concentration is compared to the SILs. 

The results of the significant impact analysis are summarized in Table 4-1. The maximum impacts from 

the Project for CO, NO2, and the annual SO2 impacts are all below the significant impact levels. 

Therefore, emissions from the Project will have an insignificant impact on air quality for these pollutants 

and averaging intervals and no further analysis is necessary. 

Based on the significant impact analysis, cumulative impact modeling was performed for SO2 3-hr and 

24-hr averages, and all PM10, and PM2.5 averaging periods. EPA has not developed 1-hr NO2 SILs to 

determine when a cumulative 1-hr NO2 NAAQS analysis is required. Therefore, even though the annual 

NO2 impacts from the Project are insignificant, a cumulative 1-hr NO2 analysis was still performed. 

4.2 Cumulative NAAQS and PSD Increment Analysis. 

For those pollutants/averaging periods for which the Project impacts are greater than the significance 

levels, cumulative modeling analyses were performed that considered emissions from both the Project 

sources and other nearby sources. The DNR provided the cumulative NAAQS and PSD source inventory 

for other facilities in the impact area, which included the nearby Domtar and Lignotech emission sources, 

as well as the main boiler sources at the Weston Power Plant. 

Even though the cumulative analysis is normally limited to the project’s significant impact area, the 

Project modeling utilized the same large receptor grids for the cumulative analyses as for the project 

significant impact analyses. 

The results of the cumulative NAAQS analysis are summarized in Table 4-2. The NAAQS results 

demonstrate that the Project will not cause or contribute to air quality concentrations that exceed the 

NAAQS or Wisconsin TSP standard. 
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TABLE 4-1. Results of the significant impact analysis. 

Pollutant Averaging Period Significant Impact Level, 

μg/m3

Highest Modeled 

Concentration, μg/m3

8-hour 500 99 

CO 

1-hour 2,000 209 

NO2 Annual 1 0.92 

Annual 1 0.98 

SO2 24-hour 5 12.6 

3-hour 25 55.6 

Annual 1 5.6 

PM10

24-hour 5 20.4 

Annual 0.3 1.2 

PM2.5

24-hour 1.2 6.4 

Footnotes 

The SILs listed for PM2.5 are the lowest of EPA’s currently proposed values. 

TABLE 4-2. Cumulative NAAQS modeling results. 

Pollutant Averaging 

Interval 

Cumulative 

Impact, 

μg/m3

Background, 

μg/m3

Total, 

μg/m3

NAAQS 

μg/m3 % of NAAQS

NO2 1-hour 61 11.9 73.2 188 39% 

24-hour 249 11.2 260.2 365 71% 

SO2

3-hour 951 11.8 962.8 1,300 74% 

PM10 24-hour 41.8 29.4 71.2 150 47% 

Annual 2.3 8.7 11 15 73% 

PM2.5

24-hour 9.0 25.6 34.6 35 99% 

TSP 24-hour 103.6 39.7 143.3 150 96% 

Lead 24-hour 0.00066 0.01 0.01066 0.15 7% 
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4.2.1 Cumulative PSD Increment Analysis. 

The results of the cumulative Class II PSD increment analysis are summarized in Table 4-3. The PSD 

increment results demonstrate that the Project will not cause or contribute to air quality impacts that 

exceed the PSD increments. 

TABLE 4-3. Cumulative PSD Increment Modeling Results. 

Pollutant Averaging 

Interval 

Maximum 

Impact, μg/m3

PSD Increment 

μg/m3

% of PSD 

Increment 

Annual 5.7 17 34% 

PM10

24-hour 21.0 30 70% 

24-hour 86.1 91 95% 

SO2

3-hour 300 512 58% 

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Chapter 5. Additional Impacts Analysis. 

The Prevention of Significant Deterioration program requires an additional impact analysis pursuant to 

NR 405.13, Wis. Adm. Code, and the Code of Federal Regulations, 40 CFR 52.21(o). NR 405.13 states: 

The purpose of this analysis is to assess the potential impact the proposed project will have on visibility, 

soils, and vegetation, as well as the impact of general commercial, residential, and industrial growth 

associated with the proposed project. 

5.1 Analysis on Soils, Vegetation, and Visibility. 

The analysis of impacts on vegetation and soils is based on EPA guidance. The National Ambient Air 

Quality Standards (NAAQS) are designed to protect “health and welfare”, including “welfare” effects on 

water, vegetation, and soils, and are a useful benchmark for evaluating soil and vegetation impacts. In 

addition, model predicted concentrations were compared to other effects screening levels for sensitive 

species presented in EPA’s “A Screening Procedure for the Impacts of Air Pollution Sources on Plants, 

Soils, and Animals,” December 12, 1980, EPA 450/2-81-078, and “Air Quality Criteria for Oxides of 

Nitrogen, Summary of Vegetation Impacts” Volume II, August 1993, EPA 600/8-91/049bF. The 

maximum modeled annual NO2 concentrations from the project were less than 1 μg/m3, which is far 

below the EPA direct effects screening concentration of 94 to 188 μg/m3 for annual NO2 averages. The 

maximum modeled 1-hr NO2 concentrations were 73 μg/m3, which is far below the EPA direct effects 

screening concentration of 3,760 μg/m3 for 4-hr NO2 averages. The maximum modeled ambient SO2

concentrations from the project were 56 μg/m3 for the 3-hr average and 0.98 μg/m3 for the annual 

average, which are far below the direct effects screening concentrations of 786 μg/m3 for 3-hr and 18 

μg/m3 for annual averages. Since the ambient impacts from the Project do not exceed the NAAQS nor 

EPA screening thresholds for sensitive vegetation and soils, the dispersion modeling analysis 

demonstrates that there are no harmful effects to vegetation and soils. 

Near the proposed project site, under certain meteorological conditions, the combustion source stacks will 

emit a visible steam plume which, after traveling a relatively short distance, will dissipate by dispersion 

and evaporation. The project has also performed cooling tower visibility modeling analyses to estimate 

the potential for ground-level fogging and icing associated with visible vapor plumes, and ground-level 

fogging and icing impacts are expected to be visibility for approximately 2 hours per year. 

The existing four mill boilers and steam turbine plant will be retired once the new facility is operational. 

As a result of the biomass CFB boiler’s air quality technology and the retirement of Domtar’s existing 

boilers, the overall emissions from the mill site is expected to be reduced. Therefore, this Project will 

have a positive overall impact on soils, vegetation, and visibility. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix E: Air Quality Impact Analysis. March, 2010

30

5.2 Associated Growth and Secondary Emissions. 

The emissions resulting from residential, commercial, and industrial growth associated with, but not 

directly a part of the project, must also be considered when conducting the air quality analysis. 

According to the U.S. Bureau of the Census, Census of Population and Housing, the population of 

Marathon County in 2008 was 131,000. Given this large local population, the construction associated 

with the Project and the operation of the new Plant will not have a significant impact to the local 

population. In addition, local municipal services will not be adversely impacted by this Project. There is 

currently sufficient fire protection and rescue services for the construction and operation of the Project. 

The Project will be located entirely within an existing industrial site, which currently hosts electric 

and steam generation facilities which are owned and operated by Domtar, as well as existing 

papermaking facilities. Therefore, the Project is not expected to have a measurable effect on the 

residential, commercial, or industrial growth of the area. 
We Energies - Air Pollution Control Construction Permit Application for a 

50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix E: Air Quality Impact Analysis. March, 2010

31

Chapter 6. Class I Air Quality Analysis. 

In the Clean Air Act Amendments of 1977, Congress specified the classification of lands for PSD 

purposes. Areas where existing air quality is considered to be of national importance were classified as 

Class I areas. These mandatory “Federal Class I areas” include all international parks, national memorial 

parks larger than 5,000 acres, and national parks larger than 6,000 acres that were in existence when the 

Amendments were passed. Congress also allowed States and Federally Recognized Indian tribes the 

option of redesignating Class II areas to Class I status to provide additional air quality protection. In 

Wisconsin, EPA has approved a request by the Forest County Potawatomi Community’s (FCP 

Community) Tribal Council to redesignate certain portions of the FCP Community Reservation near 

Crandon Wisconsin as a “non-Federal Class I area”. 

If a proposed major source or major modification may affect a Class I area, the PSD regulations require 

the reviewing authority to provide written notification of any such proposed source to the Federal Land 

Manager and the U.S. Department of Interior and U.S. Department of Agriculture officials delegated 

permit review responsibility. The meaning of the term "may affect" is interpreted by EPA policy to 

include all major sources or major modifications which propose to locate within 100 kilometers of a Class 

I area. 

Wisconsin has two Class I PSD areas, the federal Rainbow Lake Area located in the Chequamagon 

National Forest (located approximately 200 km distant from the proposed facility), and the non-Federal 

Forest County Potawatomi area in Forest County (located approximately 99 km distant from the proposed 

facility). Generally, if a PSD project is located within 100 km of a Class I area, a Class I air quality 

impact analysis may be required. However, based on guidance developed by the Federal Land Managers 

of Class I areas, an “initial screening test” may be performed to determine if air quality and visibility 

impact analyses are required. This screening test uses the sum of the annual total emissions (in tons per 

year) of SO2, NOX, PM10, and H2SO4, divided by the distance to the Class I area (in km), to determine the 

“Q/D” ratio. If the ratio is less than 10, then the Federal Land Managers do not require Class I impact 

analyses. Based on the emissions of the proposed facility and the distances to the Class I areas, the ratios 

are calculated to be 8.3 for the FCP Class I area and 4.1 for the Rainbow Lakes area. Therefore, a Class I 

analysis for the Project is not required for either of the Wisconsin Class I areas. 

Appendix A 

Summary of Cumulative Source Inventory 

Emissions and Stack Parameters 
Source ID Source Description Easting 

(m) 

Northing 

(m) 

Base 

Elevation (m)

Stack 

Height (ft) Temp. (F) Exit Vel. 

(fps) 

Stack 

Diameter (ft)

S01 Biomass Boiler Flow @ 50% 292336.5 4973906.3 353.11 265.0 288.0 27.5 10.01 

S02_03 GasOil Boilers Flows@50% 292336.2 4973903.9 353.57 225.0 365.0 32.8 6.56 

S151 Back up Feedwater Pump 292323.7 4973862.1 353.11 195.0 800.3 130.0 0.67 

S121 Dust Control System 292297.2 4973831.3 353.57 100.0 -459.7 66.3 5.91 

S124A Fuel Silo 1 Bin Vent 292307.4 4973881.8 353.28 109.9 -459.7 6.4 1.00 

S124B Fuel Silo 2 Bin Vent 292315.4 4973890.3 353.25 109.9 -459.7 6.4 1.00 

S131 CFB Bed Silo Bin Vent 292325.4 4973900.3 353.21 109.9 -459.7 10.6 2.00 

S132 Ash Silo Bin Vent 292366.8 4973932.2 353.1 75.0 -459.7 10.6 2.00 

S141~1 Cooltower Cell 1 292389 4973958.8 353.33 70.0 50.0 25.0 25.00 

S141~2 Cooltower Cell 2 292394.7 4973965.3 353.37 70.0 50.0 25.0 25.00 

S141~3 Cooltower Cell 3 292400.6 4973971.8 353.33 70.0 50.0 25.0 25.00 

S141~4 Cooltower Cell 4 292406.4 4973977.8 353.26 70.0 50.0 25.0 25.00 

S141~5 Cooltower Cell 5 292395.8 4973952.8 353.36 70.0 50.0 25.0 25.00 

S141~6 Cooltower Cell 6 292401.8 4973959.3 353.39 70.0 50.0 25.0 25.00 

DS20O Old S20 Configuration 292676.4 4974219.8 352.9 75.0 200.0 0.3 2.99 

DS21 Solid Fuel Storage/Receiving 292912.4 4974336.8 354.18 50.0 -459.7 34.0 1.51 

DS22 Refuse Bin and Feed System 292693.4 4974249.8 353.47 45.0 43.0 0.3 1.51 

DS44 Wood Chip Cyclone 292634.4 4974219.8 352.04 45.0 60.0 19.9 4.00 

DS45 Wood Room Operations 292652.4 4974236.8 352.18 32.0 70.0 30.6 2.99 

DS50 Acid Plant Process 292721.4 4974190.8 354.86 123.0 55.0 36.5 1.71 

DS51 Acid Plant Miscellaneous 292719.4 4974203.8 354.99 7.0 65.0 0.3 3.68 

DS52 Limestone Unloading Silo 292730.4 4974202.8 354.98 66.0 60.0 0.3 1.15 

DS53 Digester Operations 292676.4 4974198.8 353.26 35.0 170.0 0.3 2.13 

DS542903 Unbleached Pulp Processes 292637.3 4974200 352.28 56.0 76.7 0.3 2.36 

DS542907 Unbleached Pulp Processes 292660 4974164.3 353.21 59.0 80.0 29.3 2.33 

DS542908 Unbleached Pulp Processes 292662.1 4974166.8 353.24 59.0 80.0 12.3 1.87 

DS543001 Unbleached Pulp Processes 292652.9 4974196.1 352.32 59.0 80.0 0.3 5.18 

DS543003 Unbleached Pulp Processes 292642.9 4974198.8 352.18 8.0 80.0 0.3 4.00 

DS543307 Unbleached Pulp Processes 292659.8 4974212.8 352.47 10.0 80.0 0.3 0.49 

DS56 White Lime Silo 292604.4 4974190.8 352.04 26.5 60.0 94.6 0.67 

DS70 Bulk Starch Storage 292683.4 4974024.8 354.48 58.0 60.0 0.3 0.49 

DS80 Wastewater Treatment Plant 292158.4 4973738.8 353.54 15.0 90.0 0.3 38.62 

DS82 Pulp Mill Lift Station 292593.4 4974175.8 352.04 6.0 70.0 16.8 1.51 

DS90A Pulper Cyclone 292526.4 4973932.8 353.57 42.0 65.0 26.5 3.35 

DS90B Pulper Vent 292536.4 4973927.8 353.57 26.0 65.0 29.1 1.51 

DS90C Shredder Cyclone 292534.4 4973918.8 353.57 38.0 65.0 15.3 3.35 

L16_80 Lignotech 292774.4 4974203.8 354.73 80.0 110.0 55.4 3.50 

L17 Lignotech 292799.4 4974230.8 354.62 74.5 100.0 103.7 3.00 

L22 Lignotech 292777.4 4974283.8 355.04 38.0 69.5 0.3 0.30 

L26 Lignotech 292776.4 4974211.8 354.69 35.0 149.8 29.3 0.49 

L27 Lignotech 292798.4 4974276.8 354.77 72.0 101.8 21.2 0.98 

L29 Lignotech 292831.4 4974286.8 354.43 90.0 114.7 1.6 0.33 

WES01 Weston Unit 1 290297.5 4970963 355.39 243.0 342.2 39.9 11.92 

WES02 Weston Unit 2 290277.6 4970937 355.49 242.6 335.0 51.4 11.92 

WES03 Weston Unit 3 290605.4 4970566 359.66 496.2 328.5 107.0 16.00 

WES04N Weston Unit 4 290777.2 4970473 359.37 500.0 171.1 75.0 20.00 
Source ID Source Description PM25 PM10 TSP SO2ST NOXST CO PSDPM24 PSDPMANN PM-2.5 

 (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) 

S01 Biomass Boiler Flow @ 50% 1.84E+01 2.40E+01 2.40E+01 7.20E+01 8.00E+01 1.60E+02 2.40E+01 1.05E+02 8.06E+01 S02_03 GasOil Boilers Flows@50% 2.66E+00 2.66E+00 2.66E+00 2.20E-01 7.00E+00 2.10E+01 2.66E+00 1.17E+01 8.20E+00 S151 Back up Feedwater Pump 1.06E-01 1.32E-01 1.32E-01 5.00E-03 2.64E+00 2.30E+00 1.32E-01 6.61E-03 5.30E-02 S121 Dust Control System 1.87E+00 3.75E+00 3.75E+00 3.75E+00 1.64E+01 8.19E+00 S124A Fuel Silo 1 Bin Vent 5.15E-03 1.03E-02 1.03E-02 1.03E-02 4.51E-02 2.25E-02 S124B Fuel Silo 2 Bin Vent 5.15E-03 1.03E-02 1.03E-02 1.03E-02 4.51E-02 2.25E-02 S131 CFB Bed Silo Bin Vent 1.71E-02 3.43E-02 3.43E-02 3.43E-02 1.50E-01 7.51E-02 S132 Ash Silo Bin Vent 1.71E-02 3.43E-02 3.43E-02 3.43E-02 1.50E-01 7.51E-02 S141~1 Cooltower Cell 1 3.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04 S141~2 Cooltower Cell 2 3.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04 S141~3 Cooltower Cell 3 3.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04 S141~4 Cooltower Cell 4 3.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04 S141~5 Cooltower Cell 5 3.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04 S141~6 Cooltower Cell 6 3.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04 DS20O Old S20 Configuration -1.3E+00 -5.6E+00 DS21 Solid Fuel Storage/Receiving 2.80E-02 2.80E-02 5.90E-02 1.23E-01 DS22 Refuse Bin and Feed System 1.30E-02 1.30E-02 2.70E-02 5.69E-02 DS44 Wood Chip Cyclone 2.30E-01 7.80E-01 7.80E-01 4.30E-01 1.88E+00 1.01E+00 DS45 Wood Room Operations 8.85E-02 3.00E-01 3.00E-01 3.88E-01 DS50 Acid Plant Process 6.50E-01 6.50E-01 6.50E-01 3.80E+01 6.50E-01 2.85E+00 2.85E+00 DS51 Acid Plant Miscellaneous 1.40E-01 DS52 Limestone Unloading Silo 8.57E-02 5.00E-01 5.00E-01 5.00E-01 2.19E+00 3.75E-01 DS53 Digester Operations 6.00E-02 DS542903 Unbleached Pulp Processes 9.00E-03 9.00E-03 1.60E-02 5.00E-01 8.88E-03 3.89E-02 3.94E-02 DS542907 Unbleached Pulp Processes 2.00E-03 2.00E-03 3.00E-03 5.30E-01 1.90E-03 8.32E-03 8.76E-03 DS542908 Unbleached Pulp Processes 5.00E-04 5.00E-04 1.00E-03 6.00E-01 5.08E-04 2.23E-03 2.19E-03 DS543001 Unbleached Pulp Processes 6.00E-03 6.00E-03 1.00E-02 2.52E+00 5.58E-03 2.45E-02 2.63E-02 DS543003 Unbleached Pulp Processes 2.00E-03 2.00E-03 4.00E-03 1.01E+00 2.16E-03 9.46E-03 8.76E-03 DS543307 Unbleached Pulp Processes 3.00E-03 3.00E-03 5.00E-03 1.13E+00 2.54E-03 1.11E-02 1.31E-02 DS56 White Lime Silo 3.84E-02 7.20E-01 7.20E-01 1.68E-01 DS70 Bulk Starch Storage 6.43E-02 4.10E-01 4.10E-01 2.82E-01 DS80 Wastewater Treatment Plant 6.70E-01 
Source ID Source Description PM25 PM10 TSP SO2ST NOXST CO PSDPM24 PSDPMANN PM-2.5 

 (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) 

DS82 Pulp Mill Lift Station 3.67E-01 DS90A Pulper Cyclone 1.48E-01 5.00E-01 5.00E-01 6.48E-01 DS90B Pulper Vent 2.80E-02 9.40E-02 9.40E-02 1.23E-01 DS90C Shredder Cyclone 9.70E-02 3.30E-01 3.30E-01 4.25E-01 L16_80 Lignotech 4.00E+00 1.28E+01 1.28E+01 7.00E-01 1.75E+01 L17 Lignotech 4.00E+00 4.00E+00 4.00E+00 2.30E+00 1.75E+01 L22 Lignotech 5.00E+00 L26 Lignotech 6.20E-01 L27 Lignotech 3.80E+00 L29 Lignotech 1.00E+01 WES01 Weston Unit 1 4.77E+01 8.78E+01 8.78E+01 7.64E+02 2.09E+02 WES02 Weston Unit 2 5.46E+01 1.00E+02 1.00E+02 8.90E+02 2.39E+02 WES03 Weston Unit 3 2.54E+02 3.91E+02 3.91E+02 4.69E+03 3.91E+02 1.71E+03 1.11E+03 WES04N Weston Unit 4 1.04E+02 1.04E+02 1.04E+02 3.49E+03 1.04E+02 4.53E+02 4.53E+02 
State of Wisconsin INDEX OF AIR POLLUTION PERMIT APPLICATION FORMS 

Department of Natural Resources Form 4530-134 Rev. 12-99 

I.ADMINISTRATION 

; Form 4530-100, Facility Identification 

This application contains ; Form 4530-101, Facility Plot Plan 

the following forms: ; Forms 4530-102, -102A, and -102B, Source and Site Descriptions 

II. EMISSIONS SOURCE 

DESCRIPTION 

 

Total 

Number of 

This Form 

 ; Form 4530-103, Stack Identification 12 

 ; Form 4530-104, Boiler or Furnace Operation 3 

 □ Form 4530-105, Storage Tanks 

 □ Form 4530-106, Incineration 

 □ Form 4530-107, Printing Operations 

 □ Form 4530-108, Painting and Coating Operations 

This application contains 

the following forms (one 

form for each facility 

boiler, printing operation, 

etc.): 

 ; Form 4530-109, Miscellaneous Processes 10 

III.AIR POLLUTION 

CONTROL SYSTEM 

Total 

Number of 

This Form 

 ; Form 4530-110, Miscellaneous 1 

 □ Form 4530-111, Condensers 

 □ Form 4530-112, Adsorbers 

 □ Form 4530-113, Catalytic or Thermal Oxidation 

 □ Form 4530-114, Cyclones/Settling Chambers 

 □ Form 4530-115, Electrostatic Precipitators 

 □ Form 4530-116, Wet Collection Systems 

This application contains 

the following forms: 

 ; Form 4530-117, Baghouses/Fabric Filters 5 

IV.COMPLIANCE 

DEMONSTRATION 

Total 

Number of 

This Form 

□ Form 4530-118, Compliance Certification - Monitoring and Reporting 

□ Form 4530-119, Continuous Emission Monitoring 

□ Form 4530-120, Periodic Emission Monitoring Using Portable Monitors 

□ Form 4530-121, Control System Parameters or Operation Parameters of a Process 

□ Form 4530-122, Monitoring Maintenance Procedures 

□ Form 4530-123, Stack Testing 

□ Form 4530-124, Fuel Sampling and Analysis 

This application contains 

the following forms (one 

for each facility boiler, 

printing operation, etc.): 

□ Form 4530-125, Recordkeeping 

 



State of Wisconsin FACILITY IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-100 Rev. 12-99 Information attached? (y/n) 

1. Facility name and Name We Energies – Biomass-Fueled Cogeneration Facility 

mailing address Street or Route 231 W. Michigan

 City, State, Zip Code Milwaukee, WI 53201 

2. Facility location Street Address 200 Grand Avenue 

 City, County Rothschild, Marathon County 

3. Parent corporation Name We Energies 

 Street or Route 231 W. Michigan

 City, State, Zip Code Milwaukee, WI 53201 

 Country (if not U.S.) 

4. Responsible official Name Scott A. Patulski

 Title Vice President – Fossil Operations 

 Telephone (414) 221-5053 

5. Permit contact person Name Terry Coughlin 

 Title Manager, Air Quality 

 Telephone (414) 221-2293 

6. SIC code: 4911 7. Facility identification number: New

8. Primary activity of the operating establishment: Electric Power Generation

9. Type of permit 

; Construction permit □ Operation Permit OR □ Operation Permit Renewal 

Anticipated start date for construction: 1 / 1 / 2011 □ Part 70 Source Application 

Anticipated start date for operation: 9 / 2013 □ Non - Part 70 Source Application 

This application is requesting an expedited □ Synthetic Minor, Non - Part 70 

review (see instructions) ; Yes □ No Source Application 

□ Elective operation permit 

10.If facility is located in an area designated as "nonattainment", indicate the pollutant for the nonattainment 

designation. N/A

11. List all air pollution permits and orders issued to this facility (if a renewal application, just list those issued since the issuance 

date of your existing operation permit). No permits – this is a new facility.

12. If Renewal Application: List all air pollution control permit applications you have submitted on which the Department has 

not yet taken action. (If no permit number has been assigned yet, indicate the date of the application) N/A 

13. If Renewal Application: List all permit exemptions received from the Department since the issuance date of your existing 

operation permit. (Reference these by the date of the exemption letter or the exemption number if one was assigned.) N/A 
State of Wisconsin FACILITY PLOT PLAN 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-101 Rev. 12-99 

Use of this form is required by the Department for any air pollution control permit application filed pursuant to ss. 285.61, 285.62 or 

285.66, Wis Stats. Completion of this form is mandatory. The Department will not consider or act upon your application unless you 

complete and submit this form. It is not the Department's intention to use any personally identifiable information from this form for 

any other purpose. 

In order for a comprehensive air quality analysis to be accomplished, a facility plot plan MUST be included with the permit 

application. If the application is for an initial operation permit, submit the elements under #2 below. If the application is for a 

renewal, answer #1 below first. 

1. Have there been changes to the facility plot plan since the previous operation permit application was submitted? 

; No. The plot plan submitted with the original application can be used for the construction/renewal. The applicant 

will supply air quality modeling. 

□ Yes. An up-to-date plot plan is attached. 

2. If there have been changes to the facility plot plan since the last operation permit application submittal, RESUBMIT an up-to-date 

plot plan which must include the following or the permit application will be deemed incomplete: 

FOR DEPARTMENT USE ONLY

 COMPLETE INCOMPLETE NOT APPLICABLE

 1. A building layout (blueprint, plan view) including all buildings occupied 

by or located on the site of the facility. 

 2. The maximum height of each building (excluding stack height). 

 3. The location and numerical designation of each stack. Please ensure these 

designations correspond to the appropriate stacks listed on the other permit 

forms in this application. 

 4. The location of fenced property lines (if any). 

 5. Identify direction "North" on all submittals. 

 6. All drawings shall be to scale and shall have the scale graphically 

depicted. 

 7. An additional regional map depicting the facility location in relation to the 

surrounding vicinity (roads or other features) shall be included. 

Are there any outdoor storage piles on the facility site? ; Yes □ No 

If so, what material does the pile(s) consist of? 

N/A 

Are there any dirt roads or unpaved parking lots on the facility site? □ Yes ; No 
State of Wisconsin SOURCE AND SITE DESCRIPTIONS 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-102 Rev. 12-99 Information attached? (y/n) 

Use of this form is required by the Department for any air pollution control permit application filed pursuant to ss. 285.61, 285.62 or 

285.66, Wis Stats. Completion of this form is mandatory. The Department will not consider or act upon your application unless you 

complete and submit this form. It is not the Department's intention to use any personally identifiable information from this form for 

any other purpose. 

1. Briefly describe the proposed project or existing Unit(s) to be permitted. Attached supplemental forms as needed. 

Please refer to the attached permit application project description. 

 

For Renewal Applications: (not applicable)

1. Were any new or modified emissions units installed/modified at the facility since the last operation permit issuance date? 

□ No. Proceed to form 4530-102A. 

□ Yes. Answer the following questions: 

2. Briefly describe any new/modified emissions units installed at the facility since the last operation permit issuance date and include 

the following information. Attach supplemental forms as needed. 

a. List the Department issued construction and/or operation permit number as applicable (identifying which units were covered 

by which permit if multiple permits issued). 

i. If operation permit application forms were submitted for the new emission unit(s) covered by the construction permit 

mentioned above, reference the date of that application. 

ii. For Part 70 Sources Only: If no operation permit application forms were submitted for the new emissions unit(s) covered 

by the construction permit mentioned above, complete the appropriate forms 4530-118 through 4530-125. 

b. Include the Department issued construction permit exemption number, if one was assigned, or reference the date of the letter

of the exemption. 

 

2. Site Description 

 

The facility is located in Rothschild, Wisconsin directly adjacent to the Domtar Paper Company, 200 Grand 

Avenue, Rothschild. 

 
State of Wisconsin SOURCE DESCRIPTION - SUPPLEMENTAL 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-102A Rev. 12-99 Information attached? Y (y/n) 

Use of this form is required by the Department for any air pollution control permit application filed pursuant to ss. 285.61, 285.62 or 

285.66, Wis Stats. Completion of this form is mandatory. The Department will not consider or act upon your application unless you 

complete and submit this form. It is not the Department's intention to use any personally identifiable information from this form for 

any other purpose. 

1. List all significant existing or proposed air pollution units, operations, and activities at the facility. A short narrative of the 

inventory of air pollution emissions unit (e.g., boiler, printing line, etc.) followed by equipment specifications will suffice. If the 

facility consists of several individual emission units, present this information in an outline format. (See instruction booklet for an 

example Unit description.) 

Please refer to the permit application for details on each emissions unit. 

Stack 

ID 

Process 

ID Description 

S01 B01 Biomass Fuel-Fired Circulating Fluidized Bed Boiler B01 

S02 B02 Natural Gas-Fired Package Boiler B02 

S03 B03 Natural Gas-Fired Package Boiler B03 

S121 P121 Biomass Fuels Unloading, Screening, Hogging, and Conveying Dust Collector 

S122 F122 Self Unloading Truck Biomass Fuels Unloading 

S123 F123 Biomass Fuels Storage and Reclaim 

S124 P124 Boilerhouse Fuel Storage Silos 

S125 F125 Biomass Fuels Delivery Truck Haul Roads 

S131 P131 CFB Boiler Bed Material Silo 

S132 P132 CFB Boiler Ash Silo 

S133 F133 Boiler Ash Haul Roads 

S141 P141 Cooling Tower 

S151 P151 Emergency Diesel Engine Feed Water Pump 

For Renewal Applications: (not applicable)

1. If there were any new or modified emissions units installed/modified at the facility since the last operation permit issuance date: 

a. If any of these new/modified units were exempt from construction permit requirements, but are significant emissions units 

and operation permit application(s) for the new unit(s) were submitted to the Department reference the date of those 

submittals. 

b. If any of the new/modified units are insignificant emissions units list them on form 4530-102B. 

c. If any of the new/modified emissions units do not fit any of the above categories, fill out the appropriate forms for each 

emissions unit as follows: 

i. For Part 70 Sources: Fill out the appropriate forms 4530-103 through 4530-133; OR 

ii. For Synthetic Minor Non Part-70 Sources and Non-Part 70 Sources: Fill out the appropriate forms 4530-103 through 

4530-117 and 4530-126 through 4530-129. 
State of Wisconsin SOURCE DESCRIPTION - SUPPLEMENTAL 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-102B Rev. 12-99 Information attached? (y/n) 

Use of this form is required by the Department for any air pollution control permit application filed pursuant to ss. 285.61, 285.62 or 

285.66, Wis Stats. Completion of this form is mandatory. The Department will not consider or act upon your application unless you 

complete and submit this form. It is not the Department's intention to use any personally identifiable information from this form for 

any other purpose. 

1. Mark all insignificant existing or proposed air pollution units, operations, and activities at the facility listed below. If not listed, 

provide a short narrative of the inventory of air pollution emissions unit (e.g., boiler, printing line, etc.) followed by equipment 

specifications. If the facility consists of several individual emission units, present this information in an outline format. For 

Renewal Applications, identify those that are new since the last update to your application. (See instruction booklet for an 

example Unit description.) 

; Maintenance of Grounds, Equipment, and Buildings (lawn care, painting, etc.) 

; Boiler, Turbine, and HVAC System Maintenance 

; Pollution Control Equipment Maintenance 

 

; Internal Combustion Engines Used for Warehousing and Material Transport 

; Fire Control Equipment 

; Janitorial Activities 

; Office Activities 

; Convenience Water Heating 

; Convenience Space Heating (< 5 million BTU/hr Burning Gas, Liquid, or Wood) 

; Fuel Oil Storage Tanks (< 10,000 gal.) 

□ Stockpiled Contaminated Soils 

; Demineralization and Oxygen Scavenging of Water for Boilers 

; Purging of Natural Gas Lines 

; Sanitary Sewer and Plumbing Venting 

; Diesel fuel oil storage tanks for the emergency diesel engine feed water pump 

 

□ 

□

□

 

□
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S01 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 B01 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

; This stack has an actual exhaust point. □ This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: 250 (feet) 

8. Inside dimensions at outlet (check one and complete): 

; Circular 10.0 (feet) □ rectangular length (feet) width (feet) 

9. Exhaust flow rate: 

Normal 300,000 (ACFM) Maximum 305,000 (ACFM) 

10. Exhaust gas temperature (normal): 288 (F) 

11. Exhaust gas moisture content: Normal 25 volume percent Maximum 25 volume percent 

12. Exhaust gas discharge direction: ; Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin BOILER OR FURNACE OPERATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-104 11-93 Information attached? Y (y/n) 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S01 4. Boiler/furnace number: B01

4a. Unit description: 

The proposed boiler B01 will be a circulating fluidized bed (CFB) boiler designed to provide up to 550,000 pounds per hour 

of steam at 1,550 psig and 950 o

F. The boiler will have a maximum design heat input capacity of 800 million Btu per hour. 

The primary boiler fuels will be wood, bark, wood waste, forest residues, and wastewater treatment plant sludge from the 

Domtar Paper Mill. The boiler will also be designed to fire natural gas for a startup fuel and for load stabilization and 

supplemental firing, with a maximum natural gas firing rate of less than 250 mmBtu per hour.. 

5. Indicate the boiler/furnace control technology status. □ Uncontrolled ; Controlled 

If the boiler/furnace is controlled, enter the control device number(s) from the appropriate forms: 

4530-110 C01A 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 C01B 

6. Furnace type: Circulating Fluidized Bed (CFB) Boiler 7. Maximum continuous rating: 800 mmBtu/hr (heat input)

8. Manufacturer: metso power 9. Model number: n/a

10. Date of construction or last modification: NEW

 

11. Fuels and firing conditions: 

 Primary fuel Backup fuel #1 

(Startup Fuel) Backup fuel #2 Backup fuel #3 

Fuel name Biomass Fuels Natural Gas n/a n/a 

Higher heating value 4,530 Btu/lb (as 

received basis) 1,050 Btu/scf 

Maximum sulfur content (Wt.%) 0.35% 0.00% 

Maximum ash content (Wt.%) 7% 0 

Excess Combustion Air (%O2) 

Moisture content (as fired) (%) 50% 0% 

Maximum hourly consumption 86 ton/hour 22 MMCF 

Actual yearly consumption n/a n/a 

 

***** For this emissions unit, identify the method of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin CONTROL EQUIPMENT MISCELLANEOUS 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-110 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass FuelsFired Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S01 4. Unit identification number: B01

5. Control device number: C01A

6. Manufacturer and model number: Metso power - Selective Non-Catalytic Reduction (SNCR) System

7. Date of installation: New

8. Describe in detail the device in use. Attach a diagram of the system. Attached? Please refer to the permit 

application Control technology review.

9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below.

 ; Documentation is attached? 

Pollutant Inlet pollutant 

concentration 

Hood 

capture 

efficien

cy (%) 

Outlet pollutant 

concentration 

Efficiency (%) 

gr/acf ppmv gr/acf ppmv 

Nitrogen oxides (NOx) 100 100% 66 33% 

 

10. Discuss how the collected material will be handled for reuse or disposal. Not applicable – no collected material.

 

 

11. Prepare a malfunction prevention and abatement plan (if required under s. NR 439.11) for this pollution control system. 

Please include the following: 

a. Identification of the individuals(s), by title, responsible for inspecting, maintaining and repairing this device. 

b. Operation variables such as temperature that will be monitored in order to detect a malfunction or breakthrough, the 

correct operating range of these variables, and a detailed description of monitoring or surveillance procedures that will be 

used to show compliance. 

c. What type of monitoring equipment will be provided (temperature sensors, pressure sensors, CEMs). 

d. An inspection schedule and items or conditions that will be inspected. 

e. A listing of materials and spare parts that will be maintained in inventory. 

f. Is this plan available for review? 
State of Wisconsin CONTROL EQUIPMENT-BAGHOUSE/FABRIC FILTERS 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-117 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

Section A 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S01 4. Unit identification number: B01

5. Control device number: C01B

6. Manufacturer and model number: 

7. Date of installation: New

8. Describe in detail the control system. Attach a blueprint or diagram of the system. Attached? 

 

Pulse Jet Fabric Filter Baghouse 

9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below.

  Documentation is attached 

Pollutant Inlet pollutant 

concentration 

Outlet pollutant 

concentration 

Efficiency (%) 

gr/acf ppmv gr/acf ppmv 

Particulate Matter 7.5 0.011 99.85% 

 

10. Discuss how the collected material will be handled for reuse or disposal. 

The ash will be conveyed pneumatically to an ash silo, Process P132. The ash will then be loaded into fully enclosed 

tanker trucks for shipment offsite. 

 

11. Pressure drop across the filter (inches of H2O): 

12. Prepare a malfunction prevention and abatement plan (if required under s. NR 439.11) for this pollution control system. 

Please include the following: 

a. Identification of the individuals(s), by title, responsible for inspecting, maintaining and repairing this device. 

b. Bag cleaning techniques and frequency of cleaning or replacement schedule for filters. 

c. Operation variables that will be monitored in order to detect a malfunction or breakthrough, the correct operating range of 

these variables, and a detailed description of monitoring or surveillance procedures that will be used to show compliance. 

d. An inspection schedule and items or conditions that will be inspected. 

e. A listing of materials and spare parts that will be maintained in inventory. 

f. Is this plan available for review? 

Section B 

The following questions must be answered by sources installing new equipment or existing Units which cannot document control 

efficiency of this device by other means. 

13. Filter medium or type of fabric material (if fabric, indicate whether felt or woven): Felt

14. Maximum inlet gas flow rate (ACFM): 15. Maximum inlet gas temperature ( F): 

16. Number of bags if applicable: 17. Dimensions of bags/filters: 

18. Air to cloth ratio (acfm/ft2): 
State of Wisconsin EMISSION UNIT HAZARDOUS AIR POLLUTANT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-126 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S01 4. Unit identification number: B01

5. Unit material description: Biomass Fuels Combustion

6. Complete the following summary of hazardous air emissions from this unit. Attach sample calculations and emission factor 

references. Attached? 

Pollutant CAS Actual emissions Maximum theoretical emissions Potential to emit 

 Units Units 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Please refer to the permit application and the Case-By-Case Maximum 

Achievable Control Technology (MACT) analysis for detailed hazardous air 

pollutant emission calculations. 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S01 4. Unit identification number: B01

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

U TPY U TPY U TPY 

Particulates TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

TPY 

TPY 

TPY 

TPY 

TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 

Please refer to the permit application and the 

Control Technology Review (BACT) analysis for 

detailed emission calculations. 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S02 and S03 (identical stacks) 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 B02 and B03 

 . 

4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

; This stack has an actual exhaust point. □ This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: 200 (feet) 

8. Inside dimensions at outlet (check one and complete): 

; Circular 6.6 (feet) □ rectangular length (feet) width (feet) 

9. Exhaust flow rate: 

Normal 67,300 (ACFM) Maximum 67,300 (ACFM) 

10. Exhaust gas temperature (normal): 365 (F) 

11. Exhaust gas moisture content: Normal 18 volume percent Maximum 20 volume percent 

12. Exhaust gas discharge direction: ; Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin BOILER OR FURNACE OPERATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-104 11-93 Information attached? Y (y/n) 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S02 and S03 4. Boiler/furnace number: B02 and B03

4a. Unit description: 

The proposed boilers B02 and B03 will be identical package boilers designed to provide up to 125,000 pounds per hour of 

steam each. To deliver this steaming capacity, each boiler will have a maximum design heat input capacity of 175 million 

Btu per hour. The only boiler fuel will be natural gas. Each boiler will be equipped with ultra-low NOx burners and flue 

gas recirculation to control emissions of CO, NOx, PM, PM10, PM2.5, and VOCs. 

5. Indicate the boiler/furnace control technology status. ; Uncontrolled □ Controlled 

If the boiler/furnace is controlled, enter the control device number(s) from the appropriate forms: 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 .

6. Furnace type: Package Boiler 7. Maximum continuous rating: 175 mmBtu/hr (heat input)

8. Manufacturer: 9. Model number: 

10. Date of construction or last modification: NEW

 

11. Fuels and firing conditions: 

 Primary fuel Backup fuel #1 

(Startup Fuel) Backup fuel #2 Backup fuel #3 

Fuel name Natural Gas n/a n/a n/a 

Higher heating value 1,050 Btu/scf 

Maximum sulfur content (Wt.%) 0.00% 

Maximum ash content (Wt.%) 0 

Excess Combustion Air (%O2) 

Moisture content (as fired) (%) 0% 

Maximum hourly consumption 21 MMCF 

Actual yearly consumption n/a 

 

***** For this emissions unit, identify the method of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin EMISSION UNIT HAZARDOUS AIR POLLUTANT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-126 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S02 and S03 4. Unit identification number: B02 and B03

5. Unit material description: Biomass Fuels Combustion

6. Complete the following summary of hazardous air emissions from this unit. Attach sample calculations and emission factor 

references. Attached? 

Pollutant CAS Actual emissions Maximum theoretical emissions Potential to emit 

 Units Units 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Please refer to the permit application and the Case-By-Case Maximum 

Achievable Control Technology (MACT) analysis for detailed hazardous air 

pollutant emission calculations. 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S02 and S03 4. Unit identification number: B02 and B03

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

U TPY U TPY U TPY 

Particulates TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

TPY 

TPY 

TPY 

TPY 

TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 

Please refer to the permit application and the 

Control Technology Review (BACT) analysis for 

detailed emission calculations. 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S121 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 P121 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

; This stack has an actual exhaust point. □ This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: 100 (feet) 

8. Inside dimensions at outlet (check one and complete): 

; Circular 6.0 (feet) □ rectangular length (feet) width (feet) 

9. Exhaust flow rate: 

Normal 109,300 (ACFM) Maximum 109,300 (ACFM) 

10. Exhaust gas temperature (normal): Ambient (F) 

11. Exhaust gas moisture content: Normal 8 volume percent Maximum 12 volume percent 

12. Exhaust gas discharge direction: ; Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S121 4. Unit identification number: P121

4a. Unit description: Biomass Fuels Unloading, Screening, Hogging, and Conveying Dust Collector

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 C121 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 24 hrs./day 7 days/wk. 350 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

This is a dust collector for the biomass fuels unloading screening hogging, and conveying 

operations. Please refer to the permit application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Biomass Fuels Unloading 250 ton/hr 250 ton/hr 

Biomass Fuels Conveying 250 ton/hr 250 ton/hr 

Biomass Fuels Hogging 250 ton/hr 250 ton/hr 

Biomass Fuels Screening 250 ton/hr 250 ton/hr 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage 

piles, unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin CONTROL EQUIPMENT-BAGHOUSE/FABRIC FILTERS 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-117 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

Section A 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S121 4. Unit identification number: P121

5. Control device number: C121

6. Manufacturer and model number: 

7. Date of installation: New

8. Describe in detail the control system. Attach a blueprint or diagram of the system. Attached? 

 

Pulse Jet Fabric Filter Baghouse 

9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below.

  Documentation is attached 

Pollutant Inlet pollutant 

concentration 

Outlet pollutant 

concentration 

Efficiency (%) 

gr/acf ppmv gr/acf ppmv 

Particulate Matter 0.4 0.004 99% 

10. Discuss how the collected material will be handled for reuse or disposal. 

The collected material will either be returned to the Biomass fuels conveying system, or it will be disposed of in a 

landfill. 

11. Pressure drop across the filter (inches of H2O): 

12. Prepare a malfunction prevention and abatement plan (if required under s. NR 439.11) for this pollution control system. 

Please include the following: 

a. Identification of the individuals(s), by title, responsible for inspecting, maintaining and repairing this device. 

b. Bag cleaning techniques and frequency of cleaning or replacement schedule for filters. 

c. Operation variables that will be monitored in order to detect a malfunction or breakthrough, the correct operating range of 

these variables, and a detailed description of monitoring or surveillance procedures that will be used to show compliance. 

d. An inspection schedule and items or conditions that will be inspected. 

e. A listing of materials and spare parts that will be maintained in inventory. 

f. Is this plan available for review? 

Section B 

The following questions must be answered by sources installing new equipment or existing Units which cannot document control 

efficiency of this device by other means. 

13. Filter medium or type of fabric material (if fabric, indicate whether felt or woven): Felt

14. Maximum inlet gas flow rate (ACFM): 15. Maximum inlet gas temperature ( F): 

16. Number of bags if applicable: 17. Dimensions of bags/filters: 

18. Air to cloth ratio (acfm/ft2): 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S121 4. Unit identification number: P121

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 6.76 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S122 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 F122 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

□ This stack has an actual exhaust point. ; This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: (feet) 

8. Inside dimensions at outlet (check one and complete): 

□ Circular (feet) □ rectangular length (feet) width (feet) 

9. Exhaust flow rate: 

Normal (ACFM) Maximum (ACFM) 

10. Exhaust gas temperature (normal): (F) 

11. Exhaust gas moisture content: Normal volume percent Maximum volume percent 

12. Exhaust gas discharge direction: □ Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S122 4. Unit identification number: F122

4a. Unit description: Self Unloading Truck Biomass Fuels Unloading 

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 . 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 16 hrs./day 5 days/wk. 250 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

This is self unloading semi trailer truck unloading drop operation. Please refer to the 

permit application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Biomass Fuels Unloading 100 ton/hr 100 ton/hr 

 

Clean-up solvents n/a 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage 

piles, unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S122 4. Unit identification number: F122

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 0.02 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S123 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 F123 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

□ This stack has an actual exhaust point. ; This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: (feet) 

8. Inside dimensions at outlet (check one and complete): 

□ Circular (feet) □ rectangular length (feet) width (feet) 

9. Exhaust flow rate: 

Normal (ACFM) Maximum (ACFM) 

10. Exhaust gas temperature (normal): (F) 

11. Exhaust gas moisture content: Normal volume percent Maximum volume percent 

12. Exhaust gas discharge direction: □ Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S123 4. Unit identification number: F123

4a. Unit description: Biomass Fuels Storage and Reclaim 

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 . 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 24 hrs./day 7 days/wk. 350 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

This is the Biomass fuels storage and reclaim processes. Please refer to the permit 

application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Biomass Fuels Storage/Reclaim 250 ton/hr 250 ton/hr 

 

Clean-up solvents n/a 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage 

piles, unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S123 4. Unit identification number: F123

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 0.0007 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S124 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 P124 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

; This stack has an actual exhaust point. □ This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: 110 (feet) 

8. Inside dimensions at outlet (check one and complete): 

; Circular 1.0 (feet) □ rectangular length (feet) width (feet) 

 

9. Exhaust flow rate: 

Normal 600 (ACFM) Maximum 600 (ACFM) 

10. Exhaust gas temperature (normal): 90 (F) 

11. Exhaust gas moisture content: Normal 5 volume percent Maximum 10 volume percent 

12. Exhaust gas discharge direction: ; Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S124 4. Unit identification number: P124

4a. Unit description: Boiler B01 Biomass Fuels Day Bin Vents

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 C124 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 24 hrs./day 7 days/wk. 350 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

This is bin vents for two (2) the biomass-fired boiler fuel day bins. Please refer to the 

permit application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Biomass Fuels Storage 250 ton/hr 250 ton/hr 

 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage 

piles, unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin CONTROL EQUIPMENT-BAGHOUSE/FABRIC FILTERS 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-117 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

Section A 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S124 4. Unit identification number: P124

5. Control device number: C124

6. Manufacturer and model number: 

7. Date of installation: New

8. Describe in detail the control system. Attach a blueprint or diagram of the system. Attached? 

 

Fabric Filter Baghouse or cartridge Vent Filter 

9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below.

  Documentation is attached 

Pollutant Inlet pollutant 

concentration 

Outlet pollutant 

concentration 

Efficiency (%) 

gr/acf ppmv gr/acf ppmv 

Particulate Matter 0.4 0.004 99% 

10. Discuss how the collected material will be handled for reuse or disposal. 

The collected material will either be returned to the Biomass fuels day bins, or it will be disposed of in a landfill. 

 

11. Pressure drop across the filter (inches of H2O): 

12. Prepare a malfunction prevention and abatement plan (if required under s. NR 439.11) for this pollution control system. 

Please include the following: 

a. Identification of the individuals(s), by title, responsible for inspecting, maintaining and repairing this device. 

b. Bag cleaning techniques and frequency of cleaning or replacement schedule for filters. 

c. Operation variables that will be monitored in order to detect a malfunction or breakthrough, the correct operating range of 

these variables, and a detailed description of monitoring or surveillance procedures that will be used to show compliance. 

d. An inspection schedule and items or conditions that will be inspected. 

e. A listing of materials and spare parts that will be maintained in inventory. 

f. Is this plan available for review? 

Section B 

The following questions must be answered by sources installing new equipment or existing Units which cannot document control 

efficiency of this device by other means. 

13. Filter medium or type of fabric material (if fabric, indicate whether felt or woven): Felt

14. Maximum inlet gas flow rate (ACFM): 15. Maximum inlet gas temperature ( F): 

16. Number of bags if applicable: 17. Dimensions of bags/filters: 

18. Air to cloth ratio (acfm/ft2): 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S124 4. Unit identification number: P124

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 0.09 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S125 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 F125 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

□ This stack has an actual exhaust point. ; This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: (feet) 

8. Inside dimensions at outlet (check one and complete): 

□ Circular (feet) □ rectangular length (feet) width (feet) 

9. Exhaust flow rate: 

Normal (ACFM) Maximum (ACFM) 

10. Exhaust gas temperature (normal): (F) 

11. Exhaust gas moisture content: Normal volume percent Maximum volume percent 

12. Exhaust gas discharge direction: □ Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S125 4. Unit identification number: F125

4a. Unit description: Biomass Fuels Delivery Truck Haul Roads 

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 . 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 16 hrs./day 5 days/wk. 250 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

This is the Biomass fuels truck delivery haul roads. Please refer to the permit 

application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Biomass Fuels Delivery 250 ton/hr 250 ton/hr 

 

Clean-up solvents n/a 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage 

piles, unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S125 4. Unit identification number: F125

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 1.4 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S131 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 P131 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

; This stack has an actual exhaust point. □ This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: 110 (feet) 

8. Inside dimensions at outlet (check one and complete): 

; Circular 2.0 (feet) □ rectangular length (feet) width (feet) 

 

9. Exhaust flow rate: 

Normal 1,000 (ACFM) Maximum 1,000 (ACFM) 

10. Exhaust gas temperature (normal): Ambient (F) 

11. Exhaust gas moisture content: Normal 5 volume percent Maximum 10 volume percent 

12. Exhaust gas discharge direction: ; Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S131 4. Unit identification number: P131

4a. Unit description: CFB Boiler Bed Material Silo Bin Vent

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 C131 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 24 hrs./day 7 days/wk. 350 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

This is the CFB Boiler bed material silo bin vents. Please refer to the permit application. 

 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Bed Material Conveying/Storage 100 ton/hr 100 ton/hr 

 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage 

piles, unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin CONTROL EQUIPMENT-BAGHOUSE/FABRIC FILTERS 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-117 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

Section A 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S131 4. Unit identification number: P131

5. Control device number: C131

6. Manufacturer and model number: 

7. Date of installation: New

8. Describe in detail the control system. Attach a blueprint or diagram of the system. Attached? 

 

Fabric Filter Baghouse or cartridge Vent Filter 

9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below.

  Documentation is attached 

Pollutant Inlet pollutant 

concentration 

Outlet pollutant 

concentration 

Efficiency (%) 

gr/acf ppmv gr/acf ppmv 

Particulate Matter 0.4 0.004 99% 

10. Discuss how the collected material will be handled for reuse or disposal. 

The collected material will either be returned to the bed material silo, or it will be disposed of in a landfill. 

 

11. Pressure drop across the filter (inches of H2O): 

12. Prepare a malfunction prevention and abatement plan (if required under s. NR 439.11) for this pollution control system. 

Please include the following: 

a. Identification of the individuals(s), by title, responsible for inspecting, maintaining and repairing this device. 

b. Bag cleaning techniques and frequency of cleaning or replacement schedule for filters. 

c. Operation variables that will be monitored in order to detect a malfunction or breakthrough, the correct operating range of 

these variables, and a detailed description of monitoring or surveillance procedures that will be used to show compliance. 

d. An inspection schedule and items or conditions that will be inspected. 

e. A listing of materials and spare parts that will be maintained in inventory. 

f. Is this plan available for review? 

Section B 

The following questions must be answered by sources installing new equipment or existing Units which cannot document control 

efficiency of this device by other means. 

13. Filter medium or type of fabric material (if fabric, indicate whether felt or woven): Felt

14. Maximum inlet gas flow rate (ACFM): 15. Maximum inlet gas temperature ( F): 

16. Number of bags if applicable: 17. Dimensions of bags/filters: 

18. Air to cloth ratio (acfm/ft2): 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S131 4. Unit identification number: P131

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 0.15 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S132 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 P132 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

; This stack has an actual exhaust point. □ This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: 75 (feet) 

8. Inside dimensions at outlet (check one and complete): 

; Circular 2.0 (feet) □ rectangular length (feet) width (feet) 

 

9. Exhaust flow rate: 

Normal 1,000 (ACFM) Maximum 1,000 (ACFM) 

10. Exhaust gas temperature (normal): Ambient (F) 

11. Exhaust gas moisture content: Normal 5 volume percent Maximum 10 volume percent 

12. Exhaust gas discharge direction: ; Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S132 4. Unit identification number: P132

4a. Unit description: CFB Boiler Ash Silo

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 C132 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 24 hrs./day 7 days/wk. 350 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

This is the CFB boiler ash silo bin vents. Please refer to the permit application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Biomass Fuels 

Ash Conveying/Storage 50 ton/hr 50 ton/hr 

 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage 

piles, unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin CONTROL EQUIPMENT-BAGHOUSE/FABRIC FILTERS 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-117 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

Section A 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S132 4. Unit identification number: P132

5. Control device number: C132

6. Manufacturer and model number: 

7. Date of installation: New

8. Describe in detail the control system. Attach a blueprint or diagram of the system. Attached? 

 

Fabric Filter Baghouse or cartridge Vent Filter 

9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below.

  Documentation is attached 

Pollutant Inlet pollutant 

concentration 

Outlet pollutant 

concentration 

Efficiency (%) 

gr/acf ppmv gr/acf ppmv 

Particulate Matter 0.4 0.004 99% 

10. Discuss how the collected material will be handled for reuse or disposal. 

The collected material will either be returned to the ash silo, or it will be disposed of in a landfill. 

 

11. Pressure drop across the filter (inches of H2O): 

12. Prepare a malfunction prevention and abatement plan (if required under s. NR 439.11) for this pollution control system. 

Please include the following: 

a. Identification of the individuals(s), by title, responsible for inspecting, maintaining and repairing this device. 

b. Bag cleaning techniques and frequency of cleaning or replacement schedule for filters. 

c. Operation variables that will be monitored in order to detect a malfunction or breakthrough, the correct operating range of 

these variables, and a detailed description of monitoring or surveillance procedures that will be used to show compliance. 

d. An inspection schedule and items or conditions that will be inspected. 

e. A listing of materials and spare parts that will be maintained in inventory. 

f. Is this plan available for review? 

Section B 

The following questions must be answered by sources installing new equipment or existing Units which cannot document control 

efficiency of this device by other means. 

13. Filter medium or type of fabric material (if fabric, indicate whether felt or woven): Felt

14. Maximum inlet gas flow rate (ACFM): 15. Maximum inlet gas temperature ( F): 

16. Number of bags if applicable: 17. Dimensions of bags/filters: 

18. Air to cloth ratio (acfm/ft2): 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S132 4. Unit identification number: P132

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 0.15 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S133 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 F133 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

□ This stack has an actual exhaust point. ; This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: (feet) 

8. Inside dimensions at outlet (check one and complete): 

□ Circular (feet) □ rectangular length (feet) width (feet) 

9. Exhaust flow rate: 

Normal (ACFM) Maximum (ACFM) 

10. Exhaust gas temperature (normal): (F) 

11. Exhaust gas moisture content: Normal volume percent Maximum volume percent 

12. Exhaust gas discharge direction: □ Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S133 4. Unit identification number: F133

4a. Unit description: Boiler Ash Truck Haul Roads 

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 . 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 16 hrs./day 5 days/wk. 250 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

This is CFB boiler ash truck haul roads. Please refer to the permit application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

CFB Boiler Ash Hauling 50 ton/hr 50 ton/hr 

 

Clean-up solvents n/a 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage 

piles, unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S133 4. Unit identification number: F133

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 0.05 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S141 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 P141 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

; This stack has an actual exhaust point. □ This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: 70 (feet) 

8. Inside dimensions at outlet (check one and complete): 

; Circular 25 (feet) □ rectangular length (feet) width (feet) 

This is the exit for the proposed new cooling tower. This cooling tower will have 

6 cells. 

9. Exhaust flow rate: 

Normal 736,000 (ACFM) Maximum 736,000 (ACFM) 

10. Exhaust gas temperature (normal): 50 (F) 

11. Exhaust gas moisture content: Normal 10 volume percent Maximum 15 volume percent 

12. Exhaust gas discharge direction: ; Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S141 4. Unit identification number: P141

4a. Unit description: Mechanical Draft Cooling Tower

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 . 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 24 hrs./day 7 days/wk. 350 days/yr. 

9. Describe this process (please attach a flow diagram of the process). 

Mechanical Draft Cooling Tower. Please refer to the permit application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Circulating 

Water 22,000 gal/min 22,000 gal/min 

 

Clean-up solvents n/a 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

None 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

None 

13. Describe any fugitive emissions associated with this process, such as outdoor storage piles, 

unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S141 4. Unit identification number: P141

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates n/a 0.39 TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 
State of Wisconsin STACK IDENTIFICATION 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-103 11-93 Information attached? Y (y/n) 

1. Facility name: 2. Facility identification number: 3. Stack identification number: 

We Energies – Biomass Fuels-Fired 

Cogeneration Facility 

New S151 

4. Exhausting Unit(s), use Unit identification number from appropriate Form(s) 4530-104, 106, 107, 108 and/or 109 

4530-104 P151 . 4530-106 

 

4530-107 4530-108 4530-109 

5. Identify this stack on the plot plan required on Form 4530-101 – 

6. Indicate by checking: 

; This stack has an actual exhaust point. □ This stack serves to identify fugitive emissions. 

If this stack has an actual exhaust point, then provide the following stack parameters 

7. Discharge height above ground level: 195 (feet) 

8. Inside dimensions at outlet (check one and complete): 

; Circular 0.7 (feet) □ rectangular length (feet) width (feet) 

9. Exhaust flow rate: 

Normal 3,000 (ACFM) Maximum 3,000 (ACFM) 

10. Exhaust gas temperature (normal): 800 (F) 

11. Exhaust gas moisture content: Normal 10 volume percent Maximum 15 volume percent 

12. Exhaust gas discharge direction: ; Up □ Down □ Horizontal 

13. Is this stack equipped with a rainhat or any obstruction to the free flow of the 

exhaust gases from the stack? 

□ Yes ; No 

***** Complete the appropriate Air Permit Application Forms(s) 4530-104, 106, 107, 108 or 109 for each Unit ***** 

exhausting through this stack. 
State of Wisconsin MISCELLANEOUS PROCESSES 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-109 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S151 4. Unit identification number: P151

4a. Unit description: Emergency Diesel Engine Feed Water Pump

5. Indicate the control technology status.  Uncontrolled ; Controlled 

If the process is controlled, enter the control device number(s) from the appropriate form(s): 

4530-110 4530-111 4530-112 4530-113 

4530-114 4530-115 4530-116 4530-117 . 

6. Source Classification Code (SCC): 

7. Date of construction or last modification: New

8. Normal operating schedule: 1 hrs./day 1 days/wk. 12 days/yr. (Normal operation is for testing only.)

9. Describe this process (please attach a flow diagram of the process). 

400 hp Diesel Engine Driven Emergency Feed Water Pump. Please refer to the permit 

application. 

Attached? 

Yes 

10. List the types and amounts of raw materials used in this process: 

Material Storage/material 

handling process Average usage Units Maximum usage Units 

Demineralized 

Water Pumping 200 gal/min 200 gal/min 

 

Clean-up solvents n/a 

Other (specify) n/a 

11. List the types and amounts of finished products: 

Material Storage/material 

handling process 

Average amount 

produced Units Maximum amount produced Units 

 

12. Process fuel usage: 

Type of fuel 

Maximum heat input to 

process 

million BTU/hr. 

Average usage Units Maximum usage Units 

Diesel Fuel 3.4 24 gal/hr 24 gal/hr 

13. Describe any fugitive emissions associated with this process, such as outdoor storage piles, 

unpaved roads, open conveyors, etc.: 

Please refer to the permit application for a description of this process. Attached? 

***** For this emissions unit, identify the method(s) of compliance demonstration by completing Form 4530-118, ***** 

DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 4530-118 

and its attachment(s) to this form. This is not a requirement of non-Part 70 sources. 

***** Please complete the Air Pollution Control Permit Application Forms 4530-126 and 4530-128 for this Unit. ***** 
State of Wisconsin EMISSION UNIT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-128 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Stack identification number: S151 4. Unit identification number: P151

5. Complete the following emissions summary for the following pollutants. Attach sample calculations and emission factor 

references. Attached? Yes 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

 U TPY U TPY U TPY 

Particulates TPY 

Sulfur dioxide TPY 

Organic compounds TPY 

Carbon monoxide TPY 

Lead TPY 

Nitrogen oxides TPY 

Total reduced sulfur TPY 

Mercury TPY 

Asbestos TPY 

Beryllium TPY 

Vinyl chloride TPY 

 TPY 

 TPY 

 TPY 

 TPY 

 TPY 

Units (U) should be entered as follows: 

1 = lb/hr 

2 = lb/mmBTU 

3 = grains/dscf 

4 = lb/ gallon 

5 = ppmdv 

6 = other (specify) 

7 = other (specify) 

8 = other (specify) 

Please refer to the permit application and balance of 

plant control technology review for detailed air pollutant 

emission calculations. 
State of Wisconsin FACILITY HAZARDOUS AIR POLLUTANT SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-127 11-93 Information attached? Y (y/n) 

SEE INSTRUCTIONS ON REVERSE SIDE 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Complete the following emissions summary for all hazardous air emissions at this facility (as defined in ch. NR 445, Wis Adm. 

Code, and sec. 112, 1990 Clean Air Act Amendments): 

Pollutant CAS Actual emissions Maximum theoretical emissions Potential to emit 

Units Units 

 

TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

 TPY

Please refer to the permit application and the Case-By-Case Maximum 

Achievable Control Technology (MACT) analysis for detailed hazardous air 

pollutant emission calculations. 
State of Wisconsin FACILITY EMISSIONS SUMMARY 

Department of Natural Resources AIR POLLUTION CONTROL PERMIT APPLICATION 

Form 4530-129 11-93 Information attached? Y (y/n) 

1. Facility name: We Energies – Biomass Fuels-Fired 

Cogeneration Facility 2. Facility identification number: New

3. Complete the following emissions summary for the listed emissions at this facility. 

Air pollutant Actual Maximum theoretical 

emissions 

Potential to emit Maximum allowable 

TPY TPY TPY TPY 

Carbon Monoxide n/a 766 

Nitrogen Oxides n/a 372 

Particulate Matter (PM/PM10) n/a 131 

Particulate Matter (PM2.5) n/a 97 

Sulfur Dioxide n/a 316 

Volatile Organic Cmpds n/a 66 

Lead n/a 0.11 

Mercury n/a 0.010 

Fluorides (as HF) n/a 4.2 

Sulfuric Acid Mist n/a 3.2 

Hydrogen Chloride (HCl) n/a 63.1