## 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 E NVIRONMENTAL A SSOCIATES I NC .®
903 Superior Avenue, Suite 6 Tomah, WI 54660Air 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 megawa tt (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 w ill 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 Proj ect 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 (NO x ), particulate matter (PM/PM 10 ), fine particulate matter (PM 2.5 ), sulfur dioxide (SO 2 ), 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 NO x 372 40 YES Particulate Matter PM/PM 10 131 15 YES Particulate Matter PM 2.5 97 10 YES Sulfur Dioxide SO 2 316 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 H 2 SO 4 6.3 7 NOAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

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## Control Technology Review.

A control technology review or Best Available C ontrol Technology (BACT) analysis was conducted for each proposed new emissions unit. For the biomas s-fired Boiler B01, We Energies is proposing an advanced circulating fluidized bed boiler designed to fi re 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 NO x emissions, and a fabric filter baghouse for the control of PM, PM 10 , and PM 2.5 emissions.
For the natural gas-fired Boilers B02 and B03, We Energies proposes to install package boilers equipped with ultra low NO x burners for the control of NO x , 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 a nd 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 (NO x ) Circulating Fluidized Bed Boiler and Selective Non-Catalytic Reduction 0.10 350

PM < 10 microns (PM 10 ) Fabric Filter Baghouse 0.03 105

PM < 2.5 microns (PM 2.5 ) Fabric Filter Baghouse with Felted Filter Media Bags 0.023 81

Sulfur Dioxide (SO 2 ) 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 3.5Air 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, NO 2 , PM, PM 10 , PM 2.5 , and SO 2 . Dispersion modeling impact analysis was completed and illust rates 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 Si gnificant Deterioration (“PSD”) increment. The results of the cumulative NAAQS analysis demonstrat e 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 impact s that exceed the PSD increments.
In the dispersion modeling analysis, a significant im pact 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 significan t 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, NO 2 and the annual SO 2 standard. This means that the Project will have an insigni ficant 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, μ g/m 3 Highest Modeled Concentration, μ g/m 3

8-hour 500 99 CO 1-hour 2,000 209

NO 2 Annual 1 0.92

Annual 1 0.98

24-hour 5 12.6 SO 2 3-hour 25 55.6

Annual 1 5.6 PM 10 24-hour 5 20.4

Annual 0.3 1.2 PM 2.5 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 n earby sources, and the background concentrations of these air pollutants. The results of the cumulative N AAQS 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

- v - If the proposed source's maximum modeled air pollutant concentrations exceed th e SIL for any pollutant and averaging interval, a cumulative PSD increment imp act analysis is also performed for that pollutant and averaging interval. The resu lts of the cumulative Class II PSD increment analysis are summarized in Table ES-4. The SO 2 3-hr and 24-hr and the PM 10 24-hr concentrations are the highest second-high concentrations. The PSD increment results demonstr ate 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/m 3 Background, μg/m 3 Total, μg/m 3 NAAQS μg/m 3 % of NAAQS

NO 2 1-hour 61 11.9 73.2 188 39%

24-hour 249 11.2 260.2 365 71% SO 2 3-hour 951 11.8 962.8 1300 74%

PM 10 24-hour 41.8 29.4 71.2 150 47%

Annual 2.3 8.7 11.0 15 73% PM 2.5 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/m 3 PSD Increment ug/m 3 % of PSD Increment

Annual 5.7 17 34% PM 10 24-hour 21.0 30 70%

24-hour 86.1 91 95% SO 2 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 Applicat ion. ..................................................... 10
Chapter 2. Project Des cription ..................................................................... 11

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

2.2 Biomass-fired Circulating Fl uidized Bed Boiler B01. ....................................................................15

2.2.1 Fluidized Bed Boiler Technology. ....................................................................................15
2.2.2 CFB Boiler Fuels. .............................................................................................................1 6 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 Di esel Feed Water Pump. ....................................................................22

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

## Chapter 3. Project Emi ssions ........................................................................ 24

3.1 Biomass-fired Circulating Fl uidized 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 Fuel s 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. .................................................................................................. .....29We 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

- 7 - 3.7 Process P151: Emergency Diesel Engine Feed Water Pump.........................................................31 

## Chapter 4. Applicable Air Pollution Control Regu lations. ....................... 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 Ai r 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. ........................................................................................4 0

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. ........................................................................................4 4

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

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

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

6.2 Natural Gas-Fired Boilers B02 and B03. ........................................................................................4 9 

## Chapter 7. Dispersion Modelin g 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 Impa cts Anal ysis...................................................... 55

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

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

8.3 Class I Air Quality Anal ysis Requirements.....................................................................................5 6We 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 Cogene ration 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 m echanical draft cooling tower, Process P141. .................30
TABLE 3-4. Potential emissions for the diesel engi ne driven fire pump based on limiting operation to 100 hours per year............................................................................................................. ...31
TABLE 4-1. Total facility emissions and the PSD a pplicability 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 emis sion limits representing BACT for the biomass-fired boiler B01..................................................................................................................... ........43
TABLE 5-2. Proposed control technologies and emi ssion limits representing BACT for the natural gasfired Boilers B02 and B03....................................................................................................44
TABLE 5-3. Proposed control technologies and emi ssion 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 emissi ons 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 standa rd (NAAQS), modeling Significance Levels, and PSD Class II Increment, ug/m 3 ....................................................................................................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. .....................................................................54We 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’ propo sed 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 Energi es’ 50 MW biomass-fired cogeneration facility. FIGURE 2-4. Typical CFB boiler power block show ing the furnace, cyclone, baghouse, and stack. FIGURE 2-5. Diagram of the biomass fuels re ceiving, 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 Av ailable Control Technology (BACT) Analysis for the 50 MW Biomass-Fired Electric Generating Unit.
APPENDIX B. Control Technology Review - Best Av ailable Control Technology (BACT) Analysis for the Natural Gas-Fired Boilers.
APPENDIX C. Control Technology Review - Best Av ailable 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-Fuel ed Boiler under Section 112(g) of the Clean Air Act.
APPENDIX E. Dispersion modeling analysis.
APPENDIX F. Wisconsin Department of Natural Re sources - 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 fo r 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 pollu tant 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 unde r Section 112(g) of the Clean Air Act.
Chapter 7. Summary of the dispersion modeling analysis.
Appendix E is the detailed di spersion modeling analysis.
Chapter 8. Additional impacts analysis as required un der 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 constr uct a 50 megawatt, biomass-fired coge neration 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 th e 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 (B usiness 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 thor oughfare 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 elect ric power, and will also provide process steam for the Domtar Mill. The facility will include a new ci rculating fluidized bed (CFB) boiler which will be fueled by biomass fuels including wood, bark, pape rmill sludge, and other clean biomass fuels. The facility will also include two natural gas-fired packag e boilers which will provide steam for the Mill when the CFB boiler is unavailable. The facility will incl ude biomass fuel receiving, unloading, storage, and conveying processes, boiler bed material and ash hand ling 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 PumpWe 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

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

We Energies Biomass Cogeneration Facility

NORTH

Scale, miles 5 0 5 10We 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

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

We Energies Biomass Cogeneration FacilityWe 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

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

Biomass Fuels Storage Building

New Boilerhouse
and Stack S01

New Cooling
Tower Existing Mill

Existing MillWe 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 bo iler fuels will be logging residue, wood, bark, wood waste, forest residues, and wastewater treatment pl ant sludge from the Domtar Paper Mill. The boiler will also be designed to fire natural gas for a st artup 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 filte r baghouse, and the stack is shown in Figure 2-4. Note that there is additional boiler informati on in Appendix A to this permit application.

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



### 2.2.1 Fluidized Bed Boiler Technology.
The atmospheric pressure, fluidized bed bo iler technology was developed to minimize SO 2 and NO x emissions from the combustion of high sulfur fuels su ch as coal and petroleum coke. The fluidized bed boiler combustion process minimizes NO x formation and removes SO 2 in the boiler before post combustion air pollution control systems. Fluidized be d boilers are also excellent boilers for firing highly variable and low heat value fuel s 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

- 16 - 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 fluidizi ng 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 retu rned to the furnace to improve combustion efficiency.



### 2.2.2 CFB Boiler Fuels.
The primary fuel for the CFB boiler will be biomass fu els, including logging residues, wood, bark, wood waste, forest residues, and wastewater treatment pl ant 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 bi omass fuels consumption ra te will be 45 tons per hour on a dry basis, or approximately 84 tons per h our 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 en ergy 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 wo od waste, tree services, and construction companies

• clean solid wood waste from discarded wood packaging such as pallets/crating and from constr uction 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

- 17 - 

### 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 pr essure, high temperature steam will be fed to a new 50 MW (electric) steam turbine electric generator se t. 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 sing le 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 si lo 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 conv eyor system which will transfer the ash to the ash silo. The sand consumption will be depe ndent 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 NO x 

### 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 bo ilers 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 NO x burners and flue gas recirculati on to control emissions of CO, NO x , PM,
PM 10 , PM 2.5 , and VOCs.We Energies - Air Pollution Control Construction Permit Application for a50 MW Renewable Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix A: Control Technology Review for the Biomass-Fired Boiler.March, 2010-18 -TABLE 2-2. We Energies’ Biomass Cogeneration Facility thermal performance.Boiler Output *100% MCR100% MCR100% MCR80% MCR80% MCR80% MCR****60% MCR60%MCR ****Outlet steam flow to Domtarlb/hr *0 200,000 300,000 0 200,000 280,000 0 200,000Fuel Demand, mmBtu/hr ** 682 781 785 549 630 634 416 479Fuel Demand, tons/hr ** 75 86 87 61 70 70 46 53Boiler Efficiency 78.2% 78.2% 78.2% 77.6% 77.6% 77.6% 77.0% 77.0%Steam flow to turbine, lb/hr 483,000 550,000 550,000 385,000 440,000 440,000 290,000 330,000Turbine output, Gross MW 57 51 43 45 36 28 33 21Unit output, Net MW 50 44 37 38 30 21 27 15Turbine Heat Rate, Btu/kWh 9,321 11,855 14,118 9,497 13,489 17,716 9,841 17,396Net Electric Heat Rate,Btu/kWh ***13,361 10,944 9,343 14,314 11,191 8,778 15,669 11,728Overall Plant CogenerationEfficiency ***25.0% 48.9% 60.0% 23.8% 52.7% 66.1% 21.8% 59.1%Footnotes* % of Maximum Continuous Rating (MCR) -- Boiler output inlb/hr is based on steam delivered at 1550 psi and 950oF.* Outlet steam flow to Domtar-RothschildMill in lb/hr is based on 180 psi and 450oF temperature steam extraction from the turbine.** Fuel demand based on the estimated fuel moisture content of 39%*** Efficiency based on steam utilization by Domtar-Rothschild Mill.**** Minimum condenser flow cases.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 19 - 

## 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 ope rations 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 whic h 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 th e 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 H og Building. In the Hog Building, the fuels will be shredded in a hog to the final size required to fire th e 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 r eclaimed, the fuel will be conveyed to Transfer Tower No. 1, and then to the CFB Boile r fuel silos for combustion.
To control fugitive dust emissions from these opera tions, 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 th ese 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 th at will control dust from the unloading, conveying, hogging, and conveying operations. This process w ill 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.Air Pollution Control Construction Permit ApplicationRTP Environmental Associates, Inc.We Energies – 50 MW Biomass-Fired Cogeneration FacilityMarch, 2010-20 -FIGURE 2-5. Diagram of the biomass fuelsreceiving, conveying, and storage processes.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 21 - FIGURE 2-6. Photo of a truck dumper and A-fram e 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 no ted previously, the majority of the biomass fuels received will normally be delivered by fixed bed tr ucks which will be unloaded using the truck dumper which is included as part of Process P121. For th e 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 buildin g, the biomass fuels will drop from the conveyor onto a pile. The fuels will then be reclaimed from the st orage 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 bu ilding and conveyed via totally enclosed conveyors to the boiler fuel silos located insi de the boilerhouse. The fuel silos will include bin vents to vent the silos when filling and emptying.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 22 - 

### 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. Therefor e, the total theoretical maximum annual paved road vehicle miles traveled will be 17,754 miles per year. No te 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 sy stem 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 w ill be hauled from the site by totally enclosed pneumatic semi-trailer trucks. The maximum ash ge neration rate would be 29, 200 tons per year. Based on a vehicle capacity of 25 tons, this annual ash ge neration rate would require 1,168 shipments. In addition, the maximum daily haul rate would be 8 sh ipments 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 Fac ility will require a new mechanical draft cooling tower which will be designated as Process P141. Th is 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 cylinde r. 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 opera tional limits of no more than 100 hours in any 12 consecutive month period.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 23 - 

## 2.9 Project Schedule.

The overall project schedule is summarized in Tabl e 2-3. Construction activities would start in February, 2011 with commencement of the support f acilities, and continue until the completion of the unit in September 2013. Commercial opera tion 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 Bo iler Vendor for Construction ....................2/2011

Construction Mobilization to Site.............................................................................4/2011
Boiler Commissioning..............................................................................................2/2013
Project Commercial Operation .................................................................................9/2013Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 24 - 

# 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 emission s 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 NO x 0.15 800 120 526 33% 0.10 80.0 350.4

Particulate Matter PM / PM 10 12.0 800 9,600 42,048 99.75% 0.030 24.0 105.1

Particulate Matter PM 2.5 9.0 800 7,200 31,536 99.74% 0.023 18.4 80.6

Sulfur Dioxide SO 2 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 H 2 SO 4 0.0018 800 1.4 6.3 0.0018 1.4 6.3

Footnotes
1. Potential controlled emission rates for CO, NO x , PM/PM 10 , PM 2.5 , SO 2 , 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.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 25 - 

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

The potential emissions for each natural gas-fire d 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/mmft 3 lb/mmBtu mmBtu/hr lb/hr tons/yr

Carbon Monoxide CO 63.0 0.06 175 10.50 32.6
Nitrogen Oxides NO x 21.0 0.02 175 3.50 10.9

Particulate Matter PM/PM 10 7.6 0.0076 175 1.33 4.1

Particulate Matter PM 2.5 7.6 0.0076 175 1.33 4.1

Sulfur Dioxide SO 2 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 H 2 SO 4 0.006 0.000006 175 0.0011 0.0033

Footnotes 1. For natural gas combustion, the CO and NO x 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 NO x emission rates of 0.10 and 0.02 lb/mmBtu, respectively.

E = KC h F( 20.9) where, E = Emission Rate, lb/mmBtu 20.9 - %O 2 F = F-Factor, dscf/mmBtu

Natural Gas Combustion K C h , ppm F , dscf/mmBtu %O 2 E , lb/mmBtu Carbon Monoxide CO 7.59E-08 75 8,710 5.0 0.058 Nitrogen Oxides NO x 1.19E-07 9 8,710 5.0 0.012
2. The emission factors for uncontrolled PM, PM 10 , PM 2.5 , 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 PM 10 emissions are assumed to be PM 2.5 . 3. Sulfuric acid mist emissions for natural gas combustion are based on 1% conversion of SO 2 to SO 3 . 6. Potential emissions are based on limiting the fuel use to:

Natural Gas: HI = 1,085,000 mmBtu, 12-month average 6,200 hour/yrAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 26 - 

## 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/PM 10 , and PM 2.5 emissions to a maximum design outlet grain loading of 0.004 gr/dscf, and 0.002 gr/dscf, respectiv ely. Therefore, the maximum PM/PM 10 , and PM 2.5 emission rates are:
E = (109,300 ft 3 /min)(60 min/hr)(0.004 gr/ft 3 )(1.0 lb/7,000 gr) = 3.75 lb PM/PM 10 /hr
E = (3.75 lb/hr)(8,760 hr/yr)(1.0 ton/2,000 lb) = 16.4 ton PM/PM 10 /yr

E = (109,300 ft 3 /min)(60 min/hr)(0.002 gr/ft 3 )(1.0 lb/7,000 gr) = 1.87 lb PM 2.5 /hr
E = (1.87 lb/hr)(8,760 hr/yr)(1.0 ton/2,000 lb) = 8.2 ton PM 2.5 /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 , 5 th Edition, section 13.2.4, Equation 1 may be us ed for estimating emissi ons from this unloading process which is a drop operation:

4

. 1 3

. 1



### 2 5 ) 0032

. 0 ( ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= M U

k E

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 PM 2.5 ) = 0.35 (for PM 10 ) = 0.74 (for PM )

The normal moisture content for biom ass fuels is expected to range fro m 25-50% on an as-received basis. Based on a mean wind speed of 6.9 miles per hour, th e uncontrolled emission fact or for unloading biomass fuels is 0.0000075 lb/ton (PM 2.5 ), 0.0000496 lb/ton (PM 10 ), and 0.00010 lb/ton (PM).
As noted previously, the majority of the biomass fu els 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 reclai m hopper, the maximum theore tical truck unloading rateAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 27 - 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. Base d on these values, the maximum uncontrolled PM 2.5 , PM 10 , 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 , 5 th Edition, section 13.2.4, Equation 1:

4

. 1 3

. 1



### 2 5 ) 0032

. 0 ( ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= M U

k E

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 PM 2.5 ) = 0.35 (for PM 10 ) = 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 m iles per hour inside the building, the uncontrolled emission factor for unloadi ng biomass fuels is 6.0 x 10 -7 lb/ton (PM 2.5 ), 4.0 x 10 -6 lb/ton (PM 10 ), and 8.5 x
10 -6 lb/ton (PM). Based on these values, the maximum uncontrolled PM 2.5 , PM 10 , 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 sta ndard cubic foot of exhaust gas. Based on the control technology review, we have concluded that th e bin vents can achieve a PM and PM 10 outlet grain loading of 0.004 gr/dscf, and a PM 2.5 outlet grain loading of 0.002 gr/dscf. Therefore, potential controlled PM/PM 10 emissions would be 0.01 lb/hr and 0.045 ton/yr; potential controlled PM 2.5 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 W sL k EF

u 

### − ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= 5

. 1 65

. 0



### 3 2

where, EF u = Vehicle Emission Factor, lb/mile traveledAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 28 - k

= 0.0024 [Table 13.2.1-1, for PM 2.5 ] = 0.016 [PM 10 ] = 0.082 [PM]
sL = silt loading, g/m 2 = 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 PM 2.5 ] C = 0.00047 lb/VMT [Table 13.2.1-2, for PM 10 and PM]

The silt loading of 0.6 g/m 2 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 fa ctors of 0.030 pounds per vehicle mile traveled (lb/VMT) for PM 2.5 , 0.20 lb/VMT (PM 10 ), and 1.04 lb/ton (PM).
The renewable fuel haul trucks are expected to de liver 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
PM 2.5 , PM 10 , 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 a nd the ash silo bin vent are expected to have a volumetric flow rate of 1,000 acfm (each). Based on the control technology re view, we have concluded that the bin vents can achieve a PM and PM 10 outlet grain loading of 0.004 gr/dscf, and a PM 2.5 outlet grain loading of 0.002 gr/dscf. Therefore, potential controlled PM/PM 10 emissions for each process would be 0.034 lb/hr and 0.15 ton/yr; potential controlled PM 2.5 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 woul d require 1,168 shipments. In add ition, the maximum daily haul rate would be 8 shipments per day. The total paved road r ound trip travel for each delivery is expected to be 3,000 feet, or 0.57 mile. Therefore, the total annua l 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 PM 2.5 , PM 10 , and PM emissions for the ash truc k traffic would be 0.01, 0.07, and 0.35 tons per year, respectively.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 29 - 

## 3.6 Process P141: Cooling Tower.

In a mechanical draft cooling tower, the circulating c ooling 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 evapor ates, cooling the remaining water. A small amount of the water is entrained in the induced air flow in th e 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, PM 10 , and PM 2.5 emissions.

Cooling tower PM emissions are calculated based on th e circulating water flow rate, the total dissolved solids (TDS) in the circulating water, and the desi gn drift loss according to the following equation:



### ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= 100 %DL
10 C ) water/gal lb 345

. 8 ( min/hr) 60 ( E 6 TDS 

### kQ

Where, E = Particulate matter emissions, pounds per hour Q = Circulating water flow ra te, gallons per minute = 22,000 gpm
C TDS = 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 ai rborne particle that would be produced by the evaporation of the liquid water from a drift droplet is given by the following equation 1 :

Where, d droplet = Maximum diameter of the drift droplet that would produce a dry particle size of d particle or smaller d particle = Dry particle (particulate matter) particle size, microns

ρ salt = Density of particle = 2.5 g/cm 3

ρ water = Density of water = 1.0 g/cm 3
C TDS = Circulating water total dissolved solids, parts per million, ppm

For a circulating water total disso lved solids (TDS) level of 1,600 ppm, the drift loss droplet size would need to be smaller than 116 microns in size to form PM 10 emissions, and less than 29 microns to form
PM 2.5 . The table below is the drift loss droplet size distri bution 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. 3 / 1 6 

### 10 ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

=

TDS water salt particle droplet 

### C d d ρ ρAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 30 - 82% of the cooling tower drift loss (i.e., droplet part icle sizes less than 130 microns), would result in
PM 10 emissions, and 0.23% of the cooling tower drift loss would result in PM 2.5 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 PM 10 Emissions from Cooling Towers."

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

Flowrate C TDS 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 PM 10 22,000 1,600 0.0005% 0.82 0.072 0.317

Particulate Matter PM 2.5 22,000 1,600 0.0005% 0.0023 0.00020 0.00087Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 31 - 

## 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 en gine 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 NO x 3.00 400 2.64 0.13
Particulate Matter PM/PM 10 0.15 400 0.132 0.0066
Particulate Matter PM 2.5 0.12 400 0.106 0.0053
Sulfur Dioxide SO 2 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 H 2 SO 4 0.00057 400 0.00050 0.000025

Footnotes

1. NO x , PM, and PM 10 , 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. SO 2 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 SO 2 /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 10 12 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.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 32 - 

# 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 fac ility 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 (NO x ), particulate matter (PM/PM 10 ), fine particulate matter (PM 2.5 ), sulfur dioxide (SO 2 ), organic compounds (VOC), and fluorides (as HF). Note that this PSD applicability analysis is based only on the new fac ility. 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 NO x 350.4 21.7 0.13 372 40 YES

Particulate Matter PM 10 105.1 8.2 0.007 17.1 0.3 131 15 YES

Particulate Matter PM 2.5 80.6 8.2 0.005 8.4 0.0009 97 10 YES

Sulfur Dioxide SO 2 315.4 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 H 2 SO 4 6.3 0.007 0.000025 6.3 7 NOAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 33 - 

## 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 st eam generating units are contained in NR 440.20, Wis. Adm. Code and 40 CFR Part 60, Subpart Da. Th e 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 othe r fuel, and for which construction or modification is commenced after September 18, 1978. Boiler B01 w ill have a maximum design heat input when firing natural gas of less than 250 mmBtu per hour. Therefor e, 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 industria l – 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 constr uction, 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 (NO x ): 0.10 lb/mmBtu.
The current Subpart Db rules for NO x emissions were published in the Fe deral 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 NO x emission rate of 0.30 lb/mmBtu heat input unless the aff ected facility has an annual capacity factor for natural gas of 10% or less and is subject to a federally enforceable requireme nt 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 wh ich 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 capac ity factor of 10% or less for coal, oil, and natural gas. Under (2), if the affected facility has a low he at release rate and combusts natural gas or distillate oil in excess of 30 percent of the heat input from the co mbustion of all fuels, the limit is determined as:
En = [(0.10 * Hgo) + (0.20 * Hr)]/(Hgo + Hr)
Where, En = NO x 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.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 34 - 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 i nput) on an annual basis, and has a maximum heat input capacity greater than 250 mmBtu/hr may not ex ceed 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 e xhibit 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 durin g periods of startup, shutdown, or malfunction.

4.2.1.3 Sulfur Dioxide (SO 2 ): 0.20 lb/mmBtu.
The current Subpart Db rules for SO 2 emissions were published in the Fe deral 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 SO 2 emission rate of 0.20 lb/mmBtu, or 2) 8% of the potential SO 2 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 Nationa l 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 ma jor source” in 40 CFR. § 63 .41(2). Boiler B01 will be constructed at an existing fac ility 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,Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 35 - 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 adde d 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-fire d CFB boiler is the only unit subject to section 112(g), since it is the only unit associated with this Pr oject 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 Progr am. 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 (NO x ) and sulfur dioxide (SO 2 ) emissions which the EPA linked to the interstate transport of fine particulate matter (PM 2.5 ). The CAIR is based on a cap-and-trade program in which affected sources use allowances to cover NO x and SO 2 emissions. In Wisconsin,
CAIR NO x allowances are allocated under NR 432, Wis. Adm. Code.

NR 432.01 Applicability; purpose. (1) A PPLICABILITY. (a) This chapter applies to the owner or operator of any source that includes a CAIR NO x unit or a CAIR renewable unit. A CAIR NO x 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 w ith nameplate capacity of more than 25 MWe producing electricity fo r sale, except for those units that are excluded under par. (b).
Note: In addition, a CAIR NO x 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 biomas s fuels, Boiler B01 will also fire natural gas – a fossil fuel – during startup and load stabilization. B ecause Boiler B01 will fire a fossil fuel and will serve a generator with nameplate capacity of more than 25 MWe and will produ ce 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 th at generates renewable energy serving a generator with nameplate capacity greater than 25 MWe. Because “renewable energy”Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 36 - 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 Accide ntal Releases (40 CFR Part 68).

The CAA amendments of 1990 includ ed language that requires chemic al 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 relea ses 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 thresh old 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. Regard less, 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) unde r NR 445, Wis. Adm. Code. The applicability and purpose under NR 445.01 is stated below.

NR 445.01 Applicability; purpose. (1) A PPLICABILITY. (a) This chapter applies to all stationary air contaminant sources which may emit hazar dous 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 activ ities that are regulated by an emission standard promulgated unde r 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 measur e contaminant. Exampl es 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 h azardous air co ntaminants.

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 st andard under section 112 of the Clean Air Act. TheAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 37 - 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 u se 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 anal ysis for the biomass-fired and natural gas-fired boilers. The MACT analysis is based on dividing th e 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 th e 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 NO x control system. The NR 445.07 Table A threshold values for emissions from stacks gr eater than 75 feet are 28.2 pounds per hour and 612,587 tons per year. At an ammonia slip ra te 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 μ g/m 3 , 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 mercur y 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 respect ively) 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.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 38 - 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 Apr il 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 ar e 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 thannumber 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 ex ceed number 1 of the Ringlemannchart 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 cl eaned nor a fire started more than 3 times per day.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 39 - 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 TinInorganic, Solid Phase

482 Vanadium 264 Hydrogen chloride Acid 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 ChlorideOrganic

192 Total 2,3,7,8 TCDD (Dioxins) 491 o-Xylene 296 Mercury 20 AmmoniaAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 40 - 

## 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 B 03 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 stea m generating units that commence construction, modification, or reconstruction after June 19, 1984, a nd that have a heat input capacity greater than 100 mmBtu/hr.

4.3.1.1 Nitrogen Oxides (NO x ): 0.20 lb/mmBtu.

The NO x standards in Subpart Db are specified by the type of fuel combusted. In NR 440.205(5)(a), the
NO x emission limit is 0.20 lb/mmBtu for a high heat rel ease boiler firing natural gas. This boiler will have a maximum heat release rate of more than 70,000 Btu/hr-ft 3 , a high heat release rate. Compliance with the NO x emission limit is to be determined on a 30-day rolling average basis and applies at all times, including startup, shutdown, and/or malfuncti on 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 NO x or can use opera ting 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 simila r 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 h our 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 (SO 2 ): No Standard.

The SO 2 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 SO 2 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 le vels consistent with the lowest emitting facilities in similar source categories. These National Emissions Standards fo r Hazardous Air Pollutants (NESHAPs) require the application of the maximum achievable control technology (MACT). The U.S. EPA promulgated NESHAP for Industrial, Commercial, and Instituti onal Boilers and Process Heaters under 40 CFR Part 63, Subpart DDDDD. However, this regulation has been vacated.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 41 - 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 th e 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 a nd B03 do not serve a generator that produces electricity for sale. Therefore, these boilers are not utility units, and these bo ilers 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 fu els 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 F eedwater Pump, Process P151.

The new diesel (compression ignition or CI) engine dr iven 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.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 42 - The applicable standards for new nonroad CI engi nes 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 ma ximum engine power between 300 and 600 horsepower:

NOx + NMHC.......................3.0 g/hp-hr CO ......................................................n/a PM.......................................0.15 g/hp-hrAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 43 - 

# 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 an d 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 (NO x ) Circulating Fluidized Bed Boiler and Selective Non-Catalytic Reduction 0.10 350

PM < 10 microns (PM 10 ) Fabric Filter Baghouse 0.03 105

PM < 2.5 microns (PM 2.5 ) Fabric Filter Baghouse with Felted Filter Media Bags 0.023 88

Sulfur Dioxide (SO 2 ) 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 3.5Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 44 - 

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

The proposed boilers B02 and B03 w ill be natural gas-fired package bo ilers designed to provide up to 125,000 pounds per hour of steam. To deliver this steaming cap acity, each boiler will have a maximum design heat input capacity of 175 million Btu per h our. Based on the control technology review in Appendix B of this application, We Energies is proposing to equip each boiler with ultra-low NO x burners and flue gas recirculation to control emissions of CO, NO x , PM/PM 10 , PM 2.5 , and VOCs.
Table 5-2 summarizes the proposed control techno logies and emission limits which represent the best available control technology (BAC T) for these new package boilers.

TABLE 5-2. Proposed control technologies an d 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 (NO x ) (1) NO x emissions shall be controlled using Ultra Low NO x Burners and Flue Gas Recirculation in combination with good combustion practices as BACT. (2) NO x emissions may not exceed 0.02 lb/ mmBtu, averaged over any 30-day period.

Particulate Matter (PM) and PM 10 (1) PM and PM 10 emissions shall be controlled using natural gas as fuel and good combustion practices as BACT. (2) PM and PM 10 emissions may not exceed 0.0076 lb/mmBtu.

PM 2.5 (1) PM 2.5 emissions shall be controlled using natural gas as fuel and good combustion practices as BACT.. (2) PM 2.5 emissions may not exceed 0.0076 lb/mmBtu when firing natural gas.

Sulfur Dioxide (SO 2 ) (1) SO 2 emissions shall be controlled using natural gas as fuel as BACT. (2) SO 2 emissions may not exceed 0.0006 lb/mmBtu.

Organic Compounds (VOC) (1) VOC emissions shall be contro lled 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.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 45 - 

## 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 dr iven 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 an d 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/PM 10 emissions shall be limited to 0.004 gr/dscf. (3) PM 2.5 emissions shall be limited to 0.002 gr/dscf.

F123 Biomass Fuels Storage and Reclaim (1) Particulate matter (PM), PM 10 , and PM 2.5 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, PM 10 , and PM 2.5 emissions shall be controlled using a bin vent filter as BACT. (2) PM/PM 10 emissions shall be limited to 0.004 gr/dscf. (3) PM 2.5 emissions shall be limited to 0.002 gr/dscf.

F125 Biomass Fuels Delivery Truck Haul Roads

F133 Boiler Ash Haul Roads (1) PM, PM 10 , and PM 2.5 emissions shall be controlled using paved roadways in combination with a wet dust suppression system as BACT.

P141 Cooling Tower (1) PM, PM 10 , and PM 2.5 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.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 46 - 

# 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) Orga nic 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 combinati on with a fabric filter baghouse. These control technologies are similar to those used on the best pe rforming 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, PM 10 , and PM 2.5 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 comb ination with a fabric filter baghouse as MACT.
Mercury emissions may not exceed 2.9 pounds per trillion Btu.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 47 -

TABLE 6-2. Potential hazardous air pollutant emi ssions 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 0.095Inorganic, Solid Phase

Selenium 2.8E-06 800 0.002 0.010 Hydrogen chloride 0.018 800 14.4 63.1 Inorganic 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 0.000Organic

1,2-Dibromoethene 5.5E-05 800 0.044 0.193 Dichlorobiphenyl (PCB) 7.4E-10 800 Heptachlorobiphenyl (PCB) 6.6E-11 800Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 48 -

TABLE 6-2. Potential hazardous air pollutant emi ssions 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 0.063Organic

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 , 5 th Edition, Wood Residue Combustion, Tables 1.6-3 and 1.6-4.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 49 - 

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

The proposed natural gas-fueled boilers are also a potential source of HA P 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 boile r. These emission limits are based on the best performing similar units.

TABLE 6-3. Proposed emission limits representi ng MACT for each natural gas-fueled boiler.

HAP CATEGORY PROPOSED EMISSION LIMIT

Inorganic, solid Proposed PM and PM 10 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 c ontrolled by firing only natural gas.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

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

Emission Factor Heat Input Potential to Emit Pollutant CAS No. lb/10 6 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-0 6 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 , 5 th Edition, Natural Gas Combustion, Tables 1.4-3 and 1.4-4Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 51 - 

# 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 th e proposed source will not cause or contribute to violations of any National Ambient Air Quality Stan dard (NAAQS), or of any applicable Prevention of Significant Deterioration (PSD) increment. These app licable 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/m 3

.

Pollutant Averaging Period NAAQS Modeling Sig. Level PSD Class II Increment
Annual 100 1 25 Nitrogen Oxides (NO 2 ) 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 (PM 10 ) 24-hour 150 5 30

Annual 15 0.3 n/a Particulate Matter (PM 2.5 ) 24-hour 35 1.2 n/a Total Suspended Particulates (TSP) 24-hr 150 n/a n/a

Ozone ** (O 3 ) 8-hour 80 n/a n/a

Annual 80 1 20

24-hour 365 5 91 Sulfur Dioxide (SO 2 ) 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 PM 2.5 are the lowest of EPA’s currently proposed values.
TSP is a State of Wisconsin standard.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 52 - 

## 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 representativ e 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 PM 2.5 and 1-hr NO 2 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 signifi cant 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 imp act 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 leve l (“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 impact s 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 pe rformed for that pollutant and averaging interval. As a result of initial results, cumulativ e impact modeling was performed for NO 2 , SO 2 , PM 10 , and PM 2.5 . 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), NO 2 , and the annual SO 2 impacts are all below the significant impact levels. Therefore, em issions from the Project will have an insignificant impact on air quality for these pollutants and averag ing intervals and meet the NAAQS requirements.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

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

Pollutant Averaging Period Significant Impact Level, μ g/m 3 Highest Modeled Concentration, μ g/m 3

8-hour 500 99 CO 1-hour 2,000 209 NO 2 Annual 1 0.92 Annual 1 0.98 24-hour 5 12.6 SO 2 3-hour 25 55.6 Annual 1 5.6 PM 10 24-hour 5 20.4 Annual 0.3 1.2 PM 2.5 24-hour 1.2 6.4

Footnotes
The SILs listed for PM 2.5 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 NO 2 NAAQS, but has not yet provided 1-hr NO 2 SILs to determine when a cumulative 1-hr NO 2 NAAQS analysis is required. Therefore, even though the annual NO 2 impacts from the Project are insignificant and do not trigger a cumulative annual NO 2 NAAQS analysis, a cumulative 1-hr NO 2 NAAQS analysis was performed. Because the annual NO 2 impact was insignificant, it is reasonable to model only the Project emission sources for the 1-hr NO 2 NAAQS analysis. However, the nearby Domtar and Lignot ech sources were also included in the 1-hr NAAQS analysis, and the maximum 1-hr NO 2 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 NO 2 concentrations in the exact same form as the 1-hr NO 2 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 back ground concentration, and the total was compared to the 1-hr NO 2 NAAQS.
EPA’s guidance for determining compliance with the 24-hr PM 2.5 NAAQS is currently evolving. The results in this analysis are based on the establishe d method (programmed into the AERMOD model) of determining the highest of the eighth-highest (H 8H) 24-hr concentrations for each year in the meteorological data period, and then averaging those across all years to calculate the maximum 98 thAir Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 54 - percentile concentration. The PM 2.5 NAAQS modeling analyses may need to be revised to address new EPA guidance when the air perm it application is submitted.
The results of the cumulative NAAQS analysis ar e summarized in Table 7-3. The NAAQS results demonstrate that the Project will not cause or contri bute to air quality impacts that exceed the NAAQS.

TABLE 7-3. Cumulative NAAQS modeling results.

Pollutant Averaging Interval Cumulative Impact, μg/m 3 Background, μg/m 3 Total, μg/m 3 NAAQS μg/m 3 % of NAAQS

NO 2 1-hour 61 11.9 73.2 188 39%

24-hour 249 11.2 260.2 365 71% SO 2 3-hour 951 11.8 962.8 1300 74%

PM 10 24-hour 41.8 29.4 71.2 150 47%

Annual 2.3 8.7 11.0 15 73% PM 2.5 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 polluta nt 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 interv al. The results of the cumulative Class II PSD increment analysis are summarized in Table 7-4. The SO 2 3-hr and 24-hr and the PM 10 24-hr concentrations are the highest second-high concentrati ons. The PSD increment results demonstrate that the Project will not cause or contribute to air qua lity impacts that exceed the PSD increments.

TABLE 7-4. Cumulative PSD Increment Modeling Results.

Pollutant Averaging Interval Maximum Impact, ug/m 3 PSD Increment ug/m 3 % of PSD Increment

Annual 5.7 17 34% PM 10 24-hour 21.0 30 70%

24-hour 86.1 91 95% SO 2 3-hour 300 512 58%Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 55 - 

# 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 Federa l 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 modificat ion 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 provi de an analysis of the airquality 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 genera l commercial, residential, and industrial growth associated with the proposed project.



## 8.1 Analysis on Soils, Vege tation, 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 be nchmark for evaluating soil and vegetation impacts. In addition, model predicted concentrations were comp ared 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” Vo lume II, August 1993, EPA 600/8-91/049bF. The maximum modeled annual NO 2 concentrations from the project were less than 1 μg/m 3 , which is far below the EPA direct effects screen ing concentration of 94 to 188 μg/m 3 for annual NO 2 averages. The maximum modeled 1-hr NO 2 concentrations were 73 μg/m 3 , which is far below the EPA direct effects screening concentration of 3,760 μg/m 3 for 4-hr NO 2 averages. The maximum modeled ambient SO 2 concentrations from the project were 56 μg/m 3 for the 3-hr average and 0.98 μg/m 3 for the annual average, which are far below the direct effects screening concentrations of 786 μg/m 3 for 3-hr and 18 μg/m 3 for annual averages. Since the ambient impa cts from the Project do not exceed the NAAQS nor EPA screening thresholds for sensitive vegetati on and soils, the dispersion modeling analysis demonstrates that there are no harmful effects to vegetation and soils.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 56 - Near the proposed project site, under certain mete orological 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 exp ected to be reduced. Therefore, this Project will have a positive overall impact on so ils, 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 c onsidered when conducting the air quality analysis. According to the U.S. Bureau of the Census, Cens us of Population and Hous ing, 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 r escue 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 An alysis Requirements.

In the Clean Air Act Amendments of 1977, Congr ess 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 ar eas” include all international parks, national memorial parks larger than 5,000 acres, and national pa rks larger than 6,000 acres that were in existence when the Amendments were passed . Congress also allowed States a nd 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 reque st 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 whic h propose to locate within 100 kilometers of a Class I area.Air Pollution Control Construction Permit Application RTP Environmental Associates, Inc. We Energies – 50 MW Biomass-Fired Cogeneration Facility March, 2010

- 57 - Wisconsin has two Class I PSD are as, the federal Rainbow Lake Ar ea located in the Chequamagon National Forest (located approximately 200 km dist ant 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 screenin g test uses the sum of the annual total emissions (in tons per year) of SO 2 , NO X , PM 10 , and H 2 SO 4 , 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 La nd 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 FC P 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 Construc tion 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 E NVIRONMENTAL A SSOCIATES I NC .®
903 Superior Avenue, Suite 6 Tomah, WI 54660We 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

- 2 - 

# Executive Summary

This document is a Control Technology Review for th e 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 maximu m 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 w ill 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 Energi es is proposing to utilize an advanced circulating fluidized bed boiler designed to fire natural gas a nd biomass fuels, selective non-catalytic reduction, and a fabric filter baghouse. The following table summa rizes the proposed control technologies and emission limits which represent the best available control t echnology (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 (NO x ) Circulating Fluidized Bed Boiler and Selective Non-Catalytic Reduction 0.10 350

Particulate Matter (PM/PM 10 ) Fabric Filter Baghouse 0.03 105

PM < 2.5 microns (PM 2.5 ) Fabric Filter Baghouse with Felted Filter Media Bags 0.023 81

Sulfur Dioxide (SO 2 ) 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 3.5We 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

- 3 - 

# Table of Contents

Chapter 1. Introduction and So urce 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 Re view Metho dology......................................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 Co st Effectiveness. ........................................................................ 16


## Chapter 3. Carbon Monoxide (CO) Contr ol 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........................................................................................................... 2 2 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 Mono xide BACT Determination........................................................ 25


## Chapter 4. Nitrogen Oxides (NO x 

## ) Control Techno logy 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 NO X 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. ....................................................................................... 29We 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

- 4 - 4.3.6 Natural Gas or Coal Reburning......................................................................................... 30
4.3.7 Selective Catalytic Reduction........................................................................................... 30
4.3.8 High Dust SCR. ................................................................................................................ 3 1 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 Ox ide BACT Determination............................................................ 42


## Chapter 5. Particulate Matter and PM 10 

## 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 PM 10 ........................................................................................................... 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 PM 10 BACT Determination........................ 52


## Chapter 6. PM 2.5 

## Control Technolo gy Review...................................................53

6.1 BACT Baseline. ................................................................................................................. ............ 53
6.2 STEP 1. Identify All Potential Control Technologies................................................................... 54

6.2.1 Direct PM 2.5 Emissions. .................................................................................................... 54
6.2.2 PM 2.5 Precursors................................................................................................................ 54
6.3 STEP 2. Identify Technically Feasible Control Technologies...................................................... 54

6.3.1 Fabric Filter Baghouses. ................................................................................................... 54We 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

- 5 - 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 PM 2.5 BACT Determination............................................................................ 60


## Chapter 7. Sulfur Dioxide (SO 2 

## ) Control Techno logy 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) Contr ol 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........................................................................................................... 7 9 8.3.2 Thermal Oxidation............................................................................................................ 79
8.3.3 Good Combustion Practices.............................................................................................. 81
8.4 STEP 3. Rank the Technically Feasible Control Technologies. ................................................... 81We 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

- 6 - 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 emissi ons 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 (NO x ) emission limits representing BACT.................27 TABLE 4-2. Summary of the technical feasibility of retrofit NO x control technologies. ..........................36 TABLE 4-3. Ranking of the technically feasible NO x control technologies for the biomass boiler. ........37

TABLE 4-4. Cost effectiveness of the NO x control technology options for the biomass-fired boiler.......40 TABLE 5-1. Biomass-fired boiler particulate matter/PM 10 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 PM 2.5 control technologies. ..........................................59 TABLE 7-1. Biomass-fired boiler sulfur dioxide (SO 2 ) BACT emission limits. .......................................62 TABLE 7-2. Typical proximate and ultim ate analyses for sever al biomass fuels.....................................69 TABLE 7-3. Wood fuels analyses data and uncontrolled SO 2 emission rates...........................................70 TABLE 7-4. Ranking of the technically feasible SO 2 control technologies..............................................72

TABLE 7-5. Cost effectiveness of the SO 2 control technology options for the biomass-fired boiler. ......74

TABLE 8-1. Biomass-fired boiler VOC emission limits representing BACT. ..........................................79We 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

- 7 - TABLE 9-1. Biomass-fired boiler hydrogen fl uoride (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 showi ng 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 a nd Other Method 28 sample train. ...................................................45 FIGURE 5-2. Depiction of the flue gas flow thro ugh 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 Regene rative 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.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

- 8 - 

# Chapter 1. Introduction and Source Description.

This document is a Control Technology Review for th e 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 unde r 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 bo iler 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 st artup 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 filte r baghouse, and the stack is shown in Figure 1-1.

FIGURE 1-1. Typical CFB boiler power block show ing the furnace, cyclone, baghouse, and stack.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

- 9 - 

## 1.1 Fluidized Bed Boiler Technology.

The atmospheric pressure, fluidized bed bo iler technology was developed to minimize SO 2 and NO x emissions from the combustion of high sulfur fuels su ch as coal and petroleum coke. The fluidized bed boiler combustion process minimizes NO x formation and removes SO 2 in the boiler before post combustion air pollution control systems. Fluidized be d 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: th e 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 th ere 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 boil er technology. CFB boilers have higher fluidizing air velocities ranging from 10 to 20 ft/sec, lack a dis tinct 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 cycl ones located at the outlet of the boiler furnace and are returned to the furnace to maintain the be d 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 partic le 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 a nd completing the combustion process. Combustion air introduced at the bottom of the furnace keeps the mixture of fuel, limest one, sand, char, and ash “fluidized” in a constantly upward flowing stream. Although the fuel and lim estone/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 combusti on 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 biom ass fuels. The primary target source and anchor fuel for this project will be woody biomass. For pur poses 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 fo od crops, refuse derived fu el, treated wood, municipal solid waste, sewerage sludge, and animal waste. Fuel sources may include but are not limited to: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

- 10 -  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 wo od waste, tree services, and construction companies

 clean solid wood waste from discarded wood packaging such as pallets/crating and from constr uction 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 basi s. The biomass fuel consumption rate will be 46 tons per hour (dry basis), or 86 tons per hour on an as-received basis wh en burning the design fuel. The boiler will also be equipped with natural gas st art-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/electri c 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 pape r mill. In normal operating mode, process steam for the mill will be extracted from the turbine generato r, slightly reducing net generation capability. The CFB boiler will be equipped with a single steam drum an d multiple economizer, generating bank, superheater and steam attemperator systems. High pressure, hi gh temperature steam will be fed to a new 50 MW (electric) steam turbine electric generator set. The boi ler 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 dr iven 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 si lo 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 conv eyor system which will transfer the ash to the ash silo. The sand consumption will be depe ndent on the fuel and sand quality.



## 1.4 Potential Air Emissions.

Potential emissions for this biomass fuels-fired, circ ulating fluidized bed boiler are summarized in Table
1-1.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix A: Control Technology Review for the Biomass-Fired Boiler.March, 2010-11 -TABLE 1-1. Potential air pollutant emissions for the proposed biomass-fired boiler.UncontrolledEmissionFactorHeat InputCapacityMaximum TheoreticalEmissionsControlEfficiencyControlledEmissionFactorPotential to EmitPollutantlb/mmBtummBtu/hrlb/hrtons/yr%lb/mmBtulb/hrton/yrCarbon Monoxide CO 0.20 800 160 701 0.20 160.0 700.8Nitrogen Oxides NOx0.15 800 120 526 33.3% 0.10 80.0 350.4Particulate Matter PM/PM1012.0 800 9,600 42,048 99.75% 0.030 24.0 105.1Particulate Matter PM2.512.0 800 9,600 42,048 99.81% 0.023 18.4 80.6Sulfur Dioxide SO20.09 800 72 315 0.0% 0.09 72.0 315.4Organic Compounds OC 0.017 800 13.6 60 0.017 13.6 59.6Lead Pb 0.00003 800 0.02 0.11 0.00003 0.024 0.11Mercury Hg 0.0000029 800 0.0023 0.010 0.0000029 0.0023 0.01Fluorides (as HF) HF 0.001 800 0.8 3.5 0.001 0.80 3.5Sulfuric Acid Mist H2SO40.0018 800 1.4 6.3 0.0018 1.44 6.3Footnotes1. Potential controlled emission rates for CO, NOx, PM/PM10, PM2.5, SO2, VOC, and fluorides are based on the proposedBACT 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, 5thEdition, 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 inAppendix D of the application.4. Sulfuric acid mist emissions are estimated to be 2% of the sulfur dioxide emissions on a mass basis.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

- 12 - 

# Chapter 2. Control Technology Review Methodology.

2.1 Best Available Control Technology Definition.

The Clean Air Act and the Prevention of Significant De terioration (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 w ould 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 cost s, determines is achievable for such source or modification through applicati on 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 applicab le 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 re gulation under the Act whic h 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, a nd economic impacts, and other costs, determines is achievable for such source or modification throug h 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 contamin ant. In no event may application of best available control technology result in emissions of any ai r contaminant which would exceed the emissions allowed by any applicable standard under chs. NR 440 and 445 to 449 and un der 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 partic ular emissions unit would make the imposition of an emissions standard infeasible, a design, equi pment, work practice, operational standard or combination thereof, may be prescrib ed instead to satisfy the requireme nt 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 desi gn, equipment, work practice or operation, and shall provide for compliance by means wh ich 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 signi ficant net emissions increase for that pollutant. Individual BACT determinations are performed on a unit-by-unit, pollutant-by-pollutant basis.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 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 technol ogies until a level of cont rol considered BACT is reached, based on the environmental, energy, and eco nomic 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 pr actical potential for app lication to the emission unit and regulated pollutant under evaluation;

2. Eliminate all technically infeasible control technologies;

3. Rank remaining control technologies by effec tiveness 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 associ ated with a control alternative may be considered if dispersion modeling analyses are performed. The en ergy 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 tota l 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 effectiven ess and ultimately, whether the option is economically reasonable. The economic impacts are reviewed on a cost per ton contro lled 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 statutor y 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 provi de the “maximum degree of emissions reduction.” Second, any decision to require a lesser degree of emi ssions 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 contro ls 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 NO x burners on existing boilers often cannot achieve the same NO x , CO, and VOC emission rates as the use of low NO x burners on a new boiler which has been designed to optimize the low NO x burner design. This can in turn affect the ultimate NO x emission rates which can be achieved by post combustion controls such as selective catalytic reduction.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

- 14 - Retrofitting controls on existing boilers can also have significantly different costs as compared to the use of these same technologies on new units. Retrofitti ng controls on existing boilers can have numerous issues, including site constraints and room for th e new controls, demolition requirements for existing controls, and down time during construction a nd 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 tec hnologies 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 em ployed 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) c ontrols applied to similar source categories and gas streams, and innovative control technologies. Tec hnologies 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 stat es, “Technologies which have not yet been applied to (or permitted for) full scale operations need not be cons idered 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 "demonstr ated" successfully for the type of emission source under review, then it would normally be considered technically feasible. For an undemonstrated technology, “availability” and “applic ability” 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 otherwiseWe 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

- 15 - 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 emissi on 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 simila r 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 incremen tal 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 su ccessfully 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:

Control option annualized cost Average Cost Effectiveness ($ per ton removed) = Baseline emission rate – Control option emissions rate

The average cost effectiveness is based on the overa ll 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.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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### 2.6.2 Incremental Cost Effectiveness.
In addition to determining the average cost effectiv eness of a control option, the U.S. EPA’s New Source Review Manual states that the incremental cost e ffectiveness between dominant control options should also be calculated. The incremental cost effec tiveness compares the costs and emissions performance level of a control option to those of the next most stringent control option:

Control option annualized cost – Next control option annualized cost Incremental Cost ($ per 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 whic h 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, PM 10 , NO x , and SO 2 emissions for biomass-fired boilers, pulverized coal-f ired boilers, circulating fluidized bed boilers, and gas turbines. While cost effec tiveness is determined on a case-by-case basis, the following information on comparative economic costs of BACT options gives some perspective on the co sts that similar sources have typically not been expected to bear as BACT.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix A: Control Technology Review for the Biomass-Fired Boiler.March, 2010-17 -TABLE 2-1. Summary of recent BACT economicanalyses in which the control technology was rejected as not cost effective for BACT.Cost Effectiveness ofRejected Technology,$ per ton controlledFacilityStateBoilerTypePollutantControlTechnologyRejectedAverageIncrementalControlTechnologySelectedAverage CostEffectiveness ofSelectedTechnology,$ per ton1DTE Energy – StonemanPower PlantWI Stoker NOxSCR $9,217 SNCR3We Energies – ConcordGenerating StationWIGasTurbNOxSCR 8,236 -GoodCombustion2 Longleaf Energy Associates GA PC SO2Wet FGD - $8,964 Dry FGD $7244Rocky Mountain PowerHardinMT PC SO2Wet FGD $1,395 $23,855 Dry FGD $9185Intermountain Power 3 UT PCPM /PM10Baghouse w/Teflon Bags$31 $14,000Baghouse w/Ryton Bags$31NOxSCR at 0.04 $2,004 $10,303 SCR at 0.05 $1,5116Basin Electric - Dry ForkStationWY PCSO2Wet FGD $1,595 $15,299 Dry FGD $1,1597Black Hills Power & Light -WYGEN2WY PC NOxSCR at 0.06 $4,156 $7,742 SCR at 0.07 $4,0678Black Hills Power & Light– WYGEN3WY PCPM /PM10Baghouse w/Teflon Bags$134 $14,609Baghouse w/Fiberglass Bags$1309Deseret Power Cooperative- BonanzaUT CFB SO2Wet FGD $418 $10,540 Dry FGD $397Wet FGD - $27,36510Southern Montana ElectricCoop- HighwoodMT CFB SO2Dry FGD - $7,939Ash Reinjection $4,05411Montana-Dakota UtilitiesGascoyne StationND CFB NOxSCR $7,545 $14,339 SNCR $2,92612Red Trail Energy EthanolPlantND CFB SO2Wet FGD $1,041 $10,252 Dry FGD $52713 River Hill Power Company PA CFB SO2Wet FGD - >$5,000 Dry FGD $1,51114 Cargill - Blair Ethanol Plant NE CFB SO2Dry FGD - $5,900 No Post ControlsNOxSNCR - $5,600 SNCR $2,17415ADM – Columbus EthanolPlantNE CFBSO2Ca Inj. - $6,700We 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

- 18 - 1. In a PSD permit for the conversion of two coal-fi red boilers to wood combustion, the Department concluded that the use of regenerative selec tive catalytic reduction with an average NO x control cost of $9,217 per ton was not economically feasible.

2. In a PSD permit for 320 MW of simple cycle comb ustion turbine capacity, the Department concluded that the use of selective cataly tic reduction with an average NO x 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 th at the incremental cost effectiveness of $8,964/ton for wet FGD compared to dry FGD for SO 2 control was not cost effe ctive. The average cost effectiveness of the selected BACT option, dry F GD, was $724/ton. Georgia’s PD is available online
at: http://www.air.dnr.state.ga.us/airpermit/p sd/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, M ontana 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, dr y 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 concl uded 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/PM 10 control, was excessive fo r BACT. The average cost effectiveness of the selected BACT option for PM 10 control (a baghouse with Ryton-type bags) was $31/ton. (Ref: Utah’s Modified Source Plan Revi ew 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 Wyomi ng 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 NO x 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 NO x 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 incrementa l cost effectiveness of $15,299/ton for SO 2 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 e liminated wet FGD option at 0.054 lb/mmBtu was $1,595/ton. Although Wyomi ng 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 SO 2 control was a dry FGD system at 0. 08 lb/mmBtu, with an average cost effectiveness of $1,159/ton. (Ref: Wyoming’s An alysis for the Dry Fork project, NSR-AP-3546, February 5, 2007.)

7. In a PSD permit issued by the State of Wyomi ng 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-NO x burners plus SCR at 0.06 lb/mmBtu to low-NO x burners plus SCR at 0.08 lb/mmBtu, for NOx control was reasonable for BACT. However, for other reasons described by Wy oming, the selected BACT option was low-NO x burnersWe 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

- 19 - 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 Wyomi ng 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 capabl e 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/PM 10 control, was excessive for BACT. The aver age cost effectiveness of the selected BACT option, a baghouse with fiberglass or polyphenyle ne sulfide filter bags, was $130/ton; the average cost effectiveness of the eliminated option, a baghou se 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 B onanza Power Plant, the EPA concluded that an incremental cost of $10,540 per ton of SO 2 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 SO 2 controlled; the average cost eff ectiveness for the dry FGD system selected as BACT was $397/ton of SO 2 controlled. Further, the EPA concluded that the costs for alternative sources of coal in lieu of waste coal of $20,241 per ton of SO 2 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 SO 2 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 SO 2 controlled, for a combination of limestone injection, low-sulfur coal and dry FGD, was excessive for BACT. The selected SO 2 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, Nort h 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 NO x 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 Da kota in 2004 for a CFB boiler at the Red Trail Energy’s Richardton, ethanol plant, North Dakota de termined that an incremental cost effectiveness of $10,252/ton, comparing wet FGD plus limestone in jection to dry FGD plus limestone injection, for SO 2 control was not cost effective. The average cost effectiveness of wet FGD plus limestone injection was $1,041/ton; the average cost effec tiveness of dry FGD plus limestone injection was $527/ton. North Dakota rejected wet FGD and determ ined 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 SO 2 BACT options involving wet FGD systems were economically infeasible at an incremental dollar per ton value greater than $5,000 per ton of SO 2We 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

- 20 - removed. Pennsylvania concluded that the use of dry FGD was economically feasible for the control of SO 2 at an incremental cost of $1,511 per ton of SO 2 removed. Pennsylvania also concluded that an incremental cost effectiveness of $15,975/ton, comp aring the use of the waste coal to the nearest alternative source of coal with lower sulf ur content, was excessive as BACT for SO 2 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 SO 2 control, was excessive for BACT. (Ref: Nebraska permit CP06-0008, Sept. 8, 2006, available at http://www.epa.gov/region07/programs/art d/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 plan t, Nebraska indicated that incremental cost effectiveness of $5,600/ton for NO x control (comparing SNCR at 0.07 lb/mmB tu to SNCR at below 0.07), and an incremental cost effectiveness of $6,700/ton for SO 2 /H 2 SO 4 /HF control (comparing limestone injection to “additional” limestone injection), we re excessive for BACT. Nebraska listed incremental cost-effectiveness of $2,174 for the selected BACT option for NO x control (SNCR at 0.07 lb/mmBtu). (Ref: Nebraska permit CPM02-0006, A ugust 4, 2006, available online at: http://www.epa.gov/region07/programs/art d/air/nsr/archives/2006/finalpermits/ adm_columbus_final_ psd_permit.pdf.)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 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 boile r efficiency and emissions of particulate matter, volatile organic compounds, and organic hazardous ai r pollutants. CO and VOC emissions from the combustion of biomass fuels are normally expected to be somewhat elevat ed as compared to the combustion of natural gas, fuel oil, and coal becau se of the high moisture content and relatively low heating value of most biomass fuels. Because fuel co sts represent the highest single operating cost for this boiler, this biomass-fired boiler is designed to achie ve the highest combustion efficiencies practicable. CO emissions can be reduced by operating the boil er with higher furnace temperatures, higher excess oxygen levels, and longer furnace residence times. Unfortunately, techniques for reducing CO emissions can increase NO x emissions. Achieving low CO and low NO x 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) BA CT emission limits for new biomass-fired boilers contained in the U.S. EPA’s RACT/BACT/LAER Cl earinghouse, and in other permits issued in the United States. Emission limits range from 0.10 to 1.15 p ounds 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 cons tructed 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 Bi omass 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 Technical ly Feasible Control Technologies.

Available control technologies for the control of CO emissions include good combustion practices, oxidation catalysts, and thermal oxidation.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

- 22 - 

### 3.3.1 Oxidation Catalysts.
Oxidation catalysts are used to reduce CO emission s from natural gas or oil-fired combustion turbines, with typical CO reductions of 50 – 90%. However, oxidation cataly sts have limited demonstration on biomass-fired boilers, and we are not aware of an y demonstration or commerc ial operation of oxidation catalysts on a fluidized bed boiler. Boilers have sev eral 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 catalys ts which are susceptible to poisoning from sulfur and calcium bearing compounds. These catalysts ma y 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 m echanisms was presented at the 2008 Advanced Combustion Engineering Research Center conference 1 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 diff erence 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 lo w acid gas constituents such as sulfur dioxide (SO 2 ), 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 pr imary reason that oxidation catalyst and SCR systems located in a high dust envir onment 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 th e 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 + O 2 → 2CO 2

1 Guo, X., et. al. Poisoning/Deactivation Study of V 2 O 5 /TiO 2 SCR Catalysts , ACERC Annual Conference, February 2008.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

- 23 - Typical excess oxygen (O 2 ) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in biomassfired boilers. These low excess O 2 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 compositio n showing the high levels of potassium and sodium in biomass ash relative to coal ash.

(Source: Guo, X., et. al. Poisoning / Deactivation Study of V 2 O 5 /TiO 2 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 reducti ons. 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 ge nerally include the following components: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

- 24 - 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 ar e 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 prim arily 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 NO x emissions. This is a difficult task, since emissions of NO x and emissions of CO are inversely related. That is, measures used to reduce NO x emissions often lead to increases in CO emissions. Therefore, the boiler design to minimize CO emissions is in terrelated with the boiler design to minimize NO x formation.

TABLE 3-1. Carbon monoxide (CO) BACT em ission 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 1.15We 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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## 3.4 STEP 3. Rank the Technica lly 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 cond itions, 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, an d the low air flow rates make it difficult to obtain good air/fuel mixing. For these reasons, CO emissi ons can “spike” when tr ansient conditions occur during boiler startup and shut down.
Based on the analysis of this boiler, we have concl uded 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 th is 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 a nd 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.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 4. Nitrogen Oxides (NO x 

# ) Control Technology Review.

Nitrogen oxides (NO x ) consist of several compounds, including nitrogen oxide (NO), and nitrogen dioxide (NO 2 ). During combustion, NO usually accounts for more than 90% of the total NO x emissions. However, since NO is subsequently converted to NO 2 in the atmosphere, the mass emission rate of NO x are normally reported as NO 2 . NO x is formed during combustion by two major mechanisms; thermal formation, called “Thermal NO x ”, and fuel formation, called “Fuel NO x ”. Thermal NO x results from the high temperature oxidation of nitrogen (N 2 ) and oxygen (O 2 ). Thermal NO x formation is influenced by the flue gas residence time and excess ox ygen, but, as its name implies, thermal NO x formation is primarily influenced by temperature. Thermal NO x formation increases exponentially with temperature, and becomes significant at temperatures above 2800 °F. Fuel NO x results from the oxidation of organic nitrogen compounds in the fuel. Fuel bound nitrogen is more easily converted to NO x during combustion.
F uel NO x may account for up to 80% of the total NO x emissions from solid fuel combustion.



## 4.1 BACT Baseline.

Boiler B01 will be subject to the Standards of Perfo rmance for Industrial-Comme rcial-Institutional Steam Generating Units under 40 CFR Part 60, Subpart Db. Th is 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 NO x 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 soli d waste, or other solid fuel, except coal, may not exceed a NO x 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 ca pacity factor of 10% or less for natural gas.


## 4.2 STEP 1. Identify All Po tential Control Strategies.

There are two major technology categories for controlling NO x emissions from this biomass-fired boiler: combustion controls and post-com bustion controls. Combustion NO x controls include technologies such as advanced fluidized bed boilers to avoid NO x formation. Post combustion NO x controls reduce emissions after NO x has been created. The most common post combustion control techniques involve the injection of ammonia into the flue gas at various lo cations in the boiler or downstream of the boiler to control NO x emissions. When ammonia is injected upstream of a catalyst, the process is called Selective Catalytic Reduction (SCR); when injected in the boile r without a catalyst, the process is called Selective Non-Catalytic Reduction (SNCR). Co mbustion and post combustion contro ls may be used together to achieve the lowest emission rates. The following NO x control technologies were identified: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

- 27 - Combustion Controls • Staged Combustion

• Low NO x 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 lim its 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 (NO x ) 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.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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## 4.3 STEP 2. Identify Technical ly Feasible Control Technologies.

There are two key concepts in determining the feasi bility of potential control technologies: “availability” and “applicability.” A technology is considered “av ailable” if it can be obtained commercially, has completed a commercial demonstration, and has reach ed 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 de termining 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 “demonstrat ed 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 NO x 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 NO x formation. The fluidized bed boiler technology was developed to reduce SO 2 and NO x 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 inhere ntly 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 sa nd 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 limest one 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 NO x formation increases dramatically at temperatures in excess of 2,800°F, the lower fluidized bed boiler temperatures significantly reduces NO x formation.
Based on vendor information, the NO x emission rate from an advanced fluidized bed boiler firing biomass without post combustion controls will typically be 0.15 lb/mmBtu. This “uncontrolled” NO x emission rate is 30 – 50% less than the uncontrolled NO x 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 NO X 

### Burners and Overfire Air.

Low NO x burners (LNB) are designed to control the mixing of air and fuel to reduce the peak temperatures of combustion in coal-fired boilers. Fl uidized bed boilers do not use burners to inject the fuel into the boiler. Therefore LNBs are not technically feasible for fluidized bed boilers.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

- 29 - 

### 4.3.3 Overfire Air (Staged Combustion).
Overfire air (OFA) is a combustion staging processes typically used in conjunction with low NO x burners. A portion of the combustion air is redirected from th e LNB to a higher elevation in the furnace to reduce peak flame temperatures by reducing the concentra tion of oxygen in portions of the furnace. This technique is used in pulverized coal and stoker-fire d boilers to create an oxygen depleted zone where unburned hydrocarbon species act to reduce the NO x that was formed near the coal burner or traveling grates. The overfire air creates an oxida tion zone to complete combustion. NO x formation is minimized by completing combustion in an air-lean environment.
Overfire air systems are similar to the staged combusti on 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 com bustion process often used in conjunction with low NO x burners to reduce peak flame temperatures and create an oxygen depleted zone in the boiler by reducing the concentration of oxygen in porti ons of the furnace. Flue gas reci rculation 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 t echnique is used in pulverized coal and stoker-fired boilers to create an oxygen depleted reducing zone where unburned hydrocarbon species act to reduce the
NO x that was formed near the coal burner. This oxygen depleted zone also reduces the peak flame temperatures which minimizes NO x formation. FGR systems are NO x 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 NO x emissions are already minimized by the fluidized bed design. Therefore, FGR is not an applicable NO x control technology for fluidized bed boilers.



### 4.3.5 Oxygen-Enhanced Combustion.
Oxygen-Enhanced Combustion (OEC) is a combus tion control technology aimed at reducing the formation of thermal NO x . Praxair Technology, Inc. has develope d a method of using oxygen to achieve additional NO x reduction from low NO x burners on pulverized coal-fired boilers. Field tests were conducted at the James River Power Station Unit 3, a wa ll-fired boiler. In pilot- and full-scale testing,
NO x emissions were reduced by as much as 60%, to le vels below 0.15 lb/mmBtu, when a small portion of low-NO x burner combustion air was replaced with locally injected oxygen.

OEC has never been demonstrated or used on a fl uidized 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.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

- 30 - 

### 4.3.6 Natural Gas or Coal Reburning
Natural gas or coal reburning are NO x control techniques used primarily for reducing NO x 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 sec ond flame zone, generating chemically reducing conditions that destroy NO x in the primary combustion zone. In la rge utility pulverized coal-fired boilers, fuel reburning is conducted betw een 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 problem s can occur which can damage the boiler.
At least five utility coal-fired demons trations of reburn are in different levels of operation. In the best applications, reburning may reduce NO x emissions to 0.15 lb/mmBtu. However, to be effective in reducing NO x 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 NO x control system that can substantially reduce NO x emissions from boilers. SCR systems consist of an ammonia (NH 3 ) injection system and a catalytic reactor. Urea can be deco mposed in an external reactor to form ammonia for use in an SCR. The ammonia injection grid is located upstre am of the catalyst. Ammonia reacts with NO x and O 2 in the presence of the catalyst to form molecular nitrogen (N 2 ) and water according to the following general equations:

4NH 3 + 4NO + O 2 → 4N 2 + 6H 2 O 4NH 3 + 2NO 2 + O 2 → 3N 2 + 6H 2 O 2NH 3 + NO + NO 2 → 2N 2 + 3H 2 O

This process is called “selective” because ammonia reacts preferentially with NO x in the flue gas in the presence of a catalyst. A catalyst is used to enhance NO x 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 SO 2 to SO 3 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 particul ate 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 ope rating temperature required by the SCR process.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

- 31 - 

### 4.3.8 High Dust SCR.
High dust SCR systems have been demonstrated on pul verized coal-fired boilers. However, we are not aware of a high dust SCR systems on fluidized bed bo ilers 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 NO x 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 chemica lly attacked by alkali metals such as sodium and potassium, alkaline-earth metals such as calcium, and fouling due to the very high dust loading.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

- 32 - There have been several investigations into the e ffect of biomass firing on SCR performance. One study entitled Biomass Impacts on SCR Catalyst Performance 2 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 alka line-earth metals in the high dust environment act as “effective poisons” of the SCR catalyst. The resu lts of another research effort to assess catalyst deactivation mechanisms was presented at the 2008 Advanced Combustion Engineering Research Center (ACERC) conference 3 and has a similar conclusion; catalyst poisoning is the predominant deactivation mechanism resulting from biomass combustion. The st udy 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 differen ce 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 lo w acid gas constituents such as sulfur dioxide (SO 2 ), biomass flue gas tends to be basic while especially high sulfur coal combustion flue gas tends to be acidic. This exacerbates the catal yst 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 sh owing the high levels of potassium and sodium in biomass ash relative to coal ash.

(Source: Guo, X., et. al. Poisoning / Deactivation Study of V 2 O 5 /TiO 2 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 V 2 O 5 /TiO 2 SCR Catalysts , ACERC, February 2008.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

- 33 - 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 lo w acid gas constituents such as sulfur dioxide (SO 2 ), biomass flue gas tends to be basic while especially high sulfur coal combustion flue gas tends to be acidic. This exacerbates the catal yst deactivation and is the primary reason that SCR systems located in a high dust environment are not app licable to biomass combustors. This problem is worsened by the CFB boiler design which has an extr emely high dust loading. Erosion, plugging, and blinding are major potential problems in fluidized bed bo iler applications due to the very high particulate loading in the boiler. Based on this analysis , high dust SCR is not a technically feasible NO x 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, amm onia 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 PM 10 and PM 2.5 emissions since there are no downstream collection devices to capture th ese 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 reh eat of the flue gas, especially if any type of flue gas desulfurization (FGD) is used. However, low te mperature catalysts which require less (or possibly no) reheat are extremely sensitive to sulfite (SO 3 ) 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 cat alyst, 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 NO x reductions in order to certify the facility as a renewable energy generator by the State of Connecticut. Connecticut is focused on low NO x energy provided by renewable energy sources combusting qua lified fuels. Once certified, Boralex was allowed the opportunity to compete for the sale of renewable ener gy 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 elig ible for Connecticut’s RPS Program, the NO x 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 Environm ental Protection concluded that the best available control technology (BACT) for NO x emissions from this boiler is the use of RSCR, and an emission limit of 0.24 lb/mmBtu. Note that the NO x 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 f easible control option for this biomass-fired boiler.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

- 34 - 

### 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(NH 2 ) 2 ] or ammonia [NH 3 ], reacts with NO x , forming elemental nitrogen [N 2 ] and water without the need for a catalyst. The overall NO x 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 NO x ratio is normally much higher for SNCR systems. For SNCR, ammonia is typically injected at an NH 3 to NO x molar ratio of 1.2 – 2.0 moles of NH 3 per mole of NO x , compared with 1.0 - 1.1 moles of NH 3 per mole of NO X for SCR.
The critical parameters for successful and effective control of NO x emissions using SNCR is a proper temperature window for SNCR performance, and adequate residence time at th at temperature for the reaction to occur. If the temperature is too high, the ammonia will undergo chemical decomposition, and
NO x emission reductions will not be achieved. If the te mperature is too low, the ammonia will not react with NO x without a catalyst, and again, NO x 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 NO x with the reagent without excessive amm onia slip, and without excessive ammonia decomposition before the NO x 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 mu ch reagent as SCR systems to achieve similar NO x reductions, and SNCR cannot achieve NO x reduction efficiencies as high as SCR systems.
As noted by the U.S. EPA, certain boiler types ar e 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 NO x are good candidates 5 . SNCR has been widely used in fluidized bed boilers where the hi gh 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 Re liant Energy Seward Plant, the JEA Northside Units 1 and 2, the Kentucky Mountain Power project, and the East Kentucky Spurlock plant.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

- 35 - 

### 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 opera tion 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 cogenerati on 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 cat alytic oxidation and absorption technology. In operation, NO and CO are first oxidized to NO 2 and CO 2 . Next, NO 2 is adsorbed onto an adsorption media. When the media is saturated, NO 2 is desorbed and treated by the proprietary catalyst. Because the operation of SCONOx to oxidize CO to CO 2 is identical to the simple use of an oxidation catalyst, there is effectively no difference between SCONOx and an oxida tion catalyst in terms of CO and VOC control. Therefore, SCONOx and an oxidation catalyst are eff ectively 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 f easible for solid fuel and biomass-fired boilers.



### 4.3.12 Emerging Control Technologies.
Emerging technologies to reduce NO x 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 NO x 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 ad vanced process is the ECO system. ECOTM is an emerging post-combustion multi-pollutant control technology including NO X control and has demonstrated performance, reliability and economics th rough 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 NO x control technologies include NOxStar and Cascade. NOxStar is a hydrocarbo n enhanced SNCR system that injects hydrocarbons downstream of an SNCR system to produce radicals that will further reduce NO x 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 NO x emissions to levels that potentially could be comparable with full size SCR syst ems. 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 r ecord of commercial operation, these emerging control technologies are not technically feasible for NO x control for this boiler.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

- 36 - 

### 4.3.13 Summary of the Tec hnically Feasible Controls.
Table 4-2 is a summary of the technical feasibility of the NO x controls for the biomass-fired boiler.

TABLE 4-2. Summary of the technical feasibility of retrofit NO x control technologies.

Technology Technical Feasibility

Low NO x 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.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

- 37 - 

## 4.4 STEP 3. Rank the Technica lly Feasible Control Technologies.

4.4.1 Circulating Fluidized Bed Boiler.
A circulating fluidized bed boiler has inherently lo w NOx emissions. Based on vendor information, the
NO x emission rate from this advanced fluidized bed boiler firing biomass without post combustion controls will be 0.15 lb/mmBtu. This “uncontrolled” NO x emission rate is 30 – 50% less than the uncontrolled NO x emission rate for stoker boilers firing biomass fuels.



### 4.4.2 Selective Catalytic Reduction (SCR).
Tailgas SCR systems can be designed for control effici encies 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 NO x emission rate of 0.06 lb/mmBtu, equal to an 60% reduction from the uncontrolled boiler emission rate.



### 4.4.3 Selective Non-Cata lytic 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 remova l efficiencies of 35% and 50%. It is important to note that the SNCR effectiveness can be redu ced 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 mini mum SNCR operating temperature of approximately 1,600 o F. For this CFB boiler, SNCR is expected to reduce NO x emissions by 33% to 0.10 lb/mmBtu.
Table 4-3 is a summary of the ranking of the technically feasible NO x control technologies for the proposed CSHP biomass-fired boilers.

TABLE 4-3. Ranking of the technically feasible NO x 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 0.15We 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

- 38 - 

## 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 NO x emission rate of 0.06 lb/mmBtu for this biomass-fired boiler. Based on a capacity factor of 88% and the resulti ng uncontrolled emissions, a SCR system could reduce
NO x emissions from this boiler by 278 tons pe r year, (from 463 to 185 tons per year).
Although the use of a tailgas SCR system can achieve very low NO x emission rates, SCR would have other adverse environmental and ener gy 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 PM 2.5 . Because the only feasible SCR control option is a tailgas system, there is no possibility of contro lling 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 = C h KF (20.9) 20.9- %O 2 where, E = NH 3 Emission rate, lb/mmBtu
C

h = NH 3 concentration = 10 ppmdv
F = dscf/mmBtu = 9,780 dscf/mmBtu %O 2 = Oxygen concentration = 5.0%
K

= 4.61 x 10 -8 lb/dscf-ppm NH 3

Energy impacts from the application of the technology would include an electricity penalty from the increase in pressure drop across the system. In add ition, 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 CO 2 emissions of 2,200 tons per year.



### Economic Impacts.
The costs for SCR on this boiler will include capital co sts 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 syst em will have substantial operating costs, including reagent (ammonia) costs, natural gas reheating cost s, labor, auxiliary power requirements, catalystWe 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

- 39 - replacement costs, maintenance costs, and administrativ e 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 th e estimate of control costs. A detailed cost analysis is included in Attachment 1. The SCR syst em is expected to have a total capital cost of $14.2 million, an annual O&M cost of $1.3 mi llion, and a total annual cost of $2.9 million. From Table 4-4, the tailgas SCR system would reduce NO x 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 NO x 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 NO x 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 NO x controlled.



### Conclusions.
The use of a tail gas SCR can achieve NO x emission rates of 0.06 lb/mmBtu for this biomass-fired boiler. Based on an actual annual capacity factor of 88%, a nd the resulting uncontrolled emissions from the CFB boiler, the SCR system could reduce NO x 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. Th is is enough natural gas to heat approximately 300 homes each year. In addition, the combustion of th is natural gas would result in non-renewable CO 2 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 NO x 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 e nvironmental impacts, SCR does not represent BACT for this biomass fuels-fired CFB boiler.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

- 40 - TABLE 4-4. Cost effectiveness of the NO x 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 – 6 th 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 CRFWe 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

- 41 - 

### 4.5.2 Rank No. 2: Select ive Non-Catalytic Reduction.

Environmental and Energy Impacts.
The use of a circulating fluidized bed boiler with inherently low NO x emissions combined with SNCR can achieve NO x emission rates of 0.10 lb/mmBtu for the bioma ss-fired boiler. Based on a capacity factor of 88% and the resulting uncontrolled emissions, the use of SNCR could reduce NO x emissions by 154 tons per year (from 463 to 308 tons per year).
As with SCR, the use of SNCR may have environm ental impacts related to the on-site handling and storage of ammonia. In addition, the use of amm onia 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 NO x reductions than does an SCR system, the point of injection for the SNCR system is before the fabric f ilter 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 to tal annual cost of $1,014, 000. The annual capital cost is based only on the ammonia reagent co sts. From Table 4-4, SNCR would reduce NO x emissions by 154 tons per year at an 88% annual capacity factor. This results in an aver age cost effectiveness for SNCR of $6,580 per ton of NO x controlled.



### Conclusions.
The use of a circulating fluidized bed boiler with inherently low NO x emissions combined with SNCR can achieve NO x emission rates of 0.10 lb/mmBtu for the bioma ss-fired boiler. Based on a capacity factor of 88% and the resulting uncontrolled emissions, the use of SNCR could reduce NO x 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. Th e 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 NO x controlled. Although this is a high cost, We En ergies considers this cost to be achievable.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

- 42 - 

## 4.6 STEP 5. Proposed Nitrog en Oxide BACT Determination.

Based on this analysis, We Energies has concluded that the use of a circulating fluidized bed boiler with inherently low NO x emissions combined with selective non-cat alytic reduction (SNCR) is the best available control technology (BACT) for NO x emissions from the biomass fuels-fired boiler. Based on this analysis, We Energies proposes the follo wing limits as BACT for the control of NO x emissions from the biomass fuels-fired CFB boiler.

(1) Nitrogen oxide (NO x ) 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 (NO x ) 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 (NO x ) 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 (NO x ) emissions from the biomass-fired boiler B01 shall be continuously monitored a nd 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.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

- 43 - 

# Chapter 5. Particulate Matter and PM 10 

# Control Technology Review.

Particulate matter (PM) emissions from solid fuel-fi red 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 ma terials. 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 ma tter which exists as a solid or liquid at the lower temperature of 32 o F are measured using U.S. EPA’s RM 202, a nd 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 Sta ndards of Performance for New Stationary Sources, 40 CFR § 60.50Da(b)(2), and NR 440.20(8)(b)2. requir e the use of only Reference Method 5 for facilities without wet FGD systems or a variation of this met hod, Method 5B, for facilities with wet FGD systems. This is the method required by many states which ha ve 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. Si nce the federal NSPS standards and many states require only Reference Method 5 (or 5B) for demons trating compliance, the direct comparison of emission limits required in other stat es is not always appropriate. In other words, an emission limit requiring both Reference Methods 5 and 202 would be more stringent th an 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 trai n and results in a positive bias indicating moreWe 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

- 44 - condensable PM than is actually emitted. In devel oping Reference Method 202, the U.S. EPA recognized the potential for artifact formation due to the oxidation of SO 2 to SO 3 in the sampling equipment 7 . To address this issue, Method 202 includes a post-test nitrogen (N 2 ) purge for sources emitting SO 2 . This procedure is intended to remove dissolved SO 2 from the sample before it can react to form sulfuric acid. Unfortunately, as the referenced pape rs indicate, this proc edure is not effective in removing dissolved SO 2 .

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 evaporati ng the collected material, mostly wa ter, to a constant end weight. However, the procedure recognizes that a constant end weight may not be possib le if sulfuric acid is present. Since sulfuric acid is hydroscopic, th e sample will begin to increase in we ight as soon as the sample is taken from a dryer into a room with ambient moisture. As a result, Method 202 include s 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 (Fos sil Energy Research Corporation), Evaluation of False Positive Interference’s Associated with the Use of EPA Method 202 , Presented at the 89 th Annual Meeting of the Air & Waste Management Association, June 23-29, 1996.
B. Nott, Electric Power Research Institute, Measuremen t of Condensable Particulate Matter, TR-111327, Final Report , September, 1998. L. A. Corio (Versar, Inc) and J. Sherwell (Maryl and 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.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

- 45 - the sample with ammonium hydroxide to convert the sulfuric acid to am monium 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 (NH 4 + ) that must be subtracted to account for the added substance. Unfortunately, Method 202 does not include any other met hods 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 Emi ssions From Stationary Sources. The modified sample train is shown in Figure 4-2. This sample tr ain avoids the intimate contact of water with flue gas in the impingers, reducing formation of artif act 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 PM 10 Particulate matter emissions may also be defined by pa rticle size. Often particulate matter emissions are referred to as PM which includes all sizes of particul ate matter emissions. Particulate matter less than 10 microns in diameter is called PM 10 and include condensable PM by de finition. To address this, some permits have established a PM limit that does not incl ude condensable material (i.e., filterable PM only), and a PM 10 limit, significantly larger than the PM limit, that includes both the filterable and condensable matter. Many permit emission limits have begun to sp ecify 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.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

- 46 - 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 PM 10 . 

## 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.

PM 10 Emissions will refer to both front half or filterable PM emissions measured in accordance with U.S. EPA Refere nce Method 5 or 5B, in combination with back half or condensable emissi ons 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 comme nce construction, modification, or reconstruction after June 19, 1984, and that has a heat input capac ity 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 combus ts 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 emissi on standards and opacity limits under § 60.43b apply at all times except during periods of startup, shutdow n, or malfunction. Compliance with the PM emission standards under § 60.43b are determined through perf ormance testing using Reference Method 5, 5B, or 17. Note that this standard does not include condensable PM emissions.


## 5.6 STEP 1. Identify Poten tial 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/B ACT/LAER Clearinghouse. The technologies selected include fabric filter baghouses and electrostatic pr ecipitators. 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.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

- 47 - TABLE 5-1. Biomass-fired boiler particulate matter/PM 10 BACT emission limits.

Limit, lb/mmBtu Facility State Permit Date Capacity, mmBtu/hr Primary Fuel Control System PM PM 10 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 Test 2
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 PM 10 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.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

- 48 - 

## 5.7 STEP 2. Identify Technical ly Feasible Control Technologies.

As noted above, data from the U.S. EPA’s RBLC indi cate that the technologies sel ected as BACT include primarily fabric filter baghouses and electrostatic pr ecipitators. 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 mechan ism to clean accumulated PM from the bags, and a hopper to collect accumulated ash. Baghouses are compar tmentalized to facilitate cleaning and to provide for maintenance and repair. When the pressure drop across a compartment incr eases 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 “f ilter 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 abso rption of pollutants, including sulfur dioxide (SO 2 ), 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.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

- 49 - FFB have several methods for cleaning, including re verse 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 co sts than a RGFFB. However, because the pulse jet cleaning method is more aggressive than in the RG FFB, 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 load ing 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 r esulting 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 positiv ely charged collection plates. The discharge electrodes impart a negative charge to particles in th e 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 g as stream during rapping. Th is 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 resistivity 8 conditions. Most modern ESPs are cold-side ESPs.

8 Gas composition and temperature and particle comp osition all influence resistivity, which is a measure of the ability of a particle to retain an electrost atic 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.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

- 50 - 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 sectionaliza tion of the ESP. The smaller the collection area of the ESP, the narrower the acceptable resistivity range b ecomes. To optimize particulate resistivity and maximize collection efficiency, many ESPs utilize a sulfur trioxide (SO 3 ) injection system to condition the ash and reduce particulate resistivity. In additi on, modern ESP controls allo w the ESP operation to be optimized to maximize PM control through overa ll ESP performance management, power optimization, and programmed cleaning cycles. Finally, good secti onalization 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 g as, 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 flus hed with water to remove collected materials.
Although wet ESPs can be effective for removing su lfuric 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 e ffective operation. Wet ESPs experience current suppression when particulate concentrations in the el ectrode wash water are too high which would reduce or eliminates the PM control effec tiveness 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 conde nsation, 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 feasibl e BACT alternative, the performance of mechanical collectors is inferior to FFBs and ESPs.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

- 51 - 

## 5.8 STEP 3. Rank the Technically Feasible Technologies.

All of the identified PM control technologies, incl uding fabric filter baghou ses, dry ESPs, wet ESPs, wet scrubbers, and mechanical collectors are technically f easible 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, si nce 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 PM 10

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 pa rticulate 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.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

- 52 - 

## 5.10 STEP 5. Proposed Filterable Particulate Matter and PM 10 

## BACT Determination.

Based on this analysis, We Energies has concluded th at the use of a fabric filter baghouse is the best available control technology (BAC T) for particulate matter and PM 10 emissions from the biomass fuelsfired CFB boiler. Based on this analysis, We En ergies proposes the following limits as BACT for the control of particulate matter and PM 10 emissions from the biomass-fired, circulating fluidized bed boiler.

(1) Particulate matter and PM 10 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 PM 10 emissions may not exceed 0.03 pounds per million Btu of heat input, excluding pe riods 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.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

- 53 - 

# Chapter 6. PM 2.5 

# Control Technology Review.

Particulate matter emissions that are less than 2.5 mi crometers in diameter are known as "fine" particles, and are referred to as PM 2.5 . Various pollutants may contribute to ambient PM 2.5 concentrations. Natural gas and biomass fuel combustion results in direct emissions of PM 2.5 , as well as PM 2.5 “precursors”.
PM 2.5 precursors may also result in the formation of PM 2.5 in the atmosphere. The U.S. EPA has identified SO 2 , NO x , organic compounds (VOCs), and ammonia (NH 3 ) as PM 2.5 precursors. These gasphase precursors undergo chemical reactions in the atmosphere to form secondary PM 2.5 . Direct emissions of PM 2.5 from combustion include solid or filterable PM 2.5 , and condensable or back half PM 2.5 . Under the recently promulgated rules to revise the New Source Review (NSR) program in 40 CFR Part 52 to include PM 2.5 , the EPA identified the following PM 2.5 pollutants, and their significant levels:

1. 10 ton per year of direct PM 2.5 emissions 2. 40 ton per year of SO 2 emissions 3. 40 ton per year of NO x emissions unless demonstrated not to be a PM 2.5 precursor.

Based on the final rules, VOC and ammonia may not be considered to be PM 2.5 precursors unless the State demonstrates that these emissions ar e a significant contributor to the area PM 2.5 concentrations. In addition, during the PM 2.5 SIP development period, the EPA has indicated that NO x emissions will not be regulated as a PM 2.5 precursor to give States the opportunity to determine whether NO x emissions are a significant contributor to the ambient PM 2.5 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
PM 2.5 emissions from this biomass-fired boiler.

Direct PM 2.5 emissions from the combustion of biomass fuels include filterable PM 2.5 , and condensable
PM 2.5 . 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 boile rs controlled by fabric filter baghouses may be PM 2.5 . 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 PM 2.5 . Based on the proposed PM (filterable) and PM 10 (filterable plus condensable) BACT emission limits of 0.015 and 0.03 lb/mmBtu, respectively, the PM 2.5 emission rate would be:

E PM2.5 = 1⁄2 x (0.015) + (0.03 – 0.015) = 0.0225 lb/mmBtuWe 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

- 54 - 

## 6.2 STEP 1. Identify All Po tential Control Technologies.

6.2.1 Direct PM 2.5 

### Emissions.

For PM and PM 10 , 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 PM 2.5 emissions from this biomass-fired boiler, one-third of the direct PM 2.5 emissions, or 0.0075 lb/mmBtu, is expected to be filterable PM 2.5 ; the remaining portion of direct PM 2.5 emissions, or 0.015 lb/mmBtu, is expected to be condensable PM 2.5 .



### 6.2.2 PM 2.5 

### Precursors.

As noted above, the U.S. EPA has identified SO 2 , NO x , VOCs, and ammonia (NH 3 ) as PM 2.5 precursors. Based on the final rules, volatile organic compounds (VOC) and ammonia (NH 3 ) may not be considered to be precursors to PM 2.5 unless the State demonstrates that these emissions are a significant contributor to the area PM 2.5 concentrations. This control technology re view includes a complete control technology review for SO 2 , NO x , and VOC emissions. Therefore, further analysis of these pollutants as PM 2.5 precursors is unnecessary, since BACT contro ls will be applied to these pollutants.


## 6.3 STEP 2. Identify Technical ly Feasible Control Technologies.

As noted above, data from the U.S. EPA’s RBLC indi cate that the technologies sel ected as BACT include primarily fabric filter baghouses and electrostatic pr ecipitators. 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/PM 10 control technology re view. 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 emissi ons versus the particle size for several different PM control systems for coal combustion 9 . Figure 6-1 shows that fabric filter baghouses are very effective in reducing PM emissions, especially fine PM or PM 2.5 . 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 th an 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 (SO 2 ), sulfuric acid mist, mercury and hazardous air pollutants including hydrogen chloride (HCl) and hydrogen fluoride (HF). Since pollutants such as su lfuric acid mist, HCl, and HF directly contribute to condensable PM, fabric filter baghouses are also ve ry effective at reducing the condensable portion of
PM 2.5 emissions by controlling these PM 2.5 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.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

- 55 - 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, umCummulative Emission Factor, lb/ton Multiple Cyclones

Electrostatic Precipitator

Fabric Filter Baghouse



### Filter Media for Fabric Filter Baghouses and PM 2.5 

### 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 wove n 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 PM 2.5 control. Advanced filter media provide enhanced PM 2.5 emissions control and may be applicable to this biomass-fired boiler. The U.S. EPA implemented the Environmental Technology Ve rification (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 report 10 , “New fabrics have been developed that offer the combination of highly effective particulate removal and low operational pressure drop. Improvi ng performance of the fabrics can be observed in verification test data trends.” Completed verifica tions 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 Medi a 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, Pres ented at the Air & Waste Management Association Annual Conference, June, 2008, available at: http://epa.gov/etv/pubs/600etv08023.pdf

.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

- 56 - filter media with direct PM 2.5 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 b est state-of-the-art baghouse will increase the outlet grain loading, even when using advanced filter media.
Baghouse filtration product enhancements include fe lted 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 gene rally 2 to 3 times thicker than woven filters. This thicker overall filter improves fine pa rticle collection, since each individual randomly oriented fiber acts as a target for particle capture by impaction and in terception. Small particles are collected on the outer surface of the filter, rather than depending on the filter ca ke to achieve fine particle control. Figure 6-2 is a depiction of the fabric filter media filtration pro cess 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 contro l. The U.S. EPA’s ETV program tested outlet PM 2.5 levels as low as 0.0004 gr/dscf (0.00055 lb/mmBtu).

FIGURE 6-2. Depiction of the fabric filter medi a 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

.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

- 57 - 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 PM 2.5 control. However, this co ating 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 effectiv eness of the fabric filter baghouse for PM 2.5 precursors and condensable PM 2.5 species by limiting the contact between thes e precursors and solids in the filter cake which would otherwise remove these precursors.

Membrane bags have a polytetrafluoroethylene (PTFE) coatin g 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 PM 2.5 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 PM 2.5 precursors and condensable PM 2.5 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 contro l. The U.S. EPA’s ETV program tested outlet PM 2.5 levels as low as 0.0004 gr/dscf (0.00055 lb/mmBtu).

Electrostatic fabric filter baghouses have been developed through a pa rtnership of the U.S. EPA and Southern Research Institute. The technology is license d 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 th e 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 volta ge 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 hi gher than those achieved by either the best fabric filters or precipitators currently on the mark et, 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 conducte d pilot testing of a slip stream at a major power plant in the Southern United Stat es. The pilot plant was configured to allow testing with or without discharge electrode energization. With the electrost atic stimulation turned on, collection efficiency increased from 99.99% to 99.999%, a full order of magn itude 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

.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

- 58 - 

### 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/PM 10 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 PM 2.5 emissions, and also for PM 2.5 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 wh en firing high sulfur coals, wet ESPs cannot be used as the primary PM control system for biomass-fi red 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 elimin ates 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
PM 2.5 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 s lipstream 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 PM 2.5 and
SO 3 mist removal as a potential control technology to reduce visible emissions. The slipstream results indicate reductions in PM 2.5 emissions from 62% to 96%. These results also showed similar high SO 3 mist removal, which may account for mush of the PM 2.5 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 conde nsation, 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.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

- 59 - 

## 6.4 STEP 3. Rank the Technically Feasible Technologies.

Fabric filter baghouses, dry ESPs, wet ESPs, wet scrubbe rs, and mechanical collectors are technically feasible technologies. While wet ESPs have shown promise at reducing PM 2.5 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, si nce 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 2.5 .

TABLE 6-1. Ranking of the technically feasible PM 2.5 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 PM 2.5 precursors. Intrinsically coated bags and high efficiency microfiber bags may improve filterable PM 2.5 control without significantly reducing filter cake accumulation and the subsequent control of PM 2.5 precursors such as SO 2 and sulfuric acid mist. Membrane coated bags are expected to achieve very high filterable PM 2.5 control but may reduce filter cake accumulation which may adversely impact control of PM 2.5 precursors such as SO 2 and condensable PM 2.5 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 PM 2.5 emission rates. However, the conventional bags have good filter cake accumulation and good control of PM 2.5 precursors and condensable PM 2.5 .

3 Dry ESP 0.03 - 0.05 Inferior control, with lower filterable and lower condensable PM 2.5 control.

4 Venturi Scrubber 0.05 – 0.15 Inferior control.

5 Mechanical Collectors 0.10 – 0.30 Inferior control.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

- 60 - 

## 6.5 STEP 4. Evaluate the Most Effective Controls.

6.5.1 Rank No. 1: Fabric Filter Baghou se with Felted or Advanced Filter Media.
Based on the ranking summarized in Table 6-1, a fa bric filter baghouse with felted filter media or advanced filter media bags is expected to have the greatest potential to reduce both filterable and condensable PM 2.5 emissions from the biomass-fired boiler. Note that there is a lack of data available on
PM 2.5 emissions from biomass combustion, and th ere is no available information on the PM 2.5 emission rates for different fabric filter media on a CFB boiler firing biomass fuels. With these statements made, the highest level of PM 2.5 emission control from this biomass-fired bo iler 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 PM 2.5 

## BACT Determination.

Based on this analysis, We Energies has concluded th at the use of a fabric filter baghouse with felted filter media bags is the highest ranked control technology for the control of PM 2.5 emissions and represents the best available control technology (BACT) for PM 2.5 emissions from the biomass fuels-fired CFB boiler. Based on this analysis, We Energies pr oposes the following limits as BACT for the control of PM 2.5 emissions from this biomass-fired boiler.

(1) PM 2.5 emissions from the biomass-fired Boiler B08 shall be controlled using a fabric filter baghouse with fe lted filter media bags as the best available control technology.
(2) PM 2.5 emissions may not exceed 0.023 pounds per million Btu of heat input, excluding periods of startup and shut down.
(3) Compliance with this PM 2.5 emission limit shall be based upon the measurement of PM 2.5 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.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

- 61 - 

# Chapter 7. Sulfur Dioxide (SO 2 

# ) Control Technology Review.

Sulfur dioxide (SO 2 ) 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 SO 2 . A small portion of the sulfur is further oxidized to sulfur trioxide (SO 3 ). When the flue gas temperature drops below the dew point temperature, sulfur trioxide is s pontaneously converted to sulfuric acid (H 2 SO 4 ). Therefore, control technologies which control SO 2 emissions also reduce sulfuric acid mist emissions to varying degrees. A portion of the SO 2 and SO 3 will react with alkaline products in the ash such as calcium oxide (CaO), sodium oxide (Na 2 O), and potassium oxide (K 2 O) and water to form calcium sulfate or gypsum (CaSO 4 • 2H 2 O), sodium sulfate (Na 2 SO 4 ), and potassium sulfate (K 2 SO 4 ). 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 whic h produce highly alkaline ash. Therefore, ash in the boiler and in the filter cake of th e fabric filter baghouse will reduce SO 2 emissions.



## 7.1 BACT Baseline.

The biomass fuel-fired CFB boiler will be subject to the Standards of Performance for IndustrialCommercial-Institutional Steam Gene rating Units under 40 CFR Part 60, Subpart Db. This subpart applies to steam generating units that commence constr uction, 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 SO 2 emission rate of 0.20 lb/mmBtu, or 2) 8% of the potential SO 2 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 SO 2 emission rate of less than 0.32 lb/mmBtu are exempt from the SO 2 emissions limit in 40 CFR § 60.42b(k)(1).
Based on these NSPS limits, the baseline SO 2 emission rate is 0.20 lb/mmBtu.


## 7.2 STEP 1. Identify Poten tial Control Technologies.

Potential sulfur dioxide (SO 2 ) control technologies include pre-combustion controls such as low sulfur fuels, and post combustion controls, such as flue g as desulfurization (FGD). The following references were used to identify potential SO 2 control technologies: “Controlling SO 2 Emissions: A Review of Technologies (EPA-600/R-00-093, October 2000), th e U.S. EPA’s RACT/BACT /LAER Clearinghouse (RLBC), the U.S. EPA’s National Coal-Fired Utilit y Projects Spreadsheet Updated July 2007, and numerous air permits issued by states and the U.S. EPA.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

- 62 - Table 7-1 is a summary of SO 2 BACT emission limits for both new and modified biomass-fired boilers contained in the U.S. EPA’s RACT/BACT/LAER Cl earinghouse. The technologies selected include low sulfur fuels, duct sorbent injection, limestone in jection 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. No te that several facilities in Table 7-1 agreed to “synthetic minor” limits limiting emissions below th e PSD significant threshold of 40 tons per year.

TABLE 7-1. Biomass-fired boiler sulfur dioxide (SO 2 ) 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 Sta tion, sorbent injection into the fluidized bed boiler is required for coal combustion.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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## 7.3 STEP 2. Identify Technical ly Feasible Control Technologies.

Flue Gas Desulfurization (FGD) technologies are primar ily 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, sa turated or wet flue gas conditions, and a wet sludge reaction product which is de watered 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 c onditions 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 te mperatures about 20 to 50 °F above the saturation point, or about 150 o F to 180 o F. 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 SO 2 emissions from utility scale coal-fired boilers. In a wet FGD system, the flue gas is e xposed to an alkaline reagent which reacts with SO 2 to form a solid. There are several alka line reagents used in wet FGD syst ems, 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 sy stem absorber tower is shown in Figure 7-1.
Regardless of the wet FGD design, the flue gas leaving the absorber will be saturat ed with water, and the stack will have a visible condensed moisture plum e at all times. The conditions downstream of the absorber are highly corrosive, requiring highly corros ion-resistant materials for the downstream ductwork and stack. This would require that the stack be speci ally designed with a fiberglass liner. Equipment is also needed to manage the condensation that occu rs on the downstream ductwork and in the stack. The wet FGD reaction products also require dewatering, us ually by a combination of hydroclones and vacuum filters. Large areas are needed to manage the dewa tering 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 larg ely 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 SO 2 removal. These first wet FGD systems utilized spray tower absorbers, often without a perforated plate tray, as the me thod for contacting the flue gas with the reagent.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

- 64 - FIGURE 7-1. Typical modern wet flue gas desulfurization system absorber tower.

FGD systems installed in the 1990’s were 2 nd and 3 rd generation systems which generally achieved greater than 90% SO 2 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 SO 2 removal efficiencies of the 2 nd and 3 rd generation systems were improved primarily by improving gas to liquid c ontact. These improvements include absorption trays with perforated plates and multiple levels of interspatial reagent spray nozzles.
FGD system suppliers have introduced several new desi gns 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 impr ove the gas-to-liquid contact by forcing the flue gas to bubble through the liquid reagent using a gas spar ger design rather than spraying the alkaline slurryWe 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

- 65 - into the gas stream. Mitsubishi developed the Do uble 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 SO 2 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 (CaSO 3 ). The LSFO process further oxidizes calcium sulfite to calcium sulfate dihydrate (gypsum, or
CaSO 4 ·2H 2 O). The gypsum content of the scrubber sludge is typically 95% on a dry basis, making the sludge easier to dewater. Gypsum is a naturally occu rring mineral that is used as a raw material in the manufacture of plaster, wallboard, Portland cement, ag ricultural 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 consis ting of limestone (calcium carbonate), calcium sulfite, and calcium sulfate is contacted with the flue gas. Through a series of reactions, SO 2 in the flue gas reacts with calcium carbonate to form CaSO 3 . The flue gas exits the abso rption 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 CaSO 4 ·2H 2 O. 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 transpor t offsite. The overall FGD reaction is :

CaCO 3 (s) + SO 2 (g) + 1⁄2O 2 (g) + 2H 2 O → CaSO 4 ·2H 2 O(s) + CO 2 (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 SO 2 control system is also true for the LSFO – as the boiler outlet SO 2 concentration decreases, the ability to achieve high control efficiencies also decreases.



### Technical Feasibility
WFGD is a well demonstrated technology for the control of SO 2 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 3 rd generation FGD systems which would integrate many of the advances in wet FGD design. While we are not aware of the u se of wet FGD on similar biomass-fired boilers, wet FGD is a technically feasible control option.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

- 66 - 

### 7.3.2 Dry Flue Gas Desulfurization.
Dry FGD is also a well demonstrated technology for the control of SO 2 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 so rbent 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 SO 2 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 (cem entitious) 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 u tility scale low sulfur coal-fired boilers. The LSDA process employs a spray dryer absorber (SDA) a nd a downstream PM control device. The SDA introduces a lime or limestone slurry and flue gas at th e 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 p asses through the absorber, cooling and humidifying the flue gas stream and rapidly drying the slurry to a powde r. In practice, water is added to control the SDA outlet temperature to approximately 155 o F, or an approach temperature approximately 25 o F above the saturation temperature. SO 2 in the flue gas reacts with calcium hydroxide in the reactor or on the fabric filter bags to form solid calcium sulfite (CaSO 3 ) and calcium sulfate (CaSO 4 ):

2Ca(OH) 2 (s) + 2SO 2 (g) + 2H 2 O (g) → 2(CaSO 3 • 2H 2 O) 2Ca(OH) 2 (s) + 2SO 2 (g) + 2H 2 O (g) +O 2 → 2(CaSO 4 • 2H 2 O)

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 circula ting 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 usedWe 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

- 67 - to further reduce SO 2 emissions. The ash captured in the baghou se 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 n eed for slurry handling, atomization, and a large reactor. Reinjecting a dry solid also allows the reagen t 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 conventiona l SDA system. These semi-dry FGD systems have demonstrated the ability to achieve SO 2 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 absorber s, circulating fluidized bed systems, hydrated lime injection systems, and flash dryer absorber s, are all demonstrated for the control of SO 2 emissions from coal-fired boilers. While the proposed biomass-fire d 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 LS DA 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. Severa l 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 th e duct downstream of the air preheater to cool and humidify the flue gas. The sorbents are typically either sodium or cal cium-based and are injected either in the furnace, or in the downstream ductwork prior to the PM contro l system. Calcium based sorbents include limestone and hydrated quicklime; sodium-based sorbents include sodium bicarbonate, and trona (sodium sesquicarbonate or Na 2 CO 3 • NaHCO 3 • 2H 2 O) 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 SO 2 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 dr y system. Sorbents such as limest one or hydrated lime are injected into the boiler furnace. The injection point is select ed 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 SO 2 removal. The reaction product and fly ash are collected in the PM collection system. Furnace sorbent injection systems typically achieve SO 2 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.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

- 68 - 

### Technical Feasibility.
Dry sorbent injection into the duct work is a technically feasible cont rol 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 fa ilure of the boiler to fluidize.



### 7.3.4 Emerging Flue Gas D esulfurization Technologies.
Emerging SO 2 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 scal e boiler or are not available or applicable. Of these advanced processes, the ECO system process is cl osest 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 SO 2 and sulfuric acid from the flue gas. The m echanism 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 partic ulate removal to collect the reaction product.



### Airborne Process TM

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 Po wer Initiative grant for demonstrating technology to achieve ultra-low emissions at a pr oposed 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 bi carbonate scrubbing. Because the sodium bicarbonate reagent is expensive and the reaction product has lim ited value, the Airborne ProcessTM is intended to regenerate the scrubber reagent. The regenerati on process would recover the reagent for reuse and
convert SO 2 and NO x into ammonium sulfate and ammonium nitrate fertilizers.



### Technical Feasibility.
While several advanced FGD technologies show promise in achieving very low SO 2 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 c ontrol options for this biomass-fired boiler.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

- 69 - 

### 7.3.5 Low Sulfur Fuels and Fuel Cleaning.
Sulfur dioxide emissions may be controlled by th e use of post-combustion FGD systems designed to
remove SO 2 from the flue gas after combustion. Because SO 2 emissions occur from the oxidation of fuel sulfur, SO 2 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, 5 th Edition, Table 1.6-2, the combustion of wood waste has a typical SO 2 emission rate of 0.025 lb/mmBtu. Tables 7-2 and 7-3 indicate that the potential SO 2 combustion concentration or uncontrolled SO 2 emission rate is substantially higher than the values from AP-42, ranging from 0.13 to 0.35 lb/mmBtu, with a typical potential SO 2 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 SO 2 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 ultima te 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 SO 2 Combustion Concentration, lb/mmBtu 0.22 0.24 0.23

Footnotes Reproduced from Steam, its generation and use , 41st Edition, The Babcock & Wilcox Company.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix A: Control Technology Review for the Biomass-Fired Boiler.March, 2010-70 -TABLE 7-3. Wood fuels analyses data and uncontrolled SO2emission rates.Wood Analyses, dry basis, weight %Site 1Site 2Site 3Site 4Site 6Site 7Average90thPercentileAnalysis, Dry BasisVolatile Matter 79.59 80.53 78.52 68.47 78.53 77.24 77.15Fixed Carbon 15.25 12.09 17.61 15.55 16.33 16.36 15.53Ash 5.16 7.38 3.87 15.99 5.15 6.40 7.33Carbon 50.28 50.55 52.90 45.38 50.11 50.45 49.95Hydrogen 5.92 5.95 5.85 5.17 5.87 5.86 5.77Nitrogen 0.46 0.53 0.51 0.73 0.52 0.62 0.56Sulfur 0.12 0.06 0.08 0.05 0.15 0.10 0.09Ash 5.16 7.38 3.87 15.99 5.15 6.40 7.33Oxygen 38.07 35.54 36.79 32.69 38.20 36.57 36.31Chlorine 0.08 0.03 0.16 0.06 0.03 0.05 0.07Heat Content, Btu per pound 8,238 8,599 8,795 7,543 8,353 8,437 8,327Uncontrolled SO2Emission Rate, lb/mmBtu 0.291 0.140 0.182 0.133 0.359 0.237 0.224 0.32Uncontrolled HCl Emission Rate, lb/mmBtu 0.100 0.036 0.187 0.082 0.037 0.061 0.084 0.14FootnotesData is from the U.S. EPA Report,Wood Products in the Waste Stream - - Characterization and Combustion Emissions, EPA Report EPA600/R-96-119a.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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## 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 va riable, 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 SO 2 combustion concentration for biomass fuels, i.e., the theoretical uncontrolled SO 2 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 - C haracterization 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 SO 2 to form calcium sulfate (CaSO 4 ). 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 necessar y to achieve greater than 90% removal on high sulfur fuels 12 . However, as the fuel sulfur content decrease s, 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. EP A’s Phase I survey Information Collection Request (ICR No. 2286.01) and the Phase II test plan (ICR No. 2286.03). SO 2 stack test data for biomass combustion indicates SO 2 concentrations in the flue gas ranging from 0.1 to 51 part per million at 3%
excess O 2 . These concentrations are equivalent to SO 2 emission rates of 0.0002 – 0.10 lb/mmBtu. Other data indicates higher SO 2 concentrations for biogas/natural ga s combustion and blends of industrial sludge/natural gas/wood/bark combustion of up to 102 ppm at 3% excess O 2 , equal to 0.19 lb/mmBtu.

The available data from the U.S. EPA and other databases indicates a wide range of potential SO 2 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” SO 2 emission rate of 0.09 lb/mmBtu, equal to an SO 2 concentration of 48 parts per million at 3% excess oxygen.

12 From STEAM, its generation and use , 41 st 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.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

- 72 - 

### 7.4.2 Wet Flue Gas Desulfurization.
Modern wet FGD designs can achieve 95 - 99% SO 2 removal on an initial performance guarantee and maximum short term basis when firing high sulfur coal s. However, it is the conclusion of the U.S. EPA and other agency decisions that it is not technically feasible to achieve this hi gh control level day after day, year after year. Further, because these bioma ss-fired boilers are expected to have a very low “uncontrolled” SO 2 emission rate of 0.09 lb/mmBtu, a 90% reduction would be equal to an SO 2 emission rate of only 0.01 lb/mmBtu, equal to about 5 ppm at 5% O 2 . For this analysis, a wet FGD system is expected to reduce SO 2 emissions to a level of 0.02 lb/mmBtu, or 10 ppm at 5% O 2 .


### 7.4.3 Dry Flue Gas Desulfurization.
Modern dry FGD designs can achieve 90 - 95% SO 2 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 SO 2 emission rate of 0.03 lb/mmBtu.



### 7.4.4 Dry Sorbent Injection.
According to the U.S. EPA, dry sorb ent injection systems have typical SO 2 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 injection 15 . For this analysis, dry sorbent injection is expected to achieve an SO 2 emission rate of 0.05 lb/mmBtu, equa l to a 45% reduction from the biomass fuel uncontrolled SO 2 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 SO 2 control technologies based on the above analysis of available technologies.

TABLE 7-4. Ranking of the technically feasible SO 2 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/page s/index.cfm?pageid=3401

.
15 Refer to several papers presented by Solvair, available at http://www.solvair.us

.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

- 73 - 

## 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 SO 2 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 SO 2 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 au xiliary electric power requirements. In a wet FGD system, auxiliary electric power is required to ope rate 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 contro l technology costs. A detailed cost analysis for the SO 2 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 SO 2 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 SO 2 controlled.
In addition, the use of a wet FGD system would ha ve an increased incremental cost of $2.1 million per year as compared to the use of dry FGD. The wet FGD system would reduce SO 2 emissions by 31 tons per year as compared to the use of a dry FGD syst em. This would result in an incremental cost effectiveness of wet FGD, as compared to dry FGD, of $66,500 per ton of SO 2 controlled.



### Conclusion.

While a wet FGD SO 2 control system is technically feasible fo r 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 ne w 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 al so require substantial auxiliary electric power requirements. Finally, the u se of a wet FGD system would have an average cost effectiveness of $43,800 per ton of SO 2 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.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

- 74 - TABLE 7-5. Cost effectiveness of the SO 2 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 SO 2 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 SO 2 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 cal culated 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 SO 2 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 CRFWe 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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### 7.5.2 Rank No. 2: Dry Flue Gas Desulfurization.

Environmental and Energy Impacts.

The next most effective SO 2 control option is the use of a dry F GD system in combination with firing biomass fuels. Based on the above analys is, a dry FGD system could reduce potential SO 2 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 woul d also require additional auxiliary electric power requirements to operate injection pumps and for the induced draft fan requireme nts to overcome the dry FGD system pressure drop.



### Economic Feasibility.
Table 7-5 includes a summary of the SO 2 control technology costs. A dry FGD system is expected to have a total capital cost of $40 million, annual O&M co sts of $3.0 million, and a total annual cost of $7.4 million. From Table 7-5, a dry FGD system would reduce actual SO 2 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 SO 2 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 SO 2 emissions by 60 tons per year as compared to the use of a sorbent in jection system. This would result in an incremental cost effectiveness of dry FGD, as compared to sorbent injection, of $102,600 per ton of SO 2 controlled.



### Conclusion.
While a dry FGD SO 2 control system is technically feasible fo r the proposed biomass-fired boiler, the use of a dry FGD system would have significant energy, e nvironmental, 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 elect ric power requirements. Finally, the use of a dry FGD system would have an average cost effectiveness of $40,070 per ton of SO 2 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.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

- 76 - 

### 7.5.3 Rank No. 3: Sorbent Injection.

Environmental and Energy Impacts.

The next most effective SO 2 control option is the use of a dry sorbent injection system in combination with firing biomass fuels. Based on the above anal ysis, a dry sorbent injection system could reduce potential SO 2 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 in jection system would increase ash generation rates and may adversely impact the flyash properties wh ich may reduce its value for reuse and increase ash disposal requirements.
As with wet and dry FGD systems, a dry sorbent inje ction system would also re quire additional auxiliary electric power requirements to operate injection pump s and for the induced draft fan requirements to overcome the additional fabric filter baghouse pressu re drop due to the sorbent injection.



### Economic Feasibility.
Table 7-5 includes a summary of the SO 2 control technology costs. A dry sorbent injection system is expected to have a total capital cost of $3.3 milli on, annual O&M costs of $88 0,000, and a total annual cost of $1.2 million. From Table 7-5, a dry sorbent injection system would reduce actual SO 2 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
SO 2 controlled.



### Conclusion.
While a dry sorbent injection SO 2 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 requireme nts. Finally, the use of a dry sorbent injection system would have an average cost effectiveness of $9,950 per ton of SO 2 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 circula ting fluidized bed boiler is expected to have SO 2 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 av ailable control technology for this biomass fuelsfired boiler.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

- 77 - 

## 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 SO 2 emissions for the biomass fuels-fired CFB boiler. Based on this analysis, We Energies pr oposes the following limits as BACT for the control of SO 2 emissions from this biomass fuels-fired boiler.

(1) Sulfur dioxide (SO 2 ) 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 fuel s may be combusted in the boiler. (b) “Biomass fuels” means a resource that de rives 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 w aste, tree services, and construction companies

• clean solid wood waste from discarded w ood 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, sew erage sludge, and animal waste.
(2) SO 2 emissions may not exceed 0.09 pounds per million Btu of heat input, averaged over any consecutive 30-day period.
(3) SO 2 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.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

- 78 - 

# 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 re latively 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 designe d to achieve the highest combustion efficiencies practicable. VOC emissions can be reduced by op erating the boiler with higher flame temperatures, higher excess oxygen levels, and longe r furnace residence times. Unfo rtunately, techniques for reducing VOC emissions can increase NO x emissions. Consequently, as with CO emissions, achieving low VOC and NO x 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 perm its 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 Biomas s Generation facility (Ohio, 2006), the facility was required to install an oxidation catalyst. Howeve r, this facility has not been constructed.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

- 79 - 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 Technical ly 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 emission s - 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 de monstration on biomass-fired boilers , and we are not aware of any demonstration or commercial operation of oxidation cat alysts on a fluidized bed boiler. Boilers have several characteristics that make the use of oxidatio n 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 catalyst s which are susceptible to poisoning from sulfur and calcium bearing compounds. These catalysts may expe rience 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 m echanisms was presented at the 2008 Advanced Combustion Engineering Research Center confer ence reported that SCR catalyst poisoning is the predominant deactivation mechanism resulting from biomass combustion. Note that oxidation catalystsWe 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

- 80 - 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 lo w acid gas constituents such as sulfur dioxide (SO 2 ), 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 pr imary reason that oxidation catalyst and SCR systems located in a high dust envir onment 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 th e 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:

C 3 H 8 + 5O 2 → 3CO 2 + 4H 2 O
Typical excess oxygen (O 2 ) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in biomassfired boilers. These low excess O 2 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. Therma l 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, si nce 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 V 2 O 5 /TiO 2 SCR Catalysts , ACERC Annual Conference, February 2008.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

- 81 - 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 ge nerally 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 ar e 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 prim arily 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
NO x emissions. This is a difficult task, since emissions of NO x and emissions of CO and VOC are inversely related. That is, measures used to reduce NO x emissions often lead to increases in VOC emissions. Therefore, the boiler design to minimize VOC emissions is interrelated with the boiler design to minimize NO x formation.



## 8.4 STEP 3. Rank the Technica lly 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 gene rally expected to achieve low VOC emission rates. However, boiler startup, shutdown, and load change s can causes VOC emissions to increase because of unstable combustion conditions. Li ke CO emissions, VOC emissions are also sensitive to boiler operating conditions. Changes in operating conditions, such as rapi d 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, an d the low air flow rates make it difficult to obtain good air/fuel mixing. For these reasons, VOC emissi ons can “spike” when tr ansient conditions occur during boiler startup and shut downWe 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

- 82 - Based on the above analysis, we have conclude d 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 ach ieve a VOC emission rate of 0.017 pounds per million Btu based on a 12-month average, incl uding 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 emissi ons 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 go od 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 i nput, 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.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

- 83 - 

# 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 (CaF 2 ). Fluoride compounds such as sodium and calcium fluoride are solids at the flue gas temperatures entering the particulate matter c ontrol 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 al kaline 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. Accordi ng to NCASI Technical Bulletin No. 0837, Emissions of Sulfuric, Hydrochloric, and Hydrofluoric Ac ids 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 MA CT database emission factors fr om 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 In stitutional 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 , 5 th 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/m 3 , 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. EP A’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 forWe 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

- 84 - 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 Bioma ss/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 GasWe 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

- 85 - 

## 9.3 STEP 2. Identify Technical ly 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 pa rticulate matter control systems, and also acid gas control systems. Tech nologies that may control fluoride emissions include fabric filter baghouses, electrostatic precipitators, we t or dry FGD systems, and sorbent injection.



### 9.3.1 Flue Gas Desulf urization Systems.
Wet and dry flue gas desulfurization systems are effective fluoride control systems. From the EPRI report, Emission Factors Handbook: Guidelines for Estim ating 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 in formation 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 injecti on 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 H 2 SO 4 emissions. However, the continuous reduction of HF via hydrated lime injection from biomass combustion is not well underst ood or demonstrated in practice. Further, because biomass combustion already results in high levels of calcium oxide (CaO) and potassium oxide (K 2 O) in the ash, so that the additional injection of sorben t may not achieve substan tial 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, Hydr ochloric, 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 0.000 074 lb/mmBtu for the oil/bark boilers.
According to the U.S. EPA’s MA CT database emission factors fr om 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 In stitutional 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 , 5 th 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/m 3 , equal to 0.0011 lb/mmBtu.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

- 86 - 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. EP A’s Phase I survey Information Collection Request (ICR No. 2286.01) and the Phase II test plan (I CR 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 ove r 350 samples for biomass fuels (with descriptions including wood, bark, plywood, particleboard, hog fu el, 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 ra nging 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 probabilit y 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, base d on emission testing, is 0.0007 lb/mmBtu. This data suggests that the actual HF emissions are redu ced by almost 90% as comp ared to the uncontrolled, fuel input or potential combustion concentration for HF.

FIGURE 9-1. Hydrogen fluoride (HF) fuel samp ling 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 BtuProbability Density HF Emission Test Data

HF Fuel Sampling Data

90% Probability, 0.0007 90% Probability, 0.006 lb/mmBtuWe 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

- 87 - 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 datab ase, 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 availa ble 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 ca nnot 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 0.001We 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

- 88 - 

## 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 F GD 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 c onsume 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 opti on, would reduce actual HF emissions by 1.5 tons per year as compared to the uncontrolled biomass fuels em ission 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. Th is 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 inj ection 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. Howe ver, 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 co mbustion systems would requi re additional auxiliary electric power requirements.
The use of dry sorbent injection, th e lowest cost option, would reduce actual HF emissions by 1.5 tons per year and a total annual cost of $1.2 million. This r esults in an average cost effectiveness for the dry sorbent injection system of $806,000 per ton of HF cont rolled. 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.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

- 89 - 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 cal culated 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 CRFWe 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

- 90 - 

## 9.6 STEP 5. Proposed Fl uorides BACT Determination

Based on this analysis, We Energies has concluded that the combustion of low fluorine containing biomass fuels is the best available control technol ogy (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 fuel s may be combusted in the boiler. (b) “Biomass fuels” means a resource that de rives 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 w aste, tree services, and construction companies

• clean solid wood waste from discarded w ood 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, sew erage 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 

# Attachment 1.

Cost estimates for a Tail Gas or Regen erative 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 Parameters 1



### .

Variable Description Value Qb Boiler Size (mmBtu/hr) 2 800
NOx i n NO x inlet (lb/mmBtu) 0.15

NOx i n NO x outlet (lb/mmBtu) 4 0.06 Plant wide capacity factor 5 88%
S Sulfur content of fuel (weight fraction) 6 0.01 T Gas temperature (°F) 7 650
N SCR Number of reactor chambers 8 1

Variable Description Units Reference 9 Value

q fuel Volumetric flow rate for fuel ft 3 /min-MMBtu/hr Table 2.4 516

q flue g as Flue gas flow rate 10 acfm C alculated Value 323,789 ASR Actual Stoichiometric ratio (ASR) 2.11 1.05 Slip Theoretical ammonia slip 11 ppm by volume Page 2-37 10.00
η ad j Efficiency adjustment factor 2.20 1.13
NOx ad j NO x adjustment factor 2.21 0.90 Slip ad j Ammonia slip adjustment factor 2.22 0.72
S ad j Sulfur in fuel adjustment factor 2.23 0.96
T ad j Temperature adjustment factor 2.24 1.15

N SC R Number of reactor chambers 8 1.00
Vol catal y s t Volume of catalyst ft 3 2.19 1816

A catal y st Catalyst cross sectional area ft 2 2.25 337

A SCR Reactor cross sectional area ft 2 2.26 388 l Length and width of reactor ft 2.27 19.7 h' la y er Nominal catalyst height ft Page 2-38 3.1

n la y e r Number of catalyst layers 2.28 2.0 h la y e r Height of each catalyst layer ft 2.29 3.7

n em p t y Estimated # of empty catalyst layers Page 2-53 1.0

n total Total # of catalyst layers 2.30 3.0
C 1 Page 2-39 7.0
C 2 Page 2-39 9.0 h SC R Height of SCR reactor ft 2.31 41.1
M rea g en t Molecular weight of ammonia g/mole Page 2-39 17.0
M N Ox Molecular weight of NO 2 g/mole Page 2-39 46.0
SR T Ratio of moles of NH 3 per mole of reagent injected Page 1-24 1.0

m

rea g ent Reagent mass flow rate 12 lb/hr 2.32 37.3

C sol % concentration of aqueous reagent solution 13 Page 2-40 0.19 Constants for h SCR 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 Parameters 1



### .

Variable Description Value Qb Boiler Size (mmBtu/hr) 2 800
NOx i n NO x inlet (lb/mmBtu) 0.15

NOx i n NO x outlet (lb/mmBtu) 4 0.06 Plant wide capacity factor 5 88%
S Sulfur content of fuel (weight fraction) 6 0.01 T Gas temperature (°F) 7 650
N SCR Number of reactor chambers 8 1

Variable Description Units Reference 9 Value SCR Equation Inputs

SCR Parameter Estimates

m sol Mass flow rate of aqueous ammonia solution lb/hr 2.33 196

ρ sol Density of aqueous ammonia solution lb/ft 3 Page 2-40 56

υ sol Specific volume of aqueous ammonia solution gal/ft 3 Page 2-40 7.48

q sol Solution volume gph 2.34 26.2 t Operating days 14 days Page 2-54 14 Ammonia Tank Volume gal 2.35 8814 CF Plan t Boiler capacity factor 2.7 0.88

q rea g en t Assuming same as q sol 23.08

t o p Total Operating Time hours/yr 1.22a 7708.8
Δ P duc t Pressure drop (used mid-range value) inches H 2 O Page 2-46 2.5
Δ P catal y st Pressure drop (used mid-range value) inches H 2 O Page 2-46 0.875 Power Electrical power consumption kW 2.48 224.12
Cost elect Electrical power costs 15 $/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 N SC R is equal to n SCR 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 NO x Emission Rate, lb/mmBtu 0.15 Total Heat Input Capacity 800
Total NO x 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 Costs 1

Direct Cost Calculation Variable Description Value f(h SCR ) Adjustment for SCR reactor height, $ per mmBtu per hour 63.49 $ f(NH 3 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 - $

CC initial Initial catalyst cost, $/ft 3 240 $ f(Vol catalyst ) 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 Flowrate 1 , scfm 323,789 Stack Temperature, o F 1 315 SCR Temperature, o F 600 Flue Gas Reheat Temperature Rise, o F 285 Density of flue gas at standard conditions 2 , lb/ft 3 0.0779
Mass flow rate of Flue Gas, lb/hour 1,512,985 Heat Capacity of Flue Gas, Cp 3 , Btu/lb- o F 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/10 6 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 NO x 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 $1.30/gallon for 19% ammonia. Ammonia Input requirement, lb/hr 55.2 Based on 1.2 moles NH 3 per mole of NOx. Annual Ammonia Requirement, lb/year 425,526 Total Ammonia Costs ($/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/ft 3 and 579 ft 3 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. 3/4/2010We 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 3.5We 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 9.39We 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: N OTE: A difficult retrofit factor was used because this tailgas SCR system would control both the existing Boiler 4 and theWe 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 CapacitiesWe 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.

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 226.7We 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.

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 65,491We 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.

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 2,994We 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 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 $ $306,186We 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.

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) $ $0We 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.

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 Case1We 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.

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).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.



## L ime S p ra y Dr y er (LSD or Dr y FGD) Material Balance - Pre l 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 956,309We 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.

Flue Gas Downstream of Particulate Control Device Temperature °F 147 Pressure in. H2O -23 Flow Rate SCF M 221,579 Flow Rate ACF M 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 658We 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 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 3,854We 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.

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 3,489We 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 (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 $ $182,912We 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.

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 $ $5,552,498We 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.

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 $469,375We 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. 

### 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 SO 2 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. ) Equ i pment cost + aux ili ar i es $ 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-03-03 4 0.10 x A 0.07 x A

Basis V alue

Biomass-Fired BoilerWe 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. 

### 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 Construc tion 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 E NVIRONMENTAL A SSOCIATES I NC .®
903 Superior Avenue, Suite 6 Tomah, WI 54660We 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 tw o new natural gas-fired package boilers, designated as Boilers B02 and B03, at the We Energies’ 50 MW Biomass Fuels Plant in Ro thschild. This control technology review is required for major new source s 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 p ounds per hour of steam. To deliver this steaming capacity, each boiler will ha ve 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 NO x burners and flue gas recirculation to control emissions of CO, NO x , PM/PM 10 , PM 2.5 , and VOCs.
Table ES-1 summarizes the proposed emission limits which represent the best available control technology (BACT) for these new package boilers, a nd the potential emissions for each boiler. The proposed BACT conditions are summarized in Table ES-2.

TABLE ES-1. Proposed emission limits representi ng 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 NO x 0.02 10.9

Particulate Matter PM/PM 10 0.0076 4.1

PM < 2.5 microns PM 2.5 0.0076 4.1

Sulfur Dioxide SO 2 0.0006 0.3

Organic Compounds VOC 0.006 3.3

Fluorides (as HF) HF n/a 0.3We 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

- 3 - TABLE ES-2. Proposed control technologies a nd 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 (NO x ) (1) NO x emissions shall be controlled using Ultra Low NO x Burners and Flue Gas Recirculation in combination with good combustion practices as BACT. (2) NO x emissions may not exceed 0.02 lb/mmBtu, based on a 30-day rolling
average.

Particulate Matter (PM) and PM 10 (1) PM and PM 10 emissions shall be controlled usin g natural gas as fuel and good combustion practices as BACT. (2) PM and PM 10 emissions may not exceed 0.0076 lb/mmBtu.

PM 2.5 (1) PM 2.5 emissions shall be controlled using natural gas as fuel and good combustion practices as BACT.. (2) PM 2.5 emissions may not exceed 0.0076 lb/mmBtu.

Sulfur Dioxide (SO 2 ) (1) SO 2 emissions shall be controlled using natural gas as fuel as BACT. (2) SO 2 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 50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc. Appendix B: Control Technology Review for the Natural Gas-Fired Boilers. March, 2010

- 4 - 

# Table of Contents

Chapter 1. Introduction and So urce Description................................................8
Chapter 2. Control Technology Re view Metho dology......................................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 Co st Effectiveness. ........................................................................ 14


## Chapter 3. Carbon Monoxide (CO) Contr ol 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........................................................................................................... 2 1 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 (NO x 

## ) Control Techno logy 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 NO X 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................................................................................... 32We 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

- 5 - 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 NO x Burners.............................................. 36
4.6 STEP 5. Proposed Nitrogen Ox ide BACT Determination............................................................ 36


## Chapter 5. Particulate Matter and PM 10 

## 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. PM 2.5 

## Control Technolo gy Review...................................................43

6.1 BACT Baseline. ................................................................................................................. ............ 43
6.2 STEP 1. Identify All Potential Control Technologies................................................................... 44

6.2.1 Direct PM 2.5 Emissions. .................................................................................................... 44
6.2.2 PM 2.5 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 PM 2.5 BACT Determination............................................................................ 49


## Chapter 7. Sulfur Dioxide (SO 2 

## ) Control Techno logy Review.........................50

7.1 BACT Baseline. ................................................................................................................. ............ 50We 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

- 6 - 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........................................................................................................... 6 1 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 Tec hnology Re view............................................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................................................................................. .. 67We 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

- 7 - 

# Tables

TABLE 1-1. Potential air emissions for each 125,00 0 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 monoxi de (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 (NO x ) emission limits representing BACT from the U.S. EPA's RBLC database..................................................................................................28 TABLE 4-2. Summary of the technical feasibility of retrofit NO x control technologies. ..........................33

TABLE 4-3. Ranking of the technically feasibl e NOx control technologies............................................34

TABLE 4-4. Estimated SCR NO x control system costs for each natural gas-fired boiler. ........................35 TABLE 5-1. Natural gas-fired boiler particulate ma tter emission limits representing BACT from the U.S. EPA's RBLC da tabase..........................................................................................................38 TABLE 7-1. Natural gas-fired boiler SO 2 emission limits representing BACT from the U.S. EPA's RBLC database....................................................................................................................... .........51 TABLE 8-1. Natural gas-fired boiler VOC emissi on 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-fi red boiler hydrogen fluoride (HF) test results................65We 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

- 8 - 

# Chapter 1. Introduction and Source Description.

This document is a Control Technology Review for tw o new natural gas-fired package boilers, designated as Boilers B02 and B03, at the We Energies’ 50 MW Biomass Fuels Plant in Ro thschild. This control technology review is required for major new source s 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 ha ve 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 NO x burners and flue gas recirculati on to control emissions of CO, NO x , PM, PM 10 , PM 2.5 , and VOCs. A typical large industrial package boiler is shown in Fi gure 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 ).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

- 9 - 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 TO EMIT POLLUTANT

lb/mmft 3 lb/mmBtu mmBtu/hr lb/hr tons/yr
Carbon Monoxide CO 63.0 0.06 175 10.50 32.6 Nitrogen Oxides NO x 21.0 0.02 175 3.50 10.9
Particulate Matter PM/PM 10 7.6 0.0076 175 1.33 4.1
Particulate Matter PM 2.5 7.6 0.0076 175 1.33 4.1
Sulfur Dioxide SO 2 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 H 2 SO 4 0.006 0.000006 175 0.0011 0.0033

Footnotes 1. For natural gas combustion, the CO and NO x 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 NO x emission rates of 0.06 and 0.02 lb/mmBtu, respectively.

E = KC h F( 20.9) where, E = Emission Rate, lb/mmBtu 20.9 - %O 2 F = F-Factor, dscf/mmBtu

Natural Gas Combustion K C h , ppm F , dscf/mmBtu %O 2 E , lb/mmBtu Carbon Monoxide CO 7.59E-08 75 8,710 5.0 0.058 Nitrogen Oxides NO x 1.19E-07 9 8,710 5.0 0.012
2. The emission factors for uncontrolled PM, PM 10 , PM 2.5 , SO 2 , 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 PM 10 emissions are assumed to be PM 2.5 . 3. Sulfuric acid mist emissions for natural gas combustion are based on 1% conversion of SO 2 to SO 3 . 6. Potential emissions are based on limiting the fuel use to:

Natural Gas: HI = 1,085,000 mmBtu, 12-month average 6,200 hour/yrWe 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

- 10 - 

# Chapter 2. Control Technology Review Methodology.

2.1 Best Available Control Technology Definition.

The Clean Air Act and the Prevention of Significant De terioration (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 w ould 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 me thods, systems, and techniques, including fuel cleaning or treatment of innovative fuel combustion tec hniques 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 re gulation under the Act whic h 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, a nd economic impacts, and other costs, determines is achievable for such source or modification throug h 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 contamin ant. In no event may application of best available control technology result in emissions of any air c ontaminant 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 utiliz ing clean fuels or any other means to comply with this subsection may not be allowed to increase a bove 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 par ticular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practi ce, operational standard or combination thereof, may be prescribed instead to satisfy the requirement for th e application of best available control technology. The standard shall, to the degree possible, set fo rth the emissions reduction achievable by implementation of such design, equipment, work practice or operatio n, 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 signi ficant 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 SO 2 , NO x , PM/PM 10 , CO, VOC, and sulfuric acid mist.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

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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 technol ogies until a level of cont rol considered BACT is reached, based on the environmental, energy, and eco nomic 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 pr actical potential for app lication to the emission unit and regulated pollutant under evaluation;

2. Eliminate all technically infeasible control technologies;

3. Rank remaining control technologies by effec tiveness 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 associ ated with a control alternative may be considered if dispersion modeling analyses are performed. The en ergy 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 tota l 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 effectiven ess and ultimately, whether the option is economically reasonable. The economic impacts are reviewed on a cost per ton contro lled 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 statutor y 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 provi de the “maximum degree of emissions reduction.” Second, any decision to require a lesser degree of emi ssions 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 contro ls 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 NO x burners on existing boilers often cannot achieve the same NO x , CO, and VOC emission rates as the use of low NO x burners on a new boiler which has been designed to optimize the low NO x burner design. This can in turn affect the ultimate NO x emission rates which can be achieved by post combustion controls such as selective catalytic reduction.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

- 12 - Retrofitting controls on existing boilers can also have significantly different costs as compared to the use of these same technologies on new units. Retrofitti ng controls on existing boilers can have numerous issues, including site constraints and room for th e new controls, demolition requirements for existing controls, and down time during construction a nd 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 tec hnologies 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 em ployed 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) c ontrols applied to similar source categories and gas streams, and innovative control technologies. Tec hnologies 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 stat es, “Technologies which have not yet been applied to (or permitted for) full scale operations need not be cons idered 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 "demons trated" successfully for the type of emission source under review, then it would normally be considered technically feasible. For an undemonstrated technology, “availability” and “applic ability” 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 beWe 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

- 13 - 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 emissi on 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 simila r 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 incremen tal 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 su ccessfully 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:

Control option annualized cost Average Cost Effectiveness ($ per ton removed) = Baseline emission rate – Control option emissions rate

The average cost effectiveness is based on the overa ll 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.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

- 14 - 

### 2.6.2 Incremental Cost Effectiveness.
In addition to determining the average cost effectiv eness of a control option, the U.S. EPA’s New Source Review Manual states that the incremental cost e ffectiveness between dominant control options should also be calculated. The incremental cost effec tiveness compares the costs and emissions performance level of a control option to those of the next most stringent control option:

Control option annualized cost – Next control option annualized cost Incremental Cost ($ per 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 whic h 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, PM 10 , NO x , and SO 2 emissions for biomass-fired boilers, pulverized coal-f ired boilers, circulating fluidized bed boilers, and gas turbines. While cost effec tiveness is determined on a case-by-case basis, the following information on comparative economic costs of BACT options gives some perspective on the co sts that similar sources have typically not been expected to bear as BACT.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix B: Control Technology Review for the Natural Gas-Fired Boilers.March, 2010-15 -TABLE 2-1. Summary of recent BACT economicanalyses in which the control technology was rejected as not cost effective for BACT.Cost Effectiveness ofRejected Technology,$ per ton controlledFacilityStateBoilerTypePollutantControlTechnologyRejectedAverageIncrementalControlTechnologySelectedAverage CostEffectiveness ofSelectedTechnology,$ per ton1DTE Energy – StonemanPower PlantWI Stoker NOx SCR $9,217 SNCR2We Energies – ConcordGenerating StationWIGasTurbNOxSCR 8,236 -GoodCombustion3 Longleaf Energy Associates GA PC SO2Wet FGD - $8,964 Dry FGD $7244Rocky Mountain PowerHardinMT PC SO2Wet FGD $1,395 $23,855 Dry FGD $9185Intermountain Power 3 UT PCPM /PM10Baghouse w/Teflon Bags$31 $14,000Baghouse w/Ryton Bags$31NOxSCR at 0.04 $2,004 $10,303 SCR at 0.05 $1,5116Basin Electric – Dry ForkStationWY PCSO2Wet FGD $1,595 $15,299 Dry FGD $1,1597Black Hills Power & Light– WYGEN2WY PC NOxSCR at 0.06 $4,156 $7,742 SCR at 0.07 $4,0678Black Hills Power & Light– WYGEN3WY PCPM /PM10Baghouse w/Teflon Bags$134 $14,609Baghouse w/Fiberglass Bags$1309Deseret Power Cooperative– BonanzaUT CFB SO2Wet FGD $418 $10,540 Dry FGD $397Wet FGD - $27,36510Southern Montana ElectricCoop- HighwoodMT CFB SO2Dry FGD - $7,939Ash Reinjection $4,05411Montana-Dakota UtilitiesGascoyne StationND CFB NOxSCR $7,545 $14,339 SNCR $2,92612Red Trail Energy EthanolPlantND CFB SO2Wet FGD $1,041 $10,252 Dry FGD $52713 River Hill Power Company PA CFB SO2Wet FGD - >$5,000 Dry FGD $1,51114 Cargill – Blair Ethanol Plant NE CFB SO2Dry FGD - $5,900 No Post ControlsNOxSNCR - $5,600 SNCR $2,17415ADM – Columbus EthanolPlantNE CFBSO2Ca Inj. - $6,70016 Lakefield Junction Station MN CT CO Ox. Catalyst 3,400 - No Post ControlsWe 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

- 16 - 1. In a PSD permit for the conversion of two coal-fi red boilers to wood combustion, the Department concluded that the use of regenerative selec tive catalytic reduction with an average NO x control cost of $9,217 per ton was not economically feasible.

2. In a PSD permit for 320 MW of simple cycle comb ustion turbine capacity, the Department concluded that the use of selective cataly tic reduction with an average NO x 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 th at the incremental cost effectiveness of $8,964/ton for wet FGD compared to dry FGD for SO 2 control was not cost effe ctive. The average cost effectiveness of the selected BACT option, dry F GD, was $724/ton. Georgia’s PD is available online
at: http://www.air.dnr.state.ga.us/airpermit/p sd/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, M ontana 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, dr y 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 concl uded 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/PM 10 control, was excessive fo r BACT. The average cost effectiveness of the selected BACT option for PM 10 control (a baghouse with Ryton-type bags) was $31/ton. (Ref: Utah’s Modified Source Plan Revi ew 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 Wyomi ng 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 NO x 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 NO x 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 incrementa l cost effectiveness of $15,299/ton for SO 2 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 e liminated wet FGD option at 0.054 lb/mmBtu was $1,595/ton. Although Wyomi ng 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 SO 2 control was a dry FGD system at 0. 08 lb/mmBtu, with an average cost effectiveness of $1,159/ton. (Ref: Wyoming’s An alysis for the Dry Fork project, NSR-AP-3546, February 5, 2007.)

7. In a PSD permit issued by the State of Wyomi ng 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-NO x burners plus SCR at 0.06 lb/mmBtu to low-NO x burners plus SCR at 0.08 lb/mmBtu, for NOx control was reasonable for BACT. However, for other reasons described by Wy oming, the selected BACT option was low-NO x burnersWe 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

- 17 - 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 Wyomi ng 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 capabl e 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/PM 10 control, was excessive for BACT. The aver age cost effectiveness of the selected BACT option, a baghouse with fiberglass or polyphenyle ne sulfide filter bags, was $130/ton; the average cost effectiveness of the eliminated option, a baghou se 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 B onanza Power Plant, the EPA concluded that an incremental cost of $10,540 per ton of SO 2 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 SO 2 controlled; the average cost eff ectiveness for the dry FGD system selected as BACT was $397/ton of SO 2 controlled. Further, the EPA concluded that the costs for alternative sources of coal in lieu of waste coal of $20,241 per ton of SO 2 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 SO 2 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 SO 2 controlled, for a combination of limestone injection, low-sulfur coal and dry FGD, was excessive for BACT. The selected SO 2 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, Nort h 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 NO x 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 Da kota in 2004 for a CFB boiler at the Red Trail Energy’s Richardton, ethanol plant, North Dakota de termined that an incremental cost effectiveness of $10,252/ton, comparing wet FGD plus limestone in jection to dry FGD plus limestone injection, for SO 2 control was not cost effective. The average cost effectiveness of wet FGD plus limestone injection was $1,041/ton; the average cost effec tiveness of dry FGD plus limestone injection was $527/ton. North Dakota rejected wet FGD and determ ined 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 SO 2 BACT options involving wet FGD systems were economically infeasible at an incremental dollar per ton value greater than $5,000 per ton of SO 2We 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

- 18 - removed. Pennsylvania concluded that the use of dry FGD was economically feasible for the control of SO 2 at an incremental cost of $1,511 per ton of SO 2 removed. Pennsylvania also concluded that an incremental cost effectiveness of $15,975/ton, comp aring the use of the waste coal to the nearest alternative source of coal with lower sulf ur content, was excessive as BACT for SO 2 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 SO 2 control, was excessive for BACT. (Ref: Nebraska permit CP06-0008, Sept. 8, 2006, available at http://www.epa.gov/region07/programs/art d/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 plan t, Nebraska indicated that incremental cost effectiveness of $5,600/ton for NO x control (comparing SNCR at 0.07 lb/mmB tu to SNCR at below 0.07), and an incremental cost effectiveness of $6,700/ton for SO 2 /H 2 SO 4 /HF control (comparing limestone injection to “additional” limestone injection), we re excessive for BACT. Nebraska listed incremental cost-effectiveness of $2,174 for the selected BACT option for NO x control (SNCR at 0.07 lb/mmBtu). (Ref: Nebraska permit CPM02-0006, A ugust 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 tu rbines 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 in formation 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 es timated lifetime of 2.5 months.” Therefore, emissions of CO from this facility will eventua lly 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 insignifi cant 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 tr ansportation 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 (a nd presumably prior as well) primarily due to measures taken to control emissions from mobile sources.

The Minnesota Pubic Utilities Commission externa lity hearings found that the costs to the environment attributable to CO em issions were $0.021-0.041 per ton.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

- 19 - 

# Chapter 3. Carbon Monoxide (CO) Control Technology Review.

Carbon monoxide (CO) is emitted from natural gas-fire d boilers as a result of incomplete combustion. Incomplete combustion can also result in reduced boile r efficiency and emissions of particulate matter, volatile organic compounds, and organic hazardous ai r pollutants. Because fuel costs represent the highest single operating cost for these boilers, th ese 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, a nd longer furnace residence times. Unfortunately, techniques for reducing CO emissions can increase NO x emissions. Achieving low CO and low NO x 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. Th e technologies identified include Good Combustion Practices (GCP), and in one instance, Oxidation Ca talysts (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. Th ese rates were converted to lb/mmBtu to make the emission limits comparable.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix B: Control Technology Review for the Natural Gas-Fired Boilers.March, 2010-20 -TABLE 3-1. Natural gas-fired boiler carbon monoxide (CO) emission limits representing BACT from the U.S. EPA's RBLC database.RBLC IDFACILITYPERMITDATEPROCESSTHRUPUT ,mmBtu/hrCONTROLSLIMIT,lb/mmBtuOR-0040 Klamath Generation 03/12/03 Auxiliary Boiler 0.035TN-0153 Williams Refining & Marketing, L.L.C. 04/03/02 Heater 9.1 0.035LA-0229 Shintech Louisiana Plaquemine Plant 2 07/10/08 Utility Boilers 250.0 GCP 0.036*GA-0127 Southern Company Plant Mcdonough 01/07/08 Auxiliary Boiler 200.0 0.037OR-0046 Calpine Turner Energy Center 01/06/05 Auxiliary Boiler OC 0.038CO-0052 Rocky Mountain Energy Center. 08/11/02 Auxiliary Boiler 129.0 GCP 0.039*AL-0230 Thyssenkrupp Steel And Stainless USA 08/17/07 3 Boilers 64.9 0.040MN-0062 Heartland Corn Products 12/22/05 Boiler 198.0 0.040WV-0023 Longview Power 03/02/04 Auxiliary Boiler 225.0 GCP 0.040AR-0070 Genova Arkansas I 08/23/02 Auxiliary Boiler 33.0 GCP 0.040AR-0026 Pine Bluff Energy Center 05/05/99 Boiler 362.0 GCP 0.044SC-0049 Skygen Broad River Energy 12/02/99 Utility Boilers 230.0 GCP 0.060TN-0153 Williams Refining & Marketing 04/03/02 WCR Heater 209.0 0.070*ID-0017 Southeast Idaho Advanced Energy Center 02/10/09 Package Boiler 250.0 GCP 0.074MN-0066 Northern States Power Riverside Plant 05/16/06 Auxiliary Boiler 160.0 GCP 0.080WI-0228 Wisconsin Public Service - Weston 10/19/04 Auxiliary Boiler229.8 GCP 0.080OK-0045 Redbud Power Plant 08/15/01 Auxiliary Boiler20.0 GCP 0.082IN-0085 PSEG Lawrenceburg Energy 06/07/01 Auxiliary Boiler124.6 GCP 0.082AR-0055 Nucor Yamato Steel (Armorel) 10/10/01 Process Heaters GCP 0.082TN-0153 Williams Refining & Marketing 04/03/02 Boiler, No. 9 95.0 0.090AR-0057 Tenaska Arkansas Partners, LP 10/09/01 Boiler, (2) 122.0 GCP 0.110NE-0024 Cargill - Blair Plant 06/22/04 Boiler 276.7 GCP 0.140Footnotes“GCP” means good combustion practices. “OC” means oxidation catalyst.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

- 21 - 

## 3.3 STEP 2. Identify Technical ly 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 emission s 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 susceptibl e to poisoning from sulfur and calcium bearing compounds. These catalysts may experience deactivation a nd 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 + O 2 → 2CO 2 Typical excess oxygen (O 2 ) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in natural gas-fired boilers. These low excess O 2 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. Therma l 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 oxi dation 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 technica lly feasible CO control technology for these boilers.



### 3.3.3 Good Combustion Practices
Good combustion practices or combustion controls ge nerally 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 efficiencyWe 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

- 22 - and reduce the highest single operating cost of a utility boiler: FUEL. A fourth critical parameter is the level of oxygen in the boiler, referre d to as the excess air or excess oxygen level. Therefore, combustion control is accomplished primarily thro ugh 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 mi nimize formation of CO and NO x emissions. This is a difficult task, since emissions of NO x and emissions of CO are inversely related. That is, measures used to reduce NO x emissions often lead to increases in CO emission s. Therefore, the boiler design to minimize CO emissions is interrelated with the boiler design to minimize NO x formation.



## 3.4 STEP 3. Rank the Technica lly Feasible Control Technologies.

Based on the above analysis, the technically feasibl e CO control technologies for these natural gas-fired boilers includes good combustion practices based on the use of the ultra low NO x 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 Cata lyst 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 co uld 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 oxi dation 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 w ould include the capital costs for the catalyst and ancillary equipment, labor, auxiliary power requ irements, 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 equi pment cost of $105,000 per boiler, and a total capitalWe 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

- 23 - requirement of $210,000. From Table 3-2, the oxidati on catalyst system is expected to have an annual cost of $136,100 for each boiler. The oxidation cat alyst systems would reduce CO emissions by 16.3 tons. Based on these costs, the oxidation catalyst syst ems would have an average cost effectiveness of $8,360 per ton of CO removed.

TABLE 3-2. Oxidation catalyst control syst em 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 cat alyst 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 SFFWe 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

- 24 - 

### 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 th e control of CO emissions on these natural gas-fired boilers is not an economically feasible control option.
Numerous regulatory agencies have made determinati ons regarding the cost effectiveness of oxidation catalysts on combustion turbines and have rejected th is technology as economically infeasible at costs as low as $1,700 per ton of CO removed. These determ inations include the South Carolina Santee Cooper Rainey Generating Station, $1,717 per ton; Mississi ppi 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 in formation 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 co rresponds to an estimated lifetime of 2.5 months.” Therefore, emissions of CO from this facility will eventually become CO 2 on their own and an oxidation catalyst to sp eed the process is unn ecessary in the absence of ambient impact concerns.
2. Ambient impacts are negligible. The air di spersion modeling performed for the facility predicts ambient impacts that are classi fied as insignificant under the Federal Prevention of Significant Deterioration regul ations. 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 bo ilers 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 tota l 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 am bient 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.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

- 25 - 

### 3.5.2 Rank No. 2: Good Combustion Practices.
The use of package boilers with Ultra Low NO x 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 th at the use of good combustion practices represents the best available control technology (BACT) for the c ontrol of CO emissions from these natural gas-fired package boilers. Based on this analysis, We En ergies 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.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

- 26 - 

# Chapter 4. Nitrogen Oxides (NO x 

# ) Control Technology Review.

Nitrogen oxides (NO x ) consist of several compounds, including nitrogen oxide (NO), and nitrogen dioxide (NO 2 ). During combustion, NO usually accounts for more than 90% of the total NO x emissions. However, since NO is subsequently converted to NO 2 in the atmosphere, the mass emission rate of NO x are normally reported as NO 2 . NO x is formed during combustion by two major mech anisms; thermal formation, called “Thermal NO x ”, and fuel formation, called “Fuel NO x ”. Thermal NO x results from the high temperature oxidation of nitrogen (N 2 ) and oxygen (O 2 ). Thermal NO x formation is influenced by th e flue gas residence time and excess oxygen, but, as its name implies, thermal NO x formation is primarily influenced by temperature. Thermal NO x formation increases exponentially with te mperature, and becomes significant at temperatures above 2800 °F. Fuel NO x results from the oxidation of organic nitrogen compounds in the fuel. Fuel bound nitrogen is more easily converted to NO x during combustion. F uel NO x may account for up to 80% of the total NO x emissions, especially from solid fuel combustion.



## 4.1 BACT Baseline.

The proposed natural gas-fired boilers would be subj ect to the Standards of Pe rformance for IndustrialCommercial-Institutional Steam Gene rating Units under 40 CFR Part 60, Subpart Db, and NR 440.205, Wis. Adm. Code. This subpart applies to st eam 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 NO x standards in Subpart Db are specified by the type of fuel combusted. In NR 440.205(5)(a), the
NO x 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-ft 3 , a high heat release rate. Compliance with the NO x 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 in stall a continuous monitoring system for NO x or can use operating conditions to predict emission s in accordance with 40 CFR 60.48b(g).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

- 27 - 

## 4.2 STEP 1. Identify All Po tential Control Strategies.

Table 4-1 summarizes the NO x 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 NO x emissions from boilers: combustion controls and post-combusti on controls. Combustion NO x control techniques use technologies such as low
NO x burners, and/or overfire air to control residence time, oxygen, and combustion temperature to limit
NO x formation. Post combustion NO x control systems are designed to reduce emissions after NO x has been created. The most common secondary control t echnique involves the injection of ammonia or urea into the flue gas to reduce NO x to nitrogen and water. When inject ed upstream of a catalyst, this process is called Selective Catalytic Reduction (SCR); when in jected without a catalyst, this process is called Selective Non-Catalytic Reduction (SNCR). Combus tion and post combustion controls may be used together to achieve the lowest emission rates.
The following NO x control technologies were identified in a review of potential controls:

Combustion Controls • Low NO x 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.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix B: Control Technology Review for the Natural Gas-Fired Boilers.March, 2010-28 -TABLE 4-1. Natural gas-fired boiler nitrogen oxides (NOx) emission limits representing BACT from the U.S. EPA's RBLC database.RBLC IDFacilityPermit DateProcessThruput,mmBtu/hrControlsLimit,lb/mmBtuLA-0229 Shintech Plaquemine Plant 2 07/10/08 Utility Boilers 250 LNB, SCR 0.010TX-0499 Sandy Creek Energy Station 07/24/06 Auxiliary Boiler 175 0.010OR-0046 Calpine Turner Energy Center 01/06/05 Auxiliary Boiler SCR 0.011PA-0193 Merck and Company - West Point Plant 08/26/99 Boilers, (2) 249 LNB, FGR, and SCR 0.012*ID-0017 Southeast Idaho Advanced Energy Center 02/10/09 Package Boiler 250 LNB, FGR 0.020MN-0076 Blandin Paper/Rapids Energy Center 09/18/08 Boiler 280 LNB, FGR 0.035*AL-0230 Thyssenkrupp Steel and Stainless 08/17/07 3 Boilers 65 ULNB, FGR 0.035NJ-0036 AES Red Oak, LLC 10/24/01 Auxiliary Boiler 120 Limit to 3,600 h/yr 0.036IN-0085 PSEG Lawrenceburg Energy Facility06/07/01 Auxiliary Boiler 125 LNB 0.036AR-0026 Pine Bluff Energy Center 05/05/99 Boiler 362 LNB, FGR, GCP 0.037CO-0052 Rocky Mountain Energy Center 08/11/02Auxiliary Boiler 129 LNB, 1,900 h/yr 0.038MN-0062 Heartland Corn Products 12/22/05 Boiler 198 0.040ID-0015 J R Simplot Company - Don Siding Plant 04/05/04 Boiler 175 LNB 0.040TX-0411 Calpine Amelia Energy Center 03/26/02 Auxiliary Boiler 155 0.040SC-0049 Skygen Broad River Energy 12/02/99Utility Boilers 230 LNB, FGR, GCP 0.040ID-0015 J R Simplot Company - Don Siding Plant 04/05/04 Boiler 64 LNB 0.045NE-0024 Cargill - Blair Plant 06/22/04 Boiler 277 LNB, FGR 0.050IA-0050 Cargill - Eddyville 04/22/99 Boiler 7 182 LNB, FGR 0.050AL-0128 Alabama Power - Theodore Cogeneration 03/16/99 Boiler 220 LNB, FGR 0.053FL-0251 Okeelanta Corporation Sugar Mill 10/29/01 Boiler 211 LNB, FGR, GCP 0.060NE-0024 Cargill - Blair Plant 06/22/04 Boilers A, B & C 198 LNB, FGR 0.070LA-0183 Louisiana Pigment Co. Titanium DioxideFacility 11/14/03 Utility Boilers 135 LNB, GCP 0.074WI-0204 UWGP - Fuel Grade Ethanol Plant 08/14/03 Boiler /Oxidizer 140 GCP 0.095WV-0023 Maidsville Longview Power, LLC 03/02/04 Auxiliary Boiler 225 LNB, GCP 0.098WI-0228 Wisconsin Public Service - Weston Plant 10/19/04 Auxiliary Boiler 230 LNB, GCP 0.100VA-0270 Virginia Commonwealth University East Plant 03/31/03 Boiler 150 LNB, FGR, GCP 0.100Footnotes“GCP” means good combustion practices. “SCR” means selective catalytic reduction.“LNB” means low NOx burner. “ULNB” means ultra-low NOx burner.“FGR” means flue gas recirculation.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

- 29 - 

## 4.3 STEP 2. Identify Technical ly Feasible Control Technologies.

There are two key concepts in determining the feasi bility of potential control technologies: “availability” and “applicability.” A technology is considered “av ailable” if it can be obtained commercially, has completed a commercial demonstration, and has reach ed 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 prop osed source. In determining the feasibility of a given technology controlling to a given emission rate th ere is a third concept, “demonstrate d in practice.” A control rate or emission rate is “demonstrated in practice” if a un it with similar operating conditions has continuously.



### 4.3.1 Low NO X 

### Burners and Overfire Air.

Low NO x 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 NO x burners reduce NO x emissions by staging the combustion process. Stagi ng slows down the combustion process, resulting in cooler flame temperatures which suppresses thermal NO x formation.

Low NO x burners are designed to control fuel and air mi xing at the burner in order to create larger flame patterns. This reduces the peak flame te mperature and results in lower thermal NO x formation. The modified flame structure also reduces the amount of ox ygen available in the hottest part of the flame, improving burner efficiency. Primary combustion, NO x reduction and fuel burnout are accomplished in three stages in a modern, LNB equipped boiler:

1. The first stage is a fuel rich zone wher e oxygen levels are maintained below the stoichiometric requirement to complete combustion. Most NO x is formed in this zone.

2. The second stage is a reducing zone where unburned hydrocarbon radicals reduce the NO x formed in the first stage.

3. In the third stage, overfire air comple tes combustion, but produces additional NO x . The NO x formation is minimized by completing combustion in an air-lean environment.

Some LNBs include the installation of over-fire air por ts 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 NO x burners are an available and highly effective NO x control technology for these natural gas-fired boilers. These burners are capable of limiting NO x emissions to approximately 9 parts per million (ppm). A typical, modern ultra low NO x burner for natural gas and distillate fuel oil combustion is shown in Figure 4-1.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

- 30 - FIGURE 4-1. A typical, modern ultra-low NO x 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 NO x burners. A portion of the combustion air is redirected from th e LNB to a higher elevation in the furnace to reduce peak flame temperatures by reducing the concentra tion 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 NO x that was formed near the burner. The ove rfire air creates an oxidation zone to complete combustion. NO x 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 NO x 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 primar y 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 NO x that was formed near the burner. This oxygen depleted zone also reduces the peak flame temperatures which minimizes NO x formation.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

- 31 - 

### 4.3.4 Oxygen-Enhanced Combustion.
Oxygen-Enhanced Combustion (OEC) is a combus tion control technology aimed at reducing the formation of thermal NO x . Praxair Technology, Inc. has develope d a method of using oxygen to achieve additional NO x reduction from low NO x burners on pulverized coal-fired boilers. Field tests were conducted at the James River Power Station Unit 3, a wa ll-fired boiler. In pilot- and full-scale testing,
NO x emissions were reduced by as much as 60%, to le vels below 0.15 lb/mmBtu, when a small portion of low-NO x burner combustion air was replaced with locally injected oxygen.
We are not aware of the use of OEC on natural g as-fired boilers. Because there is no operational experience with OEC on these boilers, and because the a pplication 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 NO x control techniques used primarily for reducing NO x 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 sec ond flame zone, generating chemically reducing conditions that destroy NO x in the primary combustion zone. In la rge utility pulverized coal-fired boilers, fuel reburning is conducted betw een 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 problem s can occur which can damage the boiler.
At least five utility coal-fired demons trations of reburn are in different levels of operation. In the best applications, reburning may reduce NO x emissions to 0.15 lb/mmBtu. However, to be effective in reducing NO x emissions, reburning requires a large furnace vol ume to adequately stage combustion. This natural gas and/or coal reburning process is not applicab le to natural gas-fired boilers. Therefore, natural gas and coal reburning are not t echnically feasible control options.



### 4.3.6 Selective Catalytic Reduction.
Selective Catalytic Reduction (SCR) is a post combustion NO x control system which consists of an ammonia (NH 3 ) injection system and a catalytic reactor. Ur ea can be decomposed in an external reactor to form ammonia for use in an SCR. The ammonia in jection grid is located upstream of the catalyst. Ammonia reacts with NO x and O 2 in the presence of the catalyst to form molecular nitrogen (N 2 ) and water according to the following general equations:

4NH 3 + 4NO + O 2 → 4N 2 + 6H 2 O 4NH 3 + 2NO 2 + O 2 → 3N 2 + 6H 2 O 2NH 3 + NO + NO 2 → 2N 2 + 3H 2 O

This process is called “selective” because ammonia reacts preferentially with NO x in the flue gas in the presence of a catalyst. A catalyst is used to enhance NO x reduction and ammonia utilization. The most common catalyst is a vanadium-based material supporte d on a honeycomb substrate that is installed inWe 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

- 32 - multiple layers in the catalytic reactor. Secondary reac tions also occur in the presence of the SCR catalyst, including the oxidation of SO 2 to SO 3 and the oxidation of elemental mercury.
Based on this review, SCR is a technically feasibl e 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(NH 2 ) 2 ] or ammonia [NH 3 ], reacts with NO x , forming elemental nitrogen [N 2 ] and water without the need for a catalyst. The overall NO x reduction reactions are similar to those for the SCR systems. Multiple injection points are required to thoroughly mi x the reagent in the boiler furnace. The limiting factor for a SNCR system is the ability to contact the NO x with the reagent as the concentration decreases without resulting in excessive ammonia slip, and without excessive ammonia decomposition before the
NO x emissions can be reduced.
SNCR has been widely used in fluidized bed boile rs where the high alkaline ash loading of the CFB boilers makes ‘high dust’ loading SCR systems technica lly infeasible. SNCR has also been widely used in modern stoker boilers. However, SNCR is not appr opriate for use in package natural gas-fired boilers, since the short residence time does not allo w for adequate reaction time to reduce NO x 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 a pplied in combustion turbine applications. ABB Alstom Power purchased a proprietary technology called SCONOxTM from Goal Line Environmental Technologies. A SCONOx system has been in opera tion 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 cogenerati on 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 cat alytic oxidation and absorption technology. In operation, NO and CO are first oxidized to NO 2 and CO 2 . Next, NO 2 is adsorbed onto an adsorption media. When the media is saturated, NO 2 is desorbed and treated by the proprietary catalyst. Because the operation of SCONOx to oxidize CO to CO 2 is identical to the simple use of an oxidation catalyst, there is effectively no difference between SCONOx and an oxida tion catalyst in terms of CO and VOC control. Therefore, SCONOx and an oxidation catalyst are eff ectively 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 fo r 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.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

- 33 - 

### 4.3.9 Emerging Control Technologies.
Emerging technologies to reduce NO x 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 NO x 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 ad vanced process is the ECO system. ECOTM is an emerging post-combustion multi-pollutant control technology including NO X control and has demonstrated performance, reliability and economics th rough 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 NO x control technologies include NOxStar and Cascade. NOxStar is a hydrocarbo n enhanced SNCR system that injects hydrocarbons downstream of an SNCR system to produce radicals that will further reduce NO x 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 commerc ial operation, these emerging control technologies are not technically feasible for NO x control for these boilers.



### 4.3.10 Summary of the Tec hnically Feasible Controls.
Table 4-2 is a summary of the technical feasibility of the NO x controls for the proposed natural gas-fired boilers.

TABLE 4-2. Summary of the technical feasibility of retrofit NO x control technologies.

Technology Technical Feasibility

Low NO x 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.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

- 34 - 

## 4.4 STEP 3. Rank the Technica lly Feasible Control Technologies.

Table 4-3 is a summary of the ranking of the technically feasible NO x control technologies for the proposed natural gas-fired boilers. While SCR systems can be designed to reduce NO x 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 NO x emissions to 0.01 lb/mmBtu, or a NO x emission rate of 7 parts per milli on (ppm) at 5% excess oxygen.

TABLE 4-3. Ranking of the technicall y feasible NOx control technologies.

Control System Expected Emission Rate, lb/mmBtu Package Boiler with Ultra Low NO x Burners, Overfire Air, and Flue Gas Recirculation, and Selective Catalytic Reduction 0.01

Package Boiler with Ultra Low NO x 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 NO x emission rate of 0.01 lb/mmBtu fo r these natural gas-fired boilers. Based on limiting the operation of each boiler to 6, 200 hours per year, the SCR system could reduce NO x emissions from 10.9 tons per year for the boiler with ultra low NO x 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 NO x emissions. The use of SCR would also have adverse environm ental 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 PM 2.5 .


### 4.5.1.2 Energy Impacts.
Energy impacts from the use of SCR would include th e increased electric energy required for the induced draft fans overcome the increase in pressure drop across the SCR system.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

- 35 - TABLE 4-4. Estimated SCR NO x control system costs for ea ch 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 NO x Emissions, ton/yr 10.9 Moles ammonia per mole NO x 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 cat alyst 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 SFFWe 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

- 36 - 

### 4.5.1.3 Economic Impacts.

The costs for SCR controls on these boilers would in clude the capital costs for the SCR and ancillary equipment, labor, auxiliary power requirements, ammonia, catalyst replacement, maintenance, and administrative costs. The SCR cost an alysis 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 NO x 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 NO x removed.



### 4.5.1.4 Conclusion.
The use of SCR on these natural gas-fi red package boilers can achieve NO x 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 NO x emissions from each boiler by 5.4 tons per year, resulting in an average cost effectiveness of $45,800 per ton of NO x removed. These costs are very high, indicating that the use of SCR on these natura l gas-fired boilers is not an economically feasible control option.



### 4.5.2 Rank No. 2: Package Boiler with Ultra Low NO x 

### Burners.
The use of package boilers with Ultra Low NO x Burners, Overfire Air, and Flue Gas Recirculation can achieve a NO x emission rate of 0.02 lb/mmBtu.



## 4.6 STEP 5. Proposed Nitrog en Oxide BACT Determination.

Based on this analysis, We Energies has concluded th at the use of package boilers with Ultra Low NO x Burners, Overfire Air, and Flue Gas Recirculation is the best available control technology (BACT) for
NO x 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 NO x emissions from these boilers.

(1) Nitrogen oxide (NO x ) emissions from the natural gas-fired boilers B02 and B03 shall be controlled using Ultra Low NO x Burners, Overfire Air, and Flue Gas Recirculation as the best available control technology.
(2) Nitrogen oxide (NO x ) 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.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

- 37 - 

# Chapter 5. Particulate Matter and PM 10 

# Control Technology Review.

Particulate matter (PM) emissions from natural gas-fire d-fired boilers originate from ash in the fuel, and from products of incomplete. In Wisconsin, “par ticulate 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 ma terials. 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 exis ts 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 th e 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 constr uction, modification, or reconstruc tion after June 19, 1984, and that has a heat input capacity from fuels combusted in th e steam generating unit greater than 100 mmBtu/hr. The only NSPS PM standard that is applicable to simila r 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 o il 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 Poten tial 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/LA ER 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 ra tes were converted to lb/mmBtu to make the emission limits comparable.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix B: Control Technology Review for the Natural Gas-Fired Boilers.March, 2010-38 -TABLE 5-1. Natural gas-fired boiler particulate matter emissionlimits representing BACT from the U.S. EPA's RBLC database.RBLC IDFacilityPermit DateProcessThruput,mmBtu/hrControlsLimit,lb/mmBtuWV-0023 Longview Power, LLC - Maidsville 03/02/04 Auxiliary Boiler 225 GCP, Clean Fuels 0.0022OR-0040 Klamath Generation, LLC 03/12/03 Auxiliary Boiler 0.0042AR-0026 Pine Bluff Energy LLC-Pine Bluff Energy Center 05/05/99 Boiler 362 GCP, Clean Fuels 0.0050AR-0057 Tenaska Arkansas Partners, LP 10/09/01 Boiler 122 GCP 0.0050TX-0499 Sandy Creek Energy Station 07/24/06 Auxiliary Boiler 175 0.0050*ID-0017 SE Idaho Power County Energy Center 02/10/09 Package Boiler 250 GCP 0.0052NJ-0042 Roche Vitamins 02/05/99 Boiler 134 None Listed 0.0052NJ-0036 AES Red Oak, LLC 10/24/01 Auxiliary Boiler 120 GCP 0.0066TX-0414 Atofina Petrochemicals Port Arthur Complex 04/22/99 Supplement Boiler 227 Low Ash Fuel 0.0070OK-0045 Redbud Power Plant 08/15/01 Auxiliary Boiler 20 Low Ash Fuel, GCP 0.0074NC-0101 Forsyth Energy Plant 09/29/05 Auxiliary Boiler 110 LNB, GCP 0.0074IN-0085 PSEG Lawrenceburg Energy Facility 06/07/01 Auxiliary Boiler 125 GCP 0.0074WI-0228 Wisconsin Public Service - Weston Plant 10/19/04 Auxiliary Boiler 230 GCP, Natural Gas 0.0075TN-0153 Williams Refining & Marketing, LLC 04/03/02 Boiler 180 0.0075OH-0310 American Municipal Power Generating Station 02/07/08 Auxiliary Boiler 150 0.0076*AL-0230 Thyssenkrupp Steel & Stainless USA, LLC 08/17/07 3 Boilers 65 ULNB, FGR 0.0076MS-0069 Dupont Delisle Facility 06/08/04 Boiler 231 Natural Gas 0.0076VA-0278 Virginia Commonwealth University East Plant 03/31/03 3 Boilers 151 0.0080AL-0128 Alabama Power Co. - Theodore Cogeneration 03/16/99 Boiler 220 Natural Gas 0.0080VA-0270 Virginia Commonwealth University East Plant 03/31/03 Boiler 150 GCP 0.0080NJ-0043 Liberty Generating Station 03/28/02 Auxiliary Boiler 200 0.0080MN-0039 Minnesota Corn Processors 08/08/00 Boiler 237 Natural Gas Only 0.0084AR-0070 Genova Arkansas I, LLC 08/23/02 Auxiliary Boiler 33 GCP 0.0120NJ-0042 Roche Vitamins 02/05/99 Boiler 84 0.0142TX-0386 Calpine Amella Energy Center 03/26/02 Auxiliary Boiler 155 0.0208WI-0204 United Wisconsin Grain Producers- Ethanol Plant 08/14/03 Boiler 140 0.0393NJ-0042 Roche Vitamins 02/05/99 Boiler 118 None Listed 0.0864Footnotes“GCP” means good combustion practices. “SCR” means selective catalytic reduction.“LNB” means low NOx burner. “ULNB” means ultra-low NOx burner.“FGR” means flue gas recirculation.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

- 39 - 

## 5.3 STEP 2. Identify Technical ly 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 combus tion practices and the use of clean fuels including natural gas. Other PM controls include fabric filte r 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 mechan ism to clean accumulated PM from the bags, and a hopper to collect accumulated ash. Baghouses are compar tmentalized to facilitate cleaning and to provide for maintenance and repair. When the pressure drop across a compartment incr eases 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 part iculate filtration performance of the baghouse. For woven filter media, the filter cake is actually the prim ary control mechanism. Pa rticles 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 (SO 2 ), sulfuric acid mist, and hazardous air pollutants including mercury, hydrogen chloride (HCl), and hydrogen fluoride (H F). 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 re verse 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 met hod 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 fo r PM control from coal-fired boilers, including high particulate matter control efficiencies which are larg ely independent of fuel characteristics, relatively constant outlet grain loading over the entire boiler lo ad range, and simple opera tion 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 r esulting increased fan power requirements.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

- 40 - 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 se ries of fields which consist of negatively charged discharge electrodes and positively charged collection pl ates. The discharge electrodes impart a negative charge to particles in the gas stream. The negati vely 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 resistivity 1 conditions. Most modern

1 Gas composition, temperature, and particle compos ition all influence resistivity, which is a measure of the ability of a particle to retain an electrostatic char ge. The ability to collect particles using electrostaticWe 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

- 41 - ESPs are cold-side ESPs. Factors affecting the PM coll ection 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 (SO 3 ) injection system to condition the ash and reduce pa rticulate resistivity. In addition, modern ESP controls allow the ESP operation to be optimized to maximize PM control through overall ESP performance management, power optimization, a nd 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 g as, 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 flus hed with water to remove collected materials.
Although wet ESPs can be effective for removing su lfuric acid mist downstream of a wet FGD when firing high sulfur coals, wet ESPs have not b een 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 conde nsation, 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 feasibl e 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.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

- 42 - 

## 5.4 STEP 3. Rank the Technically Feasible Technologies.

All of the identified PM control technologies, incl uding fabric filter baghou ses, 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 require d as BACT for new or modified natural gas -fired boilers. This is because natural gas has almost no iner t materials or ash, so that the “uncontrolled” PM and PM 10 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 contro l technologies are expected to achieve emission rates lower than the use of natural gas fuel and good co mbustion 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 PM 10 emissions.



## 5.5 STEP 4. Evaluate the Most Effective Controls.

The combustion of only natural gas is expected to ach ieve an emission rate of 0.0076 lb/mmBtu for both PM and PM 10 . This is the highest ranked level of control.



## 5.6 STEP 5. Proposed Partic ulate 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 PM 10 emissions from the natural gas-fired boilers B02 and B03. Based on th is analysis, We Energies proposes the following limits as BACT for the control of PM and PM 10 emissions from these boilers.

(1) Particulate matter and PM 10 emissions from the natural gas-fired boilers B02 and B03 shall be controlled using Ultra Low NO x Burners, Overfire Air, and Flue Gas Recirculation as the best available control technology.
(2) Particulate matter and PM 10 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.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

- 43 - 

# Chapter 6. PM 2.5 

# Control Technology Review.

Particulate matter emissions that are less than 2.5 mi crometers in diameter are known as "fine" particles, and are referred to as PM 2.5 . Various pollutants contribute to ambient PM 2.5 concentrations. Fuel combustion, including natural gas, result in direct emissions of PM 2.5 . In addition, PM 2.5 “precursors” can also result in the formation of PM 2.5 in the atmosphere. The U.S. EPA has identified SO 2 , NO x , volatile organic compounds (VOC s), and ammonia (NH 3 ) as PM 2.5 precursors. These gas-phase precursors undergo chemical reactions in the atmosphere to form secondary PM 2.5 . Direct emissions of PM 2.5 from combustion includes solid or filterable PM 2.5 , and condensable or back half PM 2.5 . Under the recently promulgated rules to revise the New Source Review (NSR) program in 40 CFR Part 52 to include PM 2.5 , the EPA identified the following PM 2.5 pollutants, and their significant levels:

1. 10 ton per year of direct PM 2.5 emissions 2. 40 ton per year of SO 2 emissions 3. 40 ton per year of NO x emissions unless demonstrated not to be a PM 2.5 precursor.

Based on the final rules, VOC and ammonia may not be considered to be precursors to PM 2.5 unless the state demonstrates that these emissions are a significant contributor to the area PM 2.5 concentrations. In addition, during the PM 2.5 SIP development period, the EPA has indicated that NO x emissions will not be regulated as a PM 2.5 precursor to give States the opportunity to determine whether NO x emissions are a significant contributor to the ambient PM 2.5 concentration 2

.


## 6.1 BACT Baseline.

There are no state implementation plan emission limits or new source performance standards for direct
PM 2.5 emissions from these natural gas-fired boilers.

Direct PM 2.5 emissions from the combustion of natural gas include filterable PM 2.5 , and condensable
PM 2.5 . 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 conden sable PM emissions. The total filterable plus condensable emission factor is 7.6 lb/10 6 scf natural gas, equal to 0.0076 lb/mmBtu. For this analysis, all PM emissions from natural gas combustion are also expected to be PM 2.5 .

2 Federal Register / Vol. 73, No. 96 / Friday, May 16, 2008, page 28343.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

- 44 - 

## 6.2 STEP 1. Identify All Po tential Control Technologies.

6.2.1 Direct PM 2.5 

### Emissions.

As noted in the PM and PM 10 control technology review, the technologies selected as BACT include primarily fabric filter baghouses and electrostatic pr ecipitators. Other controls include mechanical collectors such as multicyclones, and wet venturi scrubbers.



### 6.2.2 PM 2.5 

### Precursors.

As noted above, the U.S. EPA has identified SO 2 , NO x , VOCs, and ammonia (NH 3 ) as PM 2.5 precursors. Based on the final rules, volatile organic compounds (VOC) and ammonia (NH 3 ) may not be considered to be precursors to PM 2.5 unless the State demonstrates that these emissions are a significant contributor to the area PM 2.5 concentrations. This control technology re view includes a complete control technology review for SO 2 , NO x , and VOC emissions. Therefore, further analysis of these pollutants as PM 2.5 precursors is unnecessary.


## 6.3 STEP 2. Identify Technical ly Feasible Control Technologies.

As noted above, data from the U.S. EPA’s RBLC indi cate that the technologies sel ected as BACT include primarily fabric filter baghouses and electrostatic pr ecipitators. 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/PM 10 control technology re view. 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 emissi ons versus the particle size for several different PM control systems for coal combustion 3 . Figure 6-1 shows that fabric filter baghouses are very effective in reducing PM emissions, especially fine PM.

As noted in the PM/PM 10 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 (SO 2 ), sulfuric acid mist, mercury and hazardous air pollutants including hydroge n 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 PM 2.5 emissions by controlling these PM 2.5 precursors in the baghouse. However, b ecause 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.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

- 45 - 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, umCummulative Emission Factor, lb/ton Multiple Cyclones

Electrostatic Precipitator

Fabric Filter Baghouse



### 6.3.1.1 Filter Media for Fa bric Filter Baghouses and PM 2.5 

### 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 wove n 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 PM 2.5 control. Advanced filter media provide enhanced PM 2.5 emissions control. The U.S. EPA im plemented 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 report 4 , “New fabrics have been developed that offer the combination of highly effective particulate rem oval and low operational pressure drop. Improving performance of the fabrics can be observed in verificati on 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 Medi a 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, Pres ented at the Air & Waste Management Association Annual Conference, June, 2008, available at: http://epa.gov/etv/pubs/600etv08023.pdf

.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

- 46 - http://www.epa.gov/nrmrl/std/etv/vt-apc.html . ETV test results indicate filter media with direct PM 2.5 emission levels as low as 0.000007 gr/dscf, equal to approximately 0.0001 lb/mmBtu. Note, however, that this is the tested performan ce for the filter media, not for th e entire baghouse system. Leaks which occur in even the best state-of-the-art baghouse will increase the outlet grain lo ading, even when using advanced filter media.
Baghouse filtration product enhancements include fe lted 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 gene rally 2 to 3 times thicker than woven filters. This thicker overall filter improves fine pa rticle collection, since each individual randomly oriented fiber acts as a target for particle capture by impaction and in terception. Small particles are collected on the outer surface of the filter, rather than depending on the filter ca ke to achieve fine particle control. Figure 6-2 is a depiction of the fabric filter media filtration pro cess 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 contro l. The U.S. EPA’s ETV program tested outlet PM 2.5 levels as low as 0.0004 gr/dscf (0.00055 lb/mmBtu).

FIGURE 6-2. Depiction of the fabric filter medi a 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

.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

- 47 - 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 PM 2.5 control. However, this co ating 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 effectiv eness of the fabric filter baghouse for PM 2.5 precursors and condensable PM 2.5 species by limiting the contact between thes e precursors and solids in the filter cake which would otherwise remove these precursors.

Membrane bags have a polytetrafluoroethylene (PTFE) coatin g 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 PM 2.5 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 PM 2.5 precursors and condensable PM 2.5 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 contro l. The U.S. EPA’s ETV program tested outlet PM 2.5 levels as low as 0.0004 gr/dscf (0.00055 lb/mmBtu).

Electrostatic fabric filter baghouses have been developed through a pa rtnership of the U.S. EPA and Southern Research Institute. The technology is license d 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 th e 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 volta ge 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 hi gher than those achieved by either the best fabric filters or precipitators currently on the mark et, 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 conducte d pilot testing of a slip stream at a major power plant in the Southern United Stat es. The pilot plant was configured to allow testing with or without discharge electrode energization. With the electrost atic stimulation turned on, collection efficiency increased from 99.99% to 99.999%, a full order of magn itude 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

.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

- 48 - 

### 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/PM 10 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 PM 2.5 emissions, and also for PM 2.5 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 natu ral 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
PM 2.5 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 s lipstream 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 PM 2.5 and
SO 3 mist removal as a potential control technology to reduce visible emissions. The slipstream results indicate reductions in PM 2.5 emissions from 62% to 96%. These results also showed similar high SO 3 mist removal, which may account for much of the PM 2.5 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 conde nsation, 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 techni cally feasible BACT alternative, the performance of mechanical collectors is inferior to FFBs and ESPs.


## 6.4 STEP 3. Rank the Technically Feasible Technologies.

Direct PM 2.5 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-fi red boiler. Further, because of the very low expected PM 2.5 emission rates from the combustion of natural ga s, there is no basis to conclude that postWe 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

- 49 - combustion PM controls would actually result in reductions in PM 2.5 emissions. Therefore, the highest ranked or most effective PM 2.5 control technology for these natural g as-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 u se of natural gas fuel and good combustion practices designed to minimize products of incomplete combustion is expected to achieve a PM 2.5 emission rate of 0.0076 lb/mmBtu. The use of additional add on contro ls will not reduce emissions below these levels.



## 6.6 STEP 5. Proposed PM 2.5 

## 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 PM 2.5 emissions from the natural gasfired boilers B02 and B03. Based on this analys is, We Energies proposes the following limits as BACT for the control of PM and PM 10 emissions from these boilers.

(1) PM 2.5 emissions from the natural gas-fired boilers B02 and B03 shall be controlled using Ultra Low NO x Burners, Overfire Air, and Flue Gas Recirculation as the best available control technology.
(2) PM 2.5 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.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

- 50 - 

# Chapter 7. Sulfur Dioxide (SO 2 

# ) Control Technology Review.

Sulfur dioxide (SO 2 ) 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 SO 2 . A small portion of the sulfur is further oxidized to sulfur trioxide (SO 3 ). When the flue gas temperature drops below the dew point temperature, sulfur trioxide is converted to sulfuric acid (H 2 SO 4 ). Therefore, control technologies which control SO 2 emissions also reduce sulfuric acid mist emissions to varying degrees.



## 7.1 BACT Baseline.

The proposed natural gas-fired boilers would be subj ect to the Standards of Pe rformance for IndustrialCommercial-Institutional Steam Gene rating Units under 40 CFR Part 60, Subpart Db. This subpart applies to units that commence construction, modificati on, or reconstruction after June 19, 1984, and have a heat input from fuels combusted in the steam ge nerating unit greater than 100 mmBtu/hr. The SO 2 standards in Subpart Db are only applicable when di stillate 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, SO 2 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 SO 2 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 ope rate continuous monitors for SO 2 if fuel receipts are maintained.
Because these boilers will fire only natu ral gas, there are no applicable NSPS SO 2 standards.


## 7.2 STEP 1. Identify Poten tial Control Technologies.

Potential SO 2 control technologies include pre-combustion c ontrols such as low sulfur fuels, and post combustion controls, such as flue gas desulfurization. Table 7-1 summarizes the SO 2 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 combusti on. Please note that many of the emission limits in these tables were expressed as pounds per hour. These ra tes were converted to lb/mmBtu to make the emission limits comparable.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix B: Control Technology Review for the Natural Gas-Fired Boilers.March, 2010-51 -TABLE 7-1. Natural gas-fired boiler SO2emission limits representing BACT from the U.S. EPA's RBLC database.RBLC IDFacilityPermit DateProcessThruput,mmBtu/hrControlsLimit,lb/mmBtu*AL-0230 Thyssenkrupp Steel & Stainless USA 08/17/07 3 Boilers 65 0.0006OH-0310 American Municipal Power Generating Station 02/07/08 Auxiliary Boiler 150 0.0006WI-0228 Wisconsin Public Service - Weston Plant 10/19/04 Auxiliary Boiler 230 Natural Gas 0.0006OK-0045 Redbud Power Plant 08/15/01 Auxiliary Boiler 20 Pipeline Natural Gas 0.0006AR-0026 Pine Bluff Energy LLC-Pine Bluff Energy Center 05/05/99 Boiler, Natural Gas 362 Low Sulfur Fuels 0.0006TX-0499 Sandy Creek Energy Station 07/24/06 Auxiliary Boiler 175 0.0006NJ-0042 Roche Vitamins 02/05/99 Boiler 3 (Nat Gas) 152 None Listed 0.00066VA-0278 Virginia Commonwealth University East Plant 03/31/03 Boiler 151 Low Sulfur Fuel 0.00066VA-0270 Virginia Commonwealth University East Plant 03/31/03 Boiler 150 Low Sulfur Fuel 0.00067NJ-0042 Roche Vitamins 02/05/99 Boiler 134 None Listed 0.00075NJ-0042 Roche Vitamins 02/05/99 Boiler 118 None Listed 0.00085NJ-0042 Roche Vitamins 02/05/99 Boiler 84 None Listed 0.0012MN-0039 Minnesota Corn Processors 08/08/00 Boiler 237 Natural Gas 0.0017NJ-0043 Liberty Generating Station 03/28/02 Auxiliary Boiler 200 None 0.0040NJ-0036 AES Red Oak LLC 10/24/01 AuxiliaryBoiler 120 Natural Gas Fuel 0.0043TX-0386 Calpine Amella Energy Center 03/26/02 Auxiliary Boiler 155 0.0054NC-0101 Forsyth Energy Plant 09/29/05 Auxiliary Boiler 110 Natural Gas 0.0055IN-0085 PSEG Lawrenceburg Energy Facility 06/07/01 Auxiliary Boiler 125 Natural Gas 0.006AR-0057 Tenaska Arkansas Partners, LP 10/09/01 Boiler 122 Natural Gas. 0.006CA-1024 AES Huntington Beach 08/01/02Boiler: 225 SulfurIn Fuel 0.2OH-0241 Miller Brewing Company - Trenton 05/27/04 Boiler 238 1.6Footnotes“GCP” means good combustion practices. “SCR” means selective catalytic reduction.“LNB” means low NOx burner. “ULNB” means ultra-low NOx burner.“FGR” means flue gas recirculation.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

- 52 - 

## 7.3 STEP 2. Identify Technical ly 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 th e 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 sy stems are not expected to reduce potential SO 2 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 th e use of post-combustion FGD systems designed to
remove SO 2 from the flue gas after combustion. Because SO 2 emissions occur from the oxidation of fuel sulfur, SO 2 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 pr opane) 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 supp lier through a pipeline. Pipeline natural gas contains 0.5 grains or less of total sulfur per 100 standard c ubic feet. Additionally, pipeline natural gas must either be composed of at least 70 percent methane by volu me or have a gross calorific value between 950 and 1100 Btu per standard cubic foot. Ba sed on these values, the uncontrolled SO 2 emission rate of pipeline natural gas is:



### ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= mmBtu 1.0 Btu 1,000,000
Btu 950 NG

scf 1.0
S lb 1.0 SO

lb 2.0
S grains 7,000 S lb 1.0
NG scf 100 S grains 0.5 2 NG 

### ER

ER NG = 0.0015 lb SO 2 /mmBtu

An emission rate of 0.0015 lb/mmBtu is equal to an SO 2 concentration in the flue gas of 0.8 parts per million (ppm) at 5% excess oxygen.

The emission factor for uncontrolled SO 2 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 primar ily used for large utility and industrial coal-fired boilers. FGD systems may be broadly classified as “wet” and “dry” systems. Wet FGD systems areWe 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

- 53 - characterized by low flue gas outlet temperatures, sa turated or wet flue gas conditions, and a wet sludge reaction product which is de watered 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 c onditions 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 te mperatures about 20 to 50 °F above the saturation point, or about 150 o F to 180 o F. 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 G as Desulfurization.
Wet FGD is a well demonstrated technology for the control of SO 2 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 SO 2 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 condensati on that occurs on the downstream ductwork and in the stack. The wet FGD reaction products also require de watering, usually by a combination of hydroclones and vacuum filters. Large areas are needed to mana ge 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 larg ely 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 SO 2 removal. These first wet FGD systems utilized spray tower absorbers, often without a perforated plate tray, as the me thod for contacting the flue gas with the reagent.
FGD systems installed in the 1990’s were 2 nd and 3 rd generation systems which generally achieved greater than 90% SO 2 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 SO 2 removal efficiencies of the 2 nd and 3 rd generation systems wereWe 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

- 54 - improved primarily by improving gas to liquid c ontact. These improvements include absorption trays with perforated plates and multiple levels of interspatial reagent spray nozzles.
FGD system suppliers have introduced several new desi gns 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 impr ove the gas-to-liquid contact by forcing the flue gas to bubble through the liquid reagent using a gas spar ger design rather than spraying the alkaline slurry into the gas stream. Mitsubishi developed the Do uble 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 SO 2 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 (CaSO 3 ). The LSFO process further oxidizes calcium sulfite to calcium sulfate dihydrate (gypsum, or
CaSO 4 ·2H 2 O). The gypsum content of the scrubber sludge is typically 95% on a dry basis, making the sludge easier to dewater. Gypsum is a naturally occu rring mineral that is used as a raw material in the manufacture of plaster, wallboard, Portland cement, ag ricultural 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 consis ting of limestone (calcium carbonate), calcium sulfite, and calcium sulfate is contacted with the flue gas. Through a series of reactions, SO 2 in the flue gas reacts with calcium carbonate to form CaSO 3 . The flue gas exits the abso rption 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 CaSO 4 ·2H 2 O. 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 transpor t offsite. The overall FGD reaction is :

CaCO 3 (s) + SO 2 (g) + 1⁄2O 2 (g) + 2H 2 O → CaSO 4 ·2H 2 O(s) + CO 2 (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 SO 2 control system is also true for the LSFO – as the boiler outlet SO 2 concentration decreases, the ability to achieve high control efficiencies also decreases.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

- 55 - 7.3.2.1.3 Technical Feasibility
WFGD is a well demonstrated technology for the control of SO 2 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 fro m Chiyoda, Alstom, Mitsubishi, and Babcock Power Environmental Inc. are also technically feasible. Ho wever, as noted above, the current wet FGD systems
are 3 rd 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 boile rs either in the U.S. or abroad.



### 7.3.2.2 Dry Flue G as Desulfurization.
Dry FGD is also a well demonstrated technology for the control of SO 2 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 so rbent 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 SO 2 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 (cem entitious) 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 u tility scale low sulfur coal-fired boilers. The LSDA process employs a spray dryer absorber (SDA) a nd a downstream PM control device. The SDA introduces a lime or limestone slurry and flue gas at th e 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 p asses through the absorber, cooling and humidifying the flue gas stream and rapidly drying the slurry to a powde r. In practice, water is added to control the SDA outlet temperature to approximately 155 o F, or an approach temperature approximately 25 o F above the saturation temperature. SO 2 in the flue gas reacts with calcium hydroxide in the reactor or on the fabric filter bags to form solid calcium sulfite (CaSO 3 ) and calcium sulfate (CaSO 4 ):

2Ca(OH) 2 (s) + 2SO 2 (g) + 2H 2 O (g) → 2(CaSO 3 • 2H 2 O) 2Ca(OH) 2 (s) + 2SO 2 (g) + 2H 2 O (g) +O 2 → 2(CaSO 4 • 2H 2 O)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

- 56 - 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 circula ting 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 SO 2 emissions. The ash captured in the baghou se 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 n eed for slurry handling, atomization, and a large reactor. Reinjecting a dry solid also allows the reagen t 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 conventiona l SDA system. These semi-dry FGD systems have demonstrated the ability to achieve SO 2 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 absorber s, circulating fluidized bed systems, hydrated lime injection systems, and flash dryer absorber s, are all demonstrated for the control of SO 2 emissions from coal-fired boilers. While a dry FGD system is t echnically feasible for the natural gas-fired boilers, we are not aware of the use of dry FGD systems on an y 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 ty pes 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 Na 2 CO 3 • NaHCO 3 • 2H 2 O) are injected into the duct upstream of the PM control system. The fly ash, sorbent reaction pr oducts, and unused sorbent are collected in the PM control system. Duct sorbent injection has typical SO 2 removal efficiencies ranging from 40 to 70%.
Furnace sorbent injection is also a dry system. Sorb ents 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 betweenWe 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

- 57 - the air heater and the PM collector for fl ue gas conditioning to promote additional SO 2 removal. The reaction product and fly ash are collected in the PM collection system. In retrofit situations, furnace sorbent injection systems typically achieve SO 2 removal efficiencies of 30-40%.

7.3.2.3.1 Technical Feasibility.
Sorbent injection is technically feasible for the na tural 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 D esulfurization Technologies.
Emerging SO 2 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 syst em 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 inst alled 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 SO 2 and sulfuric acid from the flue gas. The m echanism 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 partic ulate 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 Po wer 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 Ai rborne’s emission control process. The technology would combine a dry sodium bicarbonate injection with enhanced wet sodi um bicarbonate scrubbing. Because the sodium bicarbonate reagent is expensiv e 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 SO 2 and NO x 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 SO 2 emission rates, these processes are not commercial, nor are they demonstrat ed 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 r espect to other advanced technologies, due to the lack of demonstrated performance of these emerging technologies, these technologies are not considered technically feasible SO 2 control options for these boilers.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

- 58 - 

## 7.4 STEP 3. Rank the Technically Feasible Technologies.

Design SO 2 control efficiencies for advanced wet FGD systems are as high as 98% to 99%, down to SO 2 outlet concentrations of approximately 9 ppm or 0.02 lb/mmBtu. Design SO 2 control efficiencies for advanced dry FGD systems are as high as 95% to 98%, down to SO 2 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 c oncentrations. The uncontrolled SO 2 emission rates for natural gas is 0.0006 lb/mmBtu. While flue gas desulfurization syst ems are technically feasible, these controls are not expected to achieve SO 2 emission rates significantly below the uncontrolled SO 2 emission rates for natural gas combustion of approximately 0.4 parts per million at 5% excess O 2 . Therefore, the use of wet FGD and dry FGD in combination with the use of natu ral gas are expected to achieve the same outlet SO 2 emission rate as the use of natural gas only.



## 7.5 STEP 4. Evaluate the Most Effective Controls.

The most effective SO 2 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 SO 2 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 SO 2 emissions from the natural gasfired boilers B02 and B03. Based on this analys is, We Energies proposes the following limits as BACT for the control of PM and PM 10 emissions from these boilers.

(1) Sulfur dioxide (SO 2 ) 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 (SO 2 ) 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.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

- 59 - 

# 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 com bustion can also result in emissions of particulate matter, CO, and organic hazardous air pollutants, a nd 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 oxyg en levels, and longer furnace residence times. Unfortunately, techniques for reduc ing VOC emissions can increase NO x emissions. Consequently, as with CO emissions, achieving low VOC and NO x 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 fo r 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.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix B: Control Technology Review for the Natural Gas-Fired Boilers.March, 2010-60 -TABLE 8-1. Natural gas-fired boiler VOC emission limits representing BACT from the U.S. EPA's RBLC database.RBLC IDFacilityPermit DateProcessThruput,mmBtu/HrControlsLimit,lb/mmBtuNJ-0042 Roche Vitamins 02/05/99 Boiler 152 None Listed 0.0013NJ-0042 Roche Vitamins 02/05/99 Boiler 134 None Listed 0.0015NJ-0042 Roche Vitamins 02/05/99 Boiler 118 None Listed 0.0017AR-0026 Pine Bluff Energy LLC-Pine Bluff Energy Center 05/05/99 Boiler 362 GCP 0.0020NJ-0042 Roche Vitamins 02/05/99 Boiler 84 None Listed 0.0024TX-0499 Sandy Creek Energy Station 07/24/06 Auxiliary Boiler 175 0.0040NJ-0036 AES Red Oak LLC 10/24/01 Auxiliary Boiler 120 GCP 0.0040AR-0057 Tenaska Arkansas Partners, LP 10/09/01 Boiler (2) 122 GCP 0.0040OR-0046 Calpine Turner Energy Center, LLC 01/06/05 Auxiliary Boiler 417904 OC 0.0044MN-0066 Northern States Power Co. - RiversidePlant 05/16/06 Auxiliary Boiler 160 GCP 0.0050OK-0045 Redbud Power Plant 08/15/01 Auxiliary Boiler 20 GCP 0.0050AL-0128 Alabama Power Co. - Theodore Cogeneration 03/16/99 Boiler 220 Efficient Combustion 0.0050*GA-0127 Southern Company Plant Mc Donough 01/07/08 Auxiliary Boilers 200 0.0051NC-0101 Forsyth Energy Plant 09/29/05 Auxiliary Boiler 110 LNB, GCP 0.0054WI-0228 Wisconsin Public Service - Weston Plant 10/19/04 Auxiliary Boiler 230 LNB, GCP 0.0054WV-0023 Longview Power, LLC 03/02/04 Auxiliary Boiler 225 GCP 0.0054IN-0085 PSEG Lawrenceburg Energy Facility 06/07/01 Auxiliary Boiler 125 GCP 0.0054OH-0310 American Municipal Power Generating Station 02/07/08 Auxiliary Boiler 150 0.0055OH-0241 Miller Brewing Company - Trenton 05/27/04 Boiler (2) 238 0.0109VA-0278 Virginia Commonwealth University East Plant 03/31/03 Boiler (3) 151 GCP 0.0139AR-0070 Genova Arkansas I, LLC 08/23/02 Auxiliary Boiler 33 GCP 0.0180TX-0437 Hartburg Power, LP 07/05/02 Auxiliary Boiler 40 GCP 0.0200TX-0386 Calpine Amella Energy Center 03/26/02 Auxiliary Boiler 155 0.0200TN-0089 Proctor & Gamble Manufacturing Company 03/05/01 Utility Boiler 225 0.0240WI-0204 United Wisconsin Grain Producers-Ethanol Plant 08/14/03 Boiler /Oxidizer 140 0.0479NJ-0043 Liberty Generating Station 03/28/02 Auxiliary Boiler 200 OC 50 ppmdvFootnotes“GCP” means good combustion practices. “SCR” means selective catalytic reduction.“LNB” means low NOx burner. “ULNB” means ultra-low NOx burner.“FGR” means flue gas recirculation.“OC” means oxidation catalyst.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

- 61 - 

## 8.3 STEP 2. Identify Technical ly 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 de monstration in reducing VOC emissions from boilers. The CO oxidation catalys ts 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 boile r 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 + O 2 → 2CO 2 Typical excess oxygen (O 2 ) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in natural gas-fired boilers. These low excess O 2 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 eviden ce 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 contro l technology for these boilers.



### 8.3.3 Good Combustion Practices
Good combustion practices or combustion controls ge nerally 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, andWe 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

- 62 - Turbulence . These components of combustion efficiency ar e 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 prim arily 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 NO x emissions. This is a difficult task, since emissions of NO x and emissions of CO (and VOC) are inversely related. That is, measures used to reduce NO x 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 NO x formation.



## 8.4 STEP 3. Rank the Technica lly Feasible Control Technologies.

Based on the above analysis, the technically feasibl e VOC control technologies for these natural gas-fired boilers includes good combustion practices based on the use of the ultra low NO x 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 em issions 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 Cata lyst 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 oxi dation 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 catalys t 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 w ould include the capital costs for the catalyst and ancillary equipment, labor, auxiliary power requ irements, catalyst replacement, maintenance, andWe 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

- 63 - 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 equi pment cost of $105,000 per boiler, and a total capital requirement of $210,000. From Table 8-2, the oxidati on catalyst system is expected to have an annual cost of $136,100 for each boiler. The oxidation cat alyst systems would reduce VOC emissions by 0.8 tons. Based on these costs, the oxidation catalyst syst ems would have an average cost effectiveness of $170,000 per ton of VOC removed.

TABLE 8-2. Oxidation catalyst control syst em 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 cat alyst 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 SFFWe 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

- 64 - 

### 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 NO x 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 th at the use of good combustion practices represents the best available control technology (BACT) for th e 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.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

- 65 - 

# Chapter 9. Fluorides Control Technology Review.

Fluorine (F) is a trace element in natural gas. Wh en 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 (CaF 2 ). Fluoride compounds such as NaF are so lids 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 da tabase 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-fi red 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 gasWe 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

- 66 - 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 i ndicated 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 Technical ly 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 pa rticulate matter control systems, and also acid gas control systems. Tech nologies that may control fluoride emissions include fabric filter baghouses, electrostatic precipitators, we t or dry FGD systems, and sorbent injection.



### 9.3.1 Flue Gas Desulf urization 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 lim e may also reduce emissions of HF. The injection of lime into the flue gas upstream of a fabric filter ba ghouse is well demonstrated to reduce H 2 SO 4 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 lo w levels which occur from the combustion of only natural gas. Therefore, the highest ranked contro l is the combustion of low fluorine containing fuels including natural gas.



## STEP 4. Evaluate the Mo st Effective Controls.

Based on the above analysis, the combustion of lo w 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.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

- 67 - 

## 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 t echnology (BACT) for HF emissions from these natural gas-fired package boilers. Based on this analys is, We Energies proposes the following limits as BACT for the control of fluoride (HF) emissions from the natu ral gas-fired boilers. Th e available data covers a very wide range of potential emission rates. Ther efore, 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 Construc tion Permit Application


# Appendix C. Control Technology Review.

Best Available Control Technology (BACT) Analysis for the Balance of Plant Equipment, including Ma terial 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 E NVIRONMENTAL A SSOCIATES I NC .® 903 Superior Avenue, Suite 6 Tomah, WI 54660We 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

- 2 - 

# Executive Summary

This document is a Control Technology Review for th e balance of plant equipment, including material handling equipment and processes, cooling towers, a nd an emergency diesel engine-driven feed water pump for We Energies’ 50 MW Biomass Fuels Cogene ration 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 a nd two new natural gas-fired package boilers. To support these new boilers, the Plant will require new bi omass 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. Th e 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 PumpWe 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

- 3 - TABLE ES-2. Proposed control technologies a nd 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/PM 10 emissions shall be limited to 0.004 gr/dscf. (3) PM 2.5 emissions shall be limited to 0.002 gr/dscf.

F122 Self Unloading Truck Biomass Fuels Unloading (1) PM/PM 10 , and PM 2.5 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), PM 10 , and PM 2.5 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, PM 10 , and PM 2.5 emissions shall be controlled using a bin vent filter as BACT. (2) PM/PM 10 emissions shall be limited to 0.004 gr/dscf. (3) PM 2.5 emissions shall be limited to 0.002 gr/dscf.

F125 Biomass Fuels Delivery Truck Haul Roads

F133 Boiler Ash Haul Roads (1) PM, PM 10 , and PM 2.5 emissions shall be controlled using paved roadways in combination with a dust suppression system as BACT.

P141 Cooling Tower (1) PM, PM 10 , and PM 2.5 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.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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# Table of Contents

Chapter 1. Introduction and So urces Evaluated.................................................8
Chapter 2. Control Technology Re view Metho dology........................................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 fo r Process P121; Biomass Fuels Material Handlin g Proce sses. ...............................................................................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 Pr ocess F122: Biomass Fuels Self Unloading Truck Unloadin g. ................................................................................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. .................................................................. 22We 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

- 5 - 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 S ilos. ...........................................................................................................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 fo r Process P131, CFB Boiler Bed Material Silo; and Process P 132, 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 technica lly feasible control options............................................................... 33
9.6 Step 3. Rank the technically feasible control options. ................................................................. 33
9.7 Step 4. Evaluate the most effective controls................................................................................ 3 4We 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

- 6 - 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 (NO x ) 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, PM 10 , and PM 2.5 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 (SO 2 ) 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............................................................................ 42We 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

- 7 - 

# Tables

TABLE 3-1. Potential PM control technologies fo r the biomass fuels material handling processes. .......16

TABLE 3-2. Potential emissions for Pr ocesses P121 based on the BACT limits. ....................................17

TABLE 4-1. Potential PM and PM 10 control technologies for Process F123, self-unloading trucks. .......19

TABLE 5-1. Potential PM control technol ogies for Process F124, biomass fuels storage........................22

TABLE 7-1. Potential PM control t echnologies for truck haul roads........................................................26 TABLE 7-2. Fugitive dust emissions from the Biom ass 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 m echanical draft cooling tower, Process P141. .................33 TABLE 9-3. Cooling tower BACT requirement s 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. ............................................................................................... ..........36We 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

- 8 - 

# Chapter 1. Introduction and Sources Evaluated.

This document is a Control Technology Review for th e balance of plant equipment, including material handling equipment and processes, cooling towers, a nd an emergency diesel engine-driven feed water pump for We Energies’ 50 MW Biomass Fuels Cogene ration 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 Fac ility 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 bi omass-fired boiler, and two new natural gas-fired package boilers. To support these new boilers, th e Plant will require new biomass fuel handling equipment, biomass boiler ash handling equipment, a ne w 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 PumpWe 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

- 9 - 

# Chapter 2. Control Technology Review Methodology.

2.1 Best Available Control Technology Definition.

The Clean Air Act and the Prevention of Significant De terioration (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 w ould 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 cost s, determines is achievable for such source or modification through applicati on 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 applicab le 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 re gulation under the Act whic h 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, a nd economic impacts, and other costs, determines is achievable for such source or modification throug h 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 contamin ant. In no event may application of best available control technology result in emissions of any ai r contaminant which would exceed the emissions allowed by any applicable standard under chs. NR 440 and 445 to 449 and un der 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 partic ular emissions unit would make the imposition of an emissions standard infeasible, a design, equi pment, work practice, operational standard or combination thereof, may be prescrib ed instead to satisfy the requireme nt 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 desi gn, equipment, work practice or operation, and shall provide for compliance by means wh ich 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 signi ficant net emissions increase for that pollutant.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

- 10 - Individual BACT determinations are performed on a unit-by-unit, pollutant-by-pollutant basis. This BACT analysis considers potential controls for SO 2 , NO x , PM 10 , 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 technol ogies until a level of cont rol considered BACT is reached, based on the environmental, energy, and eco nomic 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 pr actical potential for app lication to the emission unit and regulated pollutant under evaluation;

2. Eliminate all technically infeasible control technologies;

3. Rank remaining control technologies by effec tiveness 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 associ ated with a control alternative may be considered if dispersion modeling analyses are performed. The en ergy 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 tota l 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 effectiven ess and ultimately, whether the option is economically reasonable. The economic impacts are reviewed on a cost per ton contro lled 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 statutor y 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 provi de the “maximum degree of emissions reduction.” Second, any decision to require a lesser degree of emi ssions 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 contro ls 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 NO x burners on existingWe 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

- 11 - boilers often cannot achieve the same NO x , CO, and VOC emission rates as the use of low NO x burners on a new boiler which has been designed to optimize the low NO x burner design. This can in turn affect the ultimate NO x 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. Retrofitti ng controls on existing boilers can have numerous issues, including site constraints and room for th e new controls, demolition requirements for existing controls, and down time during construction a nd 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 tec hnologies 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 em ployed 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) c ontrols applied to similar source categories and gas streams, and innovative control technologies. Tec hnologies 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 stat es, “Technologies which have not yet been applied to (or permitted for) full scale operations need not be cons idered 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 "demons trated" successfully for the type of emission source under review, then it would normally be considered technically feasible. For an undemonstratedWe 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

- 12 - technology, “availability” and “applic ability” 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 emissi on 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 simila r 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 incremen tal 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 su ccessfully 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:

Control option annualized cost Average Cost Effectiveness ($ per ton removed) = Baseline emission rate – Control option emissions rate

The average cost effectiveness is based on the overa ll reduction in the air pollutant from the baseline emission rate. In the draft Workshop Manual, the EPA states that the baseline emission rate representsWe 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

- 13 - 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 effectiv eness of a control option, the U.S. EPA’s New Source Review Manual states that the incremental cost e ffectiveness between dominant control options should also be calculated. The incremental cost effec tiveness compares the costs and emissions performance level of a control option to those of the next most stringent control option:

Control option annualized cost – Next control option annualized cost Incremental Cost ($ per incremental ton removed) = Next control option emission rate – Control option emissions rateWe 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

- 14 - 

# 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. Th e individual fuel material handling processes or operations will include delivery, un loading, conveying, hogging (shreddi ng), storage, and reclaim. The biomass fuels will be received in a shredded form wh ich 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 dum per, 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 convey ed 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 boile r. After the Hog Building, the fuels will be conveyed to Transfer Tower 2, and then to the Biomass Fuel s Storage Building. This building will have a belt tripper to load the fuels into the building, and a recl aim 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 opera tions, 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 thes e 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 th at 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 Domt ar Mill’s wood room to the Hog Building. The conveying air (if pneumatic) and dust collection pick up air will be exhausted to a fabric filter baghouse prior to discharge to the atmosphere . The conveying air will be exhaus ted to a fabric filter baghouse prior to discharge to the atmosphere.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

- 15 - 

## 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 em ission 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 equa l to 0.06 grains per dry standard cubic foot of exhaust gas.
In addition, NR 415.04(1)(b) and (f) includes the follo wing requirements for the control of fugitive dust from roads and roadways:
(b) Application of asphalt, water, suitable chemicals or plastic covering on dirt roads, materi al 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 contro l of fugitive dust and particulate matter emissions from biomass fuel material handling processes. Howe ver, these biomass fuel material handling processes are similar (to some degree) to coal material hand ling systems. Several studies have been conducted on the control of fugitive dust from co al 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 th e 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, PM 10 , and PM 2.5 emissions.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

- 16 - 

## 3.4 Step 2. Eliminate Technically Infeasible Options.

All of the options identified in Table 3-1 ar e technically feasible control technologies.



## 3.5 Step 3. Rank the Technicall y Feasible Control Technologies.

Table 3-1 includes the potential controls and a gene ral ranking of the control effectiveness for the proposed material handling processes. Note that in so me 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 collecti on system and a fabric filter baghouse is generally expected to be the most effective control. Howeve r, 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 co ntrol system that induces an airflow into the building and out through the dust collection system. Beca use fabric filter baghouses emit a threshold amount of PM regardless of inlet loading, the dust collector, wh en in operation, is always emitting PM, albeit at very low rates. Conversely, the use of buildings or en closures 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 mo ist biomass fuels, the use of wet dust suppression systems may be more effective than the use of dust coll ection systems. Further, the fabric filter bags in the dust collector systems may be blinded or plug ged by operating the dust collectors when very wet biomass materials are being unloaded.

TABLE 3-1. Potential PM control technologies fo r 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 Roundt able (CHEER) Workshop report, Texas Natural Resource Conservation Commission, May 1996.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

- 17 - 

## 3.6 Step 4. Evaluate the Most Effective Controls.

Based on this analysis, the use of a building or encl osure 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 emissi ons 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, PM 10 , and PM 2.5 emissions from these processes. Further, the flexibility to use either control system is beneficial in mainta ining 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 PM 2.5 , lb/hr PM 2.5 , tons/yr PM 10 , lb/hr PM 10 , 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 hand ling throughput from both fixed bed and selfunloading trucks, and unloading of fi xed 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 u se 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 t echnology 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 tr ansfer 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 PM 10 emissions from the dust collection control systems shall be limited to 0.004 grains per dry standard cubic foot of exhaust gas.
(3) PM 2.5 emissions from the dust collection control systems shall be limited to 0.002 grains per dry sta ndard 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

- 18 - 

# 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 , 5 th Edition, section 13.2.4, Equation 1 may be used for estimating em issions from this unloading process which is a drop operation:

4

. 1 3

. 1



### 2 5 ) 0032

. 0 ( ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= M U

k E

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 PM 2.5 ) = 0.35 (for PM 10 ) = 0.74 (for PM )

The normal moisture content for biomass fuels is expect ed 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 (PM 2.5 ), 0.0000496 lb/ton (PM 10 ), and 0.00010 lb/ton (PM).
As noted previously, the majority of the biomass fuel s 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 ex pected 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 PM 2.5 , PM 10 , 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.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

- 19 - (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 t echnically feasible for the truck unloading process.



## 4.4 Step 3. Rank the Technicall y 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 fugiti ve dust sources can be subjective, since control efficiencies are in some cases difficult to quantify.

TABLE 4-1. Potential PM and PM 10 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 loweri ng 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 collecti on system and a fabric filter baghouse are generally expected to be the most effective control (or combinati on of controls). However, in some cases, this mayWe 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 du st control system that in duces 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 a nd a maximum annual fuel throughput of 778,700 tons per year, this truck unloading process will have maximum uncontrolled PM, PM 10 , and PM 2.5 emissions of 6, 39, and 82 pounds per year These are extremely low nu mbers, 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 gr ain loading of 0.004 gr/dscf, the system would emit 0.069 pounds per hour. For a fuel use of 778,700 to ns per year and a design unloading process rate of 100 tons per hour, the dust control syst em would operate at least 7,790 hours per year. Therefore, for the combined use of an enclosure and dust collection system, potential annual PM, PM 10 , and PM 2.5 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 technol ogy (BACT) for process F122, the biomass fuels self unloading truck opera tion. We Energies proposes the following limits as BACT for Process F122:

(1) Particulate matter (PM), PM 10 , and PM 2.5 emissions shall be controlled using self unloading truc ks 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

- 21 - 

# 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 conve yed in fully enclosed conveyors to the Biomass Fuels Storage building. Inside the storage building, th e biomass fuels will drop from the conveyor onto a pile. The fuels will then be reclaimed from the storage build ing 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 , 5 th Edition, section 13.2.4, Equation 1:

4

. 1 3

. 1



### 2 5 ) 0032

. 0 ( ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= M U

k E

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 PM 2.5 ) = 0.35 (for PM 10 ) = 0.74 (for PM )

The normal moisture content for biomass fuels is expect ed to range from 25 -50% on an as-received basis. Based on a mean wind speed of 1.0 miles per hour insi de the building, the uncont rolled emission factor for unloading biomass fuels is 6.0 x 10 -7 lb/ton (PM 2.5 ), 4.0 x 10 -6 lb/ton (PM 10 ), and 8.5 x 10 -6 lb/ton (PM). Based on these values, the maximum uncontrolled PM 2.5 , PM 10 , 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 requirement s for the control of fug itive dust from material storage and stockpiles:
(b) Application of asphalt, water, suitable chemicals or plastic covering on dirt roads, materi al 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 50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc. Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

- 22 - 

## 5.2 Step 1. Identify All Available Control Technologies.

Potential PM and PM 10 control technology options for the biomas s fuels storage and reclaim processes are summarized in Table 5-1.

TABLE 5-1. Potential PM control technol ogies 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 Ta ble 5-1 are technically feasible for the biomass fuels storage process.



## 5.4 Step 3. Rank the Technicall y 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 conclude d that the use of a biomass fuels storage building designed to enclose the entire storage pile and the r eclaim activities represents the best available control technology for process F123, the biomass fuels storag e and reclaim processes. We Energies proposes the following limits as BACT for Process F1243:

(1) Particulate matter (PM), PM 10 , and PM 2.5 emissions shall be controlled using a biomass fuels storage building designed to enclose the entire storage pile and the reclaim activities as the best av ailable 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

- 23 - 

# Chapter 6. Control Technology Review for Process P124: Boilerhouse Fuel Storage Silos.

Biomass fuels will be reclaimed from the storage build ing 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 emi ssion 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 g as is equal to 0.06 grains per dry st andard cubic foot of exhaust gas.


## 6.2 Step 1. Identify All Available Control Technologies.

Potential PM/PM 10 and PM 2.5 control technology options for the bin ve nt 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. Regard less 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 50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc. Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

- 24 - 

## 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 Technicall y Feasible Control Technologies.

Bin vent filters will achieve a PM/PM 10 control efficiency of approximately 99.9% of the inlet grain loading, or 0.004 grains per dry standard cubic foot of exhaust gas. In add ition, bin vent filters will achieve a PM 2.5 emission rate of 0.002 grains per dry st andard cubic foot of exhaust gas.



## 6.5 Step 4. Evaluate the Most Effective Controls.

The only commercially available or feasibl e control technology to control PM, PM 10 , and PM 2.5 emissions from fuel silo bin vents is the addition of vent filters to the silos. Recent permits for similar sources have PM and PM 10 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 PM 10 outlet grain loading of 0.004 gr/dscf, and a PM 2.5 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, PM 10 , and PM 2.5 emissions from the fuel silo bin vents, Process P124. We Energies proposes the follo wing limits as BACT for the fuel storage silos:

(1) Particulate matter (PM), PM 10 , and PM 2.5 emissions from the boiler fuel storage silos shall be controlled using bin vent filters as the best available control technology.
(2) PM and PM 10 emissions shall be limited to 0.004 grains per dry standard cubic foot of exhaust gas.
(3) PM 2.5 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

- 25 - 

# 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 totall y enclosed pneumatic semi-trailer trucks. Emissions from the truck haul truck traffic may be calculate d using the paved roads emission factor from AP-42 (revision 11/2006), Section 13.2.1: Paved Roads , Equation (1):



### C W sL k EF

u 

### − ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= 5

. 1 65

. 0



### 3 2

where, EF u = Vehicle Emission Factor, lb/mile traveled k

= 0.0024 [Table 13.2.1-1, for PM 2.5 ] = 0.016 [PM 10 ] = 0.082 [PM]
sL = silt loading, g/m 2 = 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 PM 2.5 ] C = 0.00047 lb/VMT [Table 13.2.1-2, for PM 10 and PM]

The silt loading of 0.6 g/m 2 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 uncontrolle d emission factors of 0.030 pounds per vehicle mile traveled (lb/VMT) for PM 2.5 , 0.20 lb/VMT (PM 10 ), and 1.04 lb/ton (PM).
The biomass fuel haul trucks are expected to deliv er 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 annu al paved road vehicle miles traveled will be 17,754 miles per year. Based on these values, the maximum uncontrolled PM 2.5 , PM 10 , 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 w ould be 29,200 tons per year. Based on a vehicle capacity of 25 tons, this annual ash generation rate woul d require 1,168 shipments. In add ition, the maximum daily haul rate would be 8 shipments per day. The total paved road r ound trip travel for each delivery is expected to be 3,000 feet, or 0.57 mile. Therefor e, the total annual vehicle miles trav eled will be 1,168 vehicles and 0.57 miles per vehicle, or 666 miles per year. Based on these values, the maximum uncontrolled PM 2.5 , PM 10 , and PM emissions for the ash truck traffic wo uld be 0.01, 0.07, and 0.35 tons per year.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

- 26 - 

## 7.1 BACT Baseline.

There are no new source performance standards for th ese 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 park ing 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, wa ter, suitable chemicals or plastic covering on dirt roads, material stockpiles and other surfaces which can create airb orne 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/PM 10 and PM 2.5 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

- 27 - 

## 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 Technicall y Feasible Control Technologies.

Table 7-1 includes the potential controls and a ranki ng of the control effectiveness for the control of fugitive dust from the biomass delivery and ash haul tr ucks. 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 pa ve 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 roadwa ys 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 Energi es proposes the following limits as BACT for these

processes:

(1) Particulate matter (PM), PM 10 , and PM 2.5 emissions shall be controlled using paved roadways in combin ation 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 a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix C: Control Technology Review for the Balance of Plant Equipment.March, 2010-28 -TABLE 7-2. Fugitive dust emissions from the Biomass Fuels Delivery Truck Haul Roads, Process F125.RoadSurfaceSiltLoadingAverageWeight ofTruckExhaust,Brake,TireFactorPMEmissionFactorVehicle MilesTraveledDustSuppressantControlEfficiencyMaximumEmissionRatePMEmissionsPOLLUTANTParticleSizeMultiplierg/m2tonlb/VMTlb/VMTVMT/hrVMT/yr%lb/hrton/yrPM2.50.0024 0.6 27.5 0.00036 0.030 5.87 18,162 85% 0.026 0.041PM100.016 0.6 27.5 0.00047 0.203 5.87 18,162 85% 0.178 0.276PM 0.082 0.6 27.5 0.00047 1.040 5.87 18,162 85% 0.916 1.417TABLE 7-3. Fugitive dust emissions fromthe Ash Truck Haul Roads, Process F133.RoadSurfaceSiltLoadingAverageWeight ofTruckExhaust,Brake,TireFactorPMEmissionFactorVehicle MilesTraveledDustSuppressantControlEfficiencyMaximumEmissionRatePMEmissionsPOLLUTANTParticleSizeMultiplierg/m2tonlb/VMTlb/VMTVMT/hrVMT/yr%lb/hrton/yrPM2.50.0024 0.6 27.5 0.00036 0.030 1.2 683 85% 0.0053 0.0015PM100.016 0.6 27.5 0.00047 0.203 1.2 683 85% 0.0357 0.0104PM 0.082 0.6 27.5 0.00047 1.040 1.2 683 85% 0.1832 0.0533Footnotes1. Paved road emissions were estimatedfrom 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 averagedaily travel from AP-42, Table 13.2.1-3.3. The average weight of both the fuel and ash haul trucks isbased on a loaded truck weight of 40 tons, and an unloaded truckweight of 15 tons.4. For fuel delivery, the vehicle miles traveled per hour isbased on 10 trucks per hour, and a round trip distance of 3,100 feet (0.587 miles).5. For ash trucks, the vehicle miles traveled per hour is basedon 2 trucks per hour,and a round trip distance of 3,100 feet(0.587 miles).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

- 29 - 

# 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 uncontrolle d 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 emi ssion 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 g as is equal to 0.06 grains per dry st andard cubic foot of exhaust gas.


## 8.2 Step 1. Identify All Available Control Technologies.

Potential PM/PM 10 and PM 2.5 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 filtersWe 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

- 30 - use cartridge filters rather than fabric filters. Regard less 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 Technicall y Feasible Control Technologies.

Bin vent filters will achieve a PM/PM 10 control efficiency of approximately 99.9% of the inlet grain loading, or 0.004 grains per dry standard cubic foot of exhaust gas. In add ition, bin vent filters will achieve a PM 2.5 emission rate of 0.002 grains per dry st andard cubic foot of exhaust gas.



## 8.5 Step 4. Evaluate the Most Effective Controls.

The only commercially available or feasibl e control technology to control PM, PM 10 , and PM 2.5 emissions from ash silo bin vent is the addition of vent filters to the silos. Recent permits for similar sources have PM and PM 10 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 PM 10 outlet grain loading of 0.004 gr/dscf, and a PM 2.5 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, PM 10 , and PM 2.5 emissions from the CFB boiler bed material silo bin vent, Process P131, and the ash s ilo bin vent, Process P132. We Energies proposes the following limits as BACT for these processes:

(4) Particulate matter (PM), PM 10 , and PM 2.5 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 PM 10 emissions shall be limited to 0.004 grains per dry standard cubic foot of exhaust gas.
(6) PM 2.5 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

- 31 - 

# 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 leavi ng the cooling tower to reduce visible plume issues and the potential for icing and fogging. The specific ations for the new cooling tower are summarized in Table 9-1.

TABLE 9-1. Specifications for the new plume abat ed 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 c ooling 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 evapor ates, cooling the remaining water. A small amount of the water is entrained in the induced air flow in th e form of liquid phase droplets or mist. Demisters are used at the outlet of cooling towers to reduce the amo unt 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, PM 10 , and PM 2.5 emissions.
Cooling tower PM emissions are calcu lated based on the circulating water flow rate, the total dissolved solids (TDS) in the circulating water, and the desi gn drift loss according to the following equation: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

- 32 - 

### ⎥ ⎦ ⎤ ⎢ ⎣ ⎡ ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

= 100 %DL
10 C ) water/gal lb 345

. 8 ( min/hr) 60 ( E 6 TDS 

### kQ

Where, E = Particulate matter emissions, pounds per hour Q = Circulating water flow rate , gallons per minute = 22,000 gpm C TDS = 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 partic le that would be produced by the evaporation of the liquid water from a drift droplet is given by the following equation 2 :

Where, d droplet = Maximum diameter of the drift droplet that would produce a dry particle size of d particle or smaller d particle = Dry particle (particulate matter) particle size, microns

ρ salt = Density of particle = 2.5 g/cm 3

ρ water = Density of water = 1.0 g/cm 3
C TDS = 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 PM 10 Emissions from Cooling Towers."

The above table is the drift loss droplet size distributi on for a large cooling tower. For a circulating water TDS level of 1,600 ppm, the drift loss droplet size w ould 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. 3 / 1 6 

### 10 ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

=

TDS water salt particle droplet 

### C d d ρ ρWe 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

- 33 - PM 10 emissions, and less than 29 microns to form PM 2.5 . From this table, 82% of the cooling tower drift loss (i.e., droplet particle sizes less than 130 microns), would result in PM 10 emissions, and 0.23% of the cooling tower drift loss would result in PM 2.5 emissions.

TABLE 9-2. Potential emissions for the new me chanical draft cooling tower, Process P141.

Flowrate C TDS 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 PM 10 22,000 1,600 0.0005% 0.82 0.072 0.317

Particulate Matter PM 2.5 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 av ailable 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 Tabl e 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 th e 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 m echanical 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 m echanical 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%.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

- 34 - 

## 9.7 Step 4. Evaluate the most effective controls.

The only feasible control technology for this mechani cal 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 - H ugo 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, PM 10 , and PM 2.5 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, PM 10 , and PM 2.5 emissions from the mechanical draft cooling tower, Process P141.

(1) Particulate matter (PM), PM 10 , and PM 2.5 emissions from the mechanical draft cooling tower, Pro cess 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 50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc. Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

- 35 - 

# 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 displaceme nt 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 Inte rnal Combustion Engines, 40 CFR Part 60, Subpart IIII. There are two possible applicable standard s for this new diesel engine in 40 CFR § 60.4205 depending on whether or not the e ngine 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 w ith 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 beginni ng 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, Ta ble 4 include the following for model year 2009 and later stationary fire pump engines with maximu m engine power between 300 and 600 horsepower:

NOx + NMHC ...................... 3.0 g/hp-hr CO...................................................... n/a PM....................................... 0.15 g/hp-hrWe 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

- 36 - TABLE 10-1. Potential emissions for the diesel en gine 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 NO x 3.00 400 2.64 0.13
Particulate Matter PM/PM 10 0.15 400 0.132 0.0066
Particulate Matter PM 2.5 0.12 400 0.106 0.0053
Sulfur Dioxide SO 2 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 H 2 SO 4 0.00057 400 0.00050 0.000025

Footnotes

1. NO x , PM, and PM 10 , 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. SO 2 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 SO 2 /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 10 12 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 f actor for No. 6 oil combustion from the U.S. EPA's AP42 , Table 1.3-11. The fluoride emission fact or 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 50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc. Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

- 37 - 

## 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 cata lytically coated diesel particulate filters (DPF).



### 10.1.2 Step 2. Eliminate T echnically Infeasible Options.
Good combustion practices, DOCs, and DPFs are technica lly 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 pre ssure which may prevent the engine from starting.



### 10.1.3 Step 3. Rank the Technical ly Feasible Control Technologies.
DOCs and DPFs are post combustion controls and woul d 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 th e DOC and DPF would be approximately $35,000 - $70,000 per ton of CO controlled, based on first year cost s. For a service life of 5 years and an interest rate of 7%, the cost effectiveness would be appr oximately $8,600 - $17,000 pe r ton of CO reduced. These are very high costs, indicating that the use of di esel 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 utiliz e 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 di esel 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 distilla te 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

- 38 - 

## 10.2 Nitrogen Oxides (NO x 

## ) Control Technology Review.

10.2.1 Step 1. Identify All Available Control Technologies.

Available controls for NO x emissions from diesel engines includ e good combustion practices based on engine design, and selective catalytic reduction (SCR).



### 10.2.2 Step 2. Eliminate T echnically Infeasible Options.
Good combustion practices based on engine design is t echnically feasible. While SCR is available for diesel engines, we are not aware of SCR systems a pplied to emergency diesel engines. SCR systems cannot operate until the SCR catalyst is sufficiently preheated to achieve NO x 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 Technical ly 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 Performan ce Standards in 40 CFR § 60.4205, Table 4. The engine design would have potential NO x 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 u tilize 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 di esel fuel as the best available control technology (BACT) for the control of NO x emissions. We Energies proposes the following limits:

(1) NO x 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

- 39 - 

## 10.3 PM, PM 10 

## , and PM 2.5 

## Control Technology Review.

10.3.1 Step 1. Identify All Available Control Technologies.

Available controls for PM, PM 10 , and PM 2.5 emissions from diesel engine includes good combustion practices (GCP), diesel particulate filters (DPF), and diesel oxidation catalysts (DOC).



### 10.3.2 Step 2. Eliminate T echnically Infeasible Options.
Good combustion practices, DOCs, and DPFs are technica lly 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 pre ssure which may prevent the engine from starting.



### 10.3.3 Step 3. Rank the Technical ly Feasible Control Technologies.
DOCs and DPFs are post combustion controls and woul d 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 ho urs per year, the engine design would have PM, PM 10 , and PM 2.5 emissions of 0.0083, 0.0083, and 0.0067 tons pe r 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 DO C 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 eff ectiveness would be approximately $150,000 - $300,000 per ton of PM reduced. These are very high costs, indi cating that the use of diesel particulate filters and oxidation catalysts on this limited use diesel generato r is not an economically feasible control technology for the control of PM, PM 10 , and PM 2.5 emissions from this emergency diesel feed water pump.



### 10.3.5 Step 5. Proposed BACT Requirements.
Based on this analysis, We Energies proposes to utiliz e 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 di esel fuel as the best available control technology (BACT) for the control of PM, PM 10 , and PM 2.5 emissions. We Energies proposes the following limits:

(1) PM, PM 10 , and PM 2.5 emissions may not exceed 0.15 grams per horsepower hour. (2) The sulfur content of the distilla te 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

- 40 - 

## 10.4 Sulfur Dioxide (SO 2 

## ) Control Technology Review.

10.4.1 Step 1. Identify All Available Control Technologies.

Sulfur dioxide (SO 2 ) emissions result from the oxidation of sulfur in the fuel being combusted. The only available SO 2 control technology for this emer gency diesel engine is the use of low sulfur fuels. Other technologies used for other combustion sources incl ude flue gas desulfurization (FGD) systems.



### 10.4.2 Step 2. Eliminate T echnically Infeasible Options.
The only commercially available SO 2 control technology for diesel engines is the use of low sulfur fuels. Because FGD systems are not commercially available fo r diesel engines, FGD is not a technically feasible control technology for this diesel engine.



### 10.4.3 Step 3. Rank the Technical ly Feasible Control Technologies.
The only technically feasible SO 2 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 SO 2 emissions to 0.0003 ton per

year.



### 10.4.4 Step 4. Evaluate the Most Effective Controls.
Because the only technically feasible SO 2 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 utiliz e 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 di esel fuel as the best available control technology (BACT) for the control of SO 2 emissions. We Energies proposes the following limits:

(1) The sulfur content of the distilla te 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 50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc. Appendix C: Control Technology Review for the Balance of Plant Equipment. March, 2010

- 41 - 

## 10.5 Volatile Organic Compound (V OC) Control Tech nology 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 cata lytically coated diesel particulate filters (DPF).



### 10.5.2 Step 2. Eliminate T echnically Infeasible Options.
Good combustion practices, DOCs, and DPFs are technica lly 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 pre ssure which may prevent the engine from starting.



### 10.5.3 Step 3. Rank the Technical ly Feasible Control Technologies.
DOCs and DPFs are post combustion controls and woul d 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 hour s 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 th e 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 appr oximately $13,000 - $27,000 pe r ton of VOC reduced. These are very high costs, indicating that the use of di esel 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 utiliz e 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 di esel 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 distilla te 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) Cont rol Technology Review.

Fluorine (F) is a trace element in diesel fuel. Wh en 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 (CaF 2 ).



### 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 concen trations. 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 T echnically 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 indi cating their effectiveness in controlling fluoride emissions. Therefore, DPFs are not considered a te chnically feasible control option for fluoride emissions from this engine. Because FGD systems are not commerc ially available for diesel engines, FGD is not a technically feasible control technology for this engine.



### 10.6.3 Step 3. Rank the Technical ly 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 t echnology 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 utiliz e 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 di esel 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 distilla te 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 Construc tion 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 E NVIRONMENTAL A SSOCIATES I NC .®
903 Superior Avenue, Suite 6 Tomah, WI 54660Air 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 w ith the lowest emitting facilities in similar source categories. These National Emissions Standards for Hazardous Air Pollut ants (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. EP A has not established MACT standards for new industrial boilers, We Energies has prepared this cas e-by-case MACT analysis fo r 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 circ ulating fluidized bed boiler, in combination with a fabric filter baghouse. These contro l technologies are similar to those u sed 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, PM 10 , and PM 2.5 BACT emission limits represent MACT. Organic HAPs Organic HAP emissions from the bi omass 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 bioma ss 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.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

- ii - 

## Inorganic, Solid Phase HAPs.

Inorganic, solid phase HAPs are controlled by partic ulate matter (PM) control systems. Based on this case-by-case MACT analysis, We Energies has conc luded that the proposed fabric filter baghouse represents the best available control technology (BACT) for PM, PM 10 , and PM 2.5 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 car bon 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 chlori de and hydrogen fluoride. These acid gases are formed during combustion from chlori ne 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 c oncluded that using low chlorine containing biomass fuels in combination with a fabric filter baghou se 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 review ed, 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 d esulfurization (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 com bustion has high levels of al kali substances in the ash, the additional injection of sorbent may not achieve em ission reductions. Even these controls could further reduce HCl emissions, the costs of control would be ex tremely high, with an average cost effectiveness for the dry sorbent injection system of $40,000 per t on of HCl controlled. Finally, the use of sorbent injection may adversely impact the reuse of this ash , which would have substan tial environmental impacts and additional economic impacts.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

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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 inhere ntly 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 fabr ic 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 emissi on 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 feasi ble mercury control. While we are not aware of the use of activated carbon injection on any biomass-fu eled 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 th an in coal or municipal solid waste, the use of activated carbon injection will have limited ability to c ontrol mercury. Based on this review and the fact that activated carbon injection has not been demonstr ated on similar biomass-fu eled boilers, we have concluded that the level of mercur y emissions with activated carbon inj ection will be the same as the level of control when firing low mercury containing bioma ss fuels and the use of a fabric filter baghouse.
Even if activated carbon injection could reduce mercury emissions, the cost effec tiveness 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. Furt her, the use of activated carbon injection may also adversely impact the potential reuse of the boiler fl yash which could have s ubstantial environmental impacts and additional economic costs. Based on the pot ential impact to ash dispo sal, 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 evid ence that this level of control could actually be achieved in practice.
Based on this analysis, We Energies has conclude d 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.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

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## Natural Gas-Fueled Boiler.

The proposed natural gas-fueled boiler is also a pot ential source of HAP emissi ons. 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 majo r source” under Section 112(g)).
Although We Energies believes Section 112(g) of the C AA 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 propo sed 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 represen ting MACT for the natural gas-fueled boiler.

HAP CATEGORY PROPOSED EMISSION LIMIT

Inorganic, solid Proposed PM and PM 10 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 c ontrolled by firing only natural gas.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
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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 Anal ysis Methodo logy. ................................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 Haza rdous Air Po llutants...........................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 HA Ps....................................................................................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 Li mit for Organic HAPs. ............................................................ 31


## Chapter 7. Mercury..............................................................................................32Air 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
- 6 - 7.1 U.S. EPA Proposed MACT Standards........................................................................................... 32

7.2 State of Wisconsin Mercury Rule................................................................................................ .. 32

7.3 MACT Floor Analysis for Mercury............................................................................................... 3 2
7.3.1 Mercury Concentrati ons 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 I norganic, 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. .............................................. 48Air 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
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# Tables

TABLE 1. Summary of HAP Emissions fro m the biomass-fired boiler by HAP Category.
TABLE 2. Biomass-fueled boiler particulat e 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 emissi ons 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 throug h the fabric filter baghouse filter cake showing the mechanism for particulate collection and mercury control



# Attachments

Attachment 1. Potential hazardous air pollutant emis sions for the biomass-fired boiler B01 (2 pages).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
- 8 - 

# Chapter 1. Introduction.

We Energies’ proposed 50 MW Biomass-Fueled Cogene ration Facility will include a new combined heat and power steam generating unit that will use a subcr itical pressure, advanced circulating fluidized bed boiler to generate steam to power a nominal 50 MW steam turbine generator 1 and to provide process steam to the Domtar facility. Dependi ng on energy requirements, the bo iler 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 u tilize a Selective Non-Catalytic Reduction system (SNCR) for the control of nitrogen oxides (NO x ), a fabric filter baghouse for the control of particulate matter, and PM 10 , felted fabric media in the baghouse for the control of direct PM 2.5 , the use low sulfur containing fuels including biomass fuels and natural gas for sulfur dioxide (SO 2 ) 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 technol ogy (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 ma intained, 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 constr ucted major source would require additional control technology or a change in control technology, the a pplication for a MACT determ ination 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 pl ant 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 capa bilities, auxiliary power requirements and resulting plant capacity. Daily operating conditions including fuel heat conten t, fuel moisture content, emissions control operations along with boiler and-or turbine fouling will also have impacts on capacity.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
- 9 - 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 includi ng identification of alternative control technologies considered by the applicant to meet the emission limitation; and This MACT Analysis

(xiii) Any other relevant inform ation required pursuant to subpa rt A. This MACT AnalysisAir 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
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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 so urces 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 proce sses 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 in formation, 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 categ ory 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 th en 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 s ources is defined in 40 CFR § 63.41 as: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
- 11 - 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 owne r or operator of each permit application or other application requiring a case-by-case MACT determination concerning construction or reco nstruction 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 construc ted 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 emi ssion control that is achieved in practice by the best controlled similar source.” When a standard must be achievable, it must be achie vable under most adverse circumstances which can reasonably be expected to recur. Thus, the MACT standard should be set at aAir 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
- 12 - 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 emi ssion control that is achieved in practice by the best controlled similar source.” While this sentence is relatively straightforwar d, it can be difficult to follow in practice. The stumbling block for review agencies ha s often been the phrase, “achieved in practice”. How is “achieved in practice” determined?

The D.C. Circuit Court has ruled that where the la w 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 ru led that EPA is justified in setting the standard at a level that is a reasonable estimate of the perform ance of the “best controlled similar unit” under the worst reasonably foreseeable circumstances.
Therefore, this case-by-case MACT analysis is base d on first identifying the "best performing" similar unit. Then, to account for variability, this MACT anal ysis 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 majo r 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 th e 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 itsel f 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.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
- 13 - 

# Chapter 3. Biomass-Fueled Boiler Case-by-Case MACT Analysis.

3.1 Hazardous Air Pollutant Emissions.

Hazardous air pollutants (HAP) emitted from biomass-fu eled 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 charact eristics 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 ph ase HAPs occur as trace substances in all fuels, including biomass fuels and natural gas. These subs tances 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 eff ectively controlled by the highly alkaline ash from biomass combustion in the advanced circulating fluidi zed 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 contai n very small amounts of mercury. Multi-pollutant control systems, including fabric filter baghouse par ticulate 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 emission s 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 tho se 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 un controlled wood residue combustion, and that are listed as a federal HAP.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
- 14 - 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%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
- 15 - 

# 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, arsen ic, beryllium, cadmium, chromium, chromium VI, cobalt, lead, manganese, nickel, and selenium. Du ring 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 mode rn, high efficiency PM control devices such as the proposed fabric filter baghouse. The Control Technol ogy Review for PM contai ned 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, PM 10 , and PM 2.5 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. Unde r 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. Th is requirement was based on Reference Method 5 or 17, i.e., front half emissions only

. 

## 4.2 MACT Floor Analysis fo r 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 emis sions 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, th e 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 achieva ble under the most adverse circumstances which can reasonably be expected to occur. Thus, the MACT st andard 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.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
- 16 - TABLE 2. Biomass-fueled boiler particulate matter and PM 10 BACT emission limits.

Limit, lb/mmBtu Facility State Permit Date Capacity, mmBtu/hr Primary Fuel Control System 3 PM PM 10 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 Test 2
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 PM 10 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. “E SP” 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. Co mpliance 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 PM 10 emissions from biomass; the second limit is for natural gas.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
- 17 - In the control technology review, We Energies has propo sed the use of a fabric filter baghouse to attain a best available control technology front-half, filtera ble 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 sim ilar units in Table 2. There are many factors that affect the PM emission rates of the best performing un its 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 ach ievable 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 ach ieved 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 em issions 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 emissi on 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 cont rol 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 activitiesAir 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
- 18 - • 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 Li mit for Inorganic, Solid Phase HAPs.

Based on this analysis, We Energies has conclude d 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 h as also concluded that that the BACT compliance demonstration requirements for PM also demonstrat e 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 determ inations 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 Ro ad Generating Station, Permit No. 03-RV-166, condition I.A.12.a.(1).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
- 19 - 

# Chapter 5. Inorganic, Acid Gas HAPs.

Inorganic, vapor phase acid gas HAPs include hydrochl oric and hydrofluoric acids. They are formed from chlorine and fluorine contained in the biomass fu els. 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 contro lled 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 co nverted 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. Unde r 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 Servi ce of New Hampshire - Schiller Station. This limit apparently reflects the vacated NESHAP limit for new so lid 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 Schille r Station includes wood and coal . The Schiller Station has a circulating fluidized bed (CFB) boiler. The permit requires the u se of sorbent (limestone) injection to the CFB boiler for SO 2 and HCl control. However, the use of sorbent injection is not required to demonstrate compliance with the MACT limit. When demonstrating complia nce 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 perm it reviewed is 0.006 lb/mmBtu for the Yellow Pine Energy Company, Georgia. The permit for this fac ility also allows the use of tire derived fuel, and requires the use of a dry sorbent inj ection system for the control of SO 2 emissions.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
- 20 - TABLE 3. Biomass-fueled boiler HCl emission limits representing MACT.

Facility State Permit Date Primary Fuel Control System a 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 0.034 b YES
Pub Service of NH - Schiller NH Oct-04 Wood / Coal FSI / FFB 0.02 c 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 0.284 d YES

Footnotes

a “FFB” means fabric filter baghouse; “ESP” means electrost atic 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, In c. (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 range d from 50 to 162 ppm, with an average of 70 ppm. Assuming all chlorine is emitted as HCl, the averag e HCl emission rate was 0.011 and 0.007 lb/mmBtu for bark and stemwood, respectively, with a 95 th percentile of 0.014 lb/mmBtu.
According to NCASI Technical Bulletin No. 0837, Emissions of Sulfuric, Hydr ochloric, 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 th is 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 muchAir 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
- 21 - 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 95 th 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 , 5 th Edition, Wood Residue Combustion, Tables 1.6-3, is 0.0192 lb/mmBtu.

TABLE 4. Wood fuels analyses data and uncontr olled 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. EP A’s Phase I survey Information Collection Request (ICR No. 2286.01) and the Phase II test plan (I CR 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 ov er 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 boile rs, with emission rates ranging from 0.0002 lb/mmBtu to 0.072 lb/mmBtu. Several of the emission test resu lts 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,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
- 22 - 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 HC l 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 (C aO) 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 ha d a chlorine content of 0.07%, equal to 0.002 moles of chlorine per 100 lb dry fuel. Therefore, the effect ive 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 th at the MACT floor for HCl emissions from this biomass-fueled boiler is 0.018 lb/mmBtu. This em ission 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 BtuProbability Density HCl Emission Test Data

HCl Fuel Sampling Data

90% Probability, 0.018 lb/mmBtu 90% Probability, 0.13 lb/mmBtuAir 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
- 23 - 

## 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 wi th inherently low chloride concentrations, combined with the use of a fabric filter baghouse or electrost atic 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 sorben t injection systems. However, all of the facilities that were identified with MACT limits may demons trate 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 th e 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 subbitu minous 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 sorben t injection is not well understood or demonstrated in practice. Because biomass combustion already r esults in high levels of calcium oxide (CaO) and potassium oxide (K 2 O) in the ash, the additional injection of so rbent may not achieve substantial emission reductions.
Even if the use of FGD systems or sorbent injec tion 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 an nual 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 c ontrolled. 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 adver sely 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 pe r 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 in jection 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.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
- 24 - 

## 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 Yello w 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 d esulfurization (FGD) systems, including dry sorbent injection, were evaluated as a potential control tech nology for HCl emissions from biomass combustion. However, the continuous reduction of HCl emissi ons 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 (K 2 O) in the ash, the additional injection of sorbent may not achieve substantial emis sion reductions. Even if the use of FGD systems or sorbent injection could further reduce HCl emissions, th e 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 adver sely impact the reuse of this ash which would have substantial environmental costs a nd 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 a nother method approved in writing by the Department.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
- 25 - 

## 5.5 MACT Floor Analysis fo r Hydrogen Fluoride (HF).

Based on the permits and information ava ilable, 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 vaca ted National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Instituti onal 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, Hydr ochloric, 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 0.000 074 lb/mmBtu for the oil/bark boilers.
According to the U.S. EPA’s MA CT database emission factors fr om 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 In stitutional 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 , 5 th Edition, Wood Residue Combustion, does not list an emission factor fo r HF emissions. In Switzerland, the combustion requirements for wood limit HF emissions to 2 mg/m 3 , 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. EP A’s Phase I survey Information Collection Request (ICR No. 2286.01) and the Phase II test plan (I CR 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 ove r 350 samples for biomass fuels (with descriptions including wood, bark, plywood, particleboard, hog fu el, 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 ra nging 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 di stributions for each data set. The 90% probability for the HF emission rate, based on fuel sampling and anal ysis, is 0.006 lb/mmBtu, while the 90% probability distribution for the HF emission rate, based on emissi on 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.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
- 26 - 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 fi ring this typical biomass fuel is more than forty to one (40:1). This high level of reac tive 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. Th e 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 BtuProbability Density HF Emission Test Data

HF Fuel Sampling Data

90% Probability, 0.0007 90% Probability, 0.006 lb/mmBtuAir 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
- 27 - 

## 5.6 Beyond the Floor MACT Analys is for Hydrogen Fluoride (HF).

Based upon information reviewed, the most common c ontrol method used to control HF emissions from biomass fueled-boilers is the use of biomass fuels wi th inherently low fluoride concentrations, combined with the use of a fabric filter baghouse or electrost atic 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 sorben t injection systems. However, all of the facilities that were identified with MACT limits may demons trate 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 th e 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 co al combustion (which has a highly alkaline ash) of 50%. However, the continuous reduction of HF em issions 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 (K 2 O) in the ash, the additional injection of sorbent may not achie ve substantial emission reductions.
As with the control of HCl emissions, even if the us e of FGD systems or sorbent injection could further reduce HF emissions, the costs of control would be extr emely 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 contro l 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 adver sely impact the reuse of this ash which would have substantial environmental costs and additional econom ic impacts. The combustion of biomass fuels would produce about 29,100 tons per year of ash. Th is ash will be derived from biomass fuels, and is anticipated to have value as a soil amendment or fe rtilizer. However, if sorbent injection were to adversely impact the reuse of this ash, the ash may n eed to be disposed of in a landfill. Not only would this have environmental conseque nces, but this could also lead to much higher costs.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
- 28 - 

## 5.7 Proposed Case-by-Case MACT for Hydrogen Fluoride (HF).

Based on the permits and information ava ilable, We Energies did not identify any biomass-fueled boiler with a hydrogen fluoride (HF) emission limit. Base d on the available data, we have concluded that the MACT floor for HF emissions from this biomass-fuel ed 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 d esulfurization (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 emissi ons 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 (K 2 O) in the ash, the additional injection of sorbent may not achieve substantial emis sion reductions. Even if the use of FGD systems or sorbent injection could further reduce HF emissions, th e costs of control would be extremely high, with an average cost effectiveness for th e dry sorbent injection system of more than $700,000 per ton of HF controlled. In addition, the use of sorbent injecti on may adversely impact the reuse of this ash which would have substantial environmental co sts 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.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
- 29 - 

# 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 th e 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, Comme rcial, 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 expensiv e 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. Unde r 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 boile rs 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 ofAir 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
- 30 - 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 Bi omass 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 othe r 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 ach ieved 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 1.15Air 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
- 31 - 

## 6.3 Beyond the Floor Organic HAP MACT Analysis.

The only control methods, based upon available info rmation, actually used to control organic HAP emissions from biomass-fueled boilers is good co mbustion 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 co mmenced operation. There are significant technicalquestions regarding the ability of oxidation catalysts to control organic HAP emissions from biomassfueled boilers. Because of the serio us technical questions regarding th e 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 ma ximum achievable control technology for organic HAPs from this biomass-fueled boiler, so that no othe r requirements are necessary for this HAP category. Note that this conclusion is consistent with th e case-by-case MACT determinations for organic HAP emissions made by the Department in the air pollu tion control construction permit for Weston Unit 4, Permit No. 03-RV-248, condition I.A.12.a.(3), and in th e air pollution control construction permit for the Elm Road Generating Station, Permit No. 03-RV-166, condition I.A.12.a.(3).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
- 32 - 

# Chapter 7. Mercury.

Mercury is a trace element in biomass fuels. Mercur y is an unusual metal because it boils at a very low temperature of 675 o F. When fuel is burned, the high combus tion temperatures vaporize mercury to form elemental mercury (Hg 0 ). 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 (Hg p ). The total mercury in the flue gas (Hg T ) is the sum of Hg p , Hg +2 , and Hg 0

. Mercury is present at varying concentrations in biom ass. When biomass is burned, mercury exits the boiler at extremely low concentra tions, 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. Unde r 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 emi ssions 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 sourc es 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 boile rs which have commenced initial operation, and the mercury emission limit which represents MACT. Becau se these are new units, or existing units with new controls, these units represent the best performing si milar units for the control of mercury emissions. Based on the information reviewed, the mercury em ission limits for new biomass-fueled boilers and which have made an initial complia nce demonstration is 3.0 pounds pe r trillion Btu of heat input. Other emission limits range from 9.0 to 25.0 lb/TBtu. A ll of the permits with a MACT limit required initial compliance demonstration by stack testing. No sour ces were required to install mercury specific controls.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
- 33 - TABLE 6. Biomass-fueled boiler mercury emission limits representing MACT.

Facility State Permit Date Primary Fuel Control System a Limit, lb/TBtu B 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 Oc t-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 10 12 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 produc ts manufacturing facilities across the c ountry. According to this report, the mercury content of the bark samples ranged from less than 1.0 to 37.4 part s per billion (ppb) on an oven dry basis, with an average of 12.5 ppb. For st emwood, 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 wa s 1.42 pounds per trillion Btu (lb/TBtu) and 0.28 lb/TBtu for bark and stemwood, respectively. The 90 th 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 mercuryAir 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
- 34 - 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, equa l 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 EP A 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 e qual to an emission rate of approximately 0.6 pounds per trillion Btu.
The emission factor for mercury emissions from w aste wood combustion in the U.S. EPA’s AP-42, Compilation of Air Pollutant Emission Factors , 5 th Edition, Wood Residue Combustion, Tables 1.6-4, is 3.5 lb/TBtu, and is given an A rating. This emissi on 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. EP A’s Phase I survey Information Collection Request (ICR No. 2286.01) and the Phase II test plan (I CR 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 da ta included over 500 samples for biomass fuels (with descriptions including wood, bark, plywood, particle board, hog fuel, and biomass). The mercury fuel sampling and analysis data ranged from 0.06 lb/trilli on 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 e ach 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, na tural gas, and a fabric filter baghouse. Biomass fuels generally have very low mercury levels, with typica l 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” u nder the worst reasonably foreseeable circumstances.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
- 35 - FIGURE 3. Mercury (Hg) fuel sampling and an alysis 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 An alysis 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 emissi on 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 ge nerally have very low mercury leve ls, with typical mercury in fuel levels of 0.3 to 3.0 pounds per trillion Btu of h eat 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 ma tter control systems. Although we are not aware of any biomass-fueled boiler using post combustion me rcury control systems, mercury emissions from municipal waste combustors and coal-fueled electric utility steam generating units may also be controlledAir 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
- 36 - through mercury-specific control technologies. B ased upon available information, mercury specific controls include activated carbon injection (ACI), mercury oxidation catalysts, and other controls, including halogen injection into the boiler. De velopment of halogenated powdered activated carbon (PAC) sorbents, including brominated PAC, is also underway to improve merc ury control performance. Both the mercury oxidation catalysts and activated ca rbon 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, ther e is little information on the level of control which may be expected from the PM contro l 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 efficien cies for coal-fired electric generating units equipped with only fabric filter baghouse PM controls aver aged 72% and 90% for su bbituminous and bituminous coal combustion, respectively. By comparison, co al-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-fi red boilers using fabric filter baghouses as compared to those using electrostatic precipitators is probabl y due to the increased contact that the flue gas experiences with fly ash and unburned carbon on the filter cak e 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 cap ture is also related to th e 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.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
- 37 - 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 munici pal 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 baghou se, to collect the mercury sorbent separately from the fly ash. In this latter arrangement, a sy stem called a Compact Hybrid Particle Collector (COHPAC TM ) may be used. When a COHPAC is combined with sorbent injection, it is called Toxic Emission Control (TOXECON TM ).
From 2001 to 2003, the Department of Energy’s Na tional Energy Technology Lab, the Electric Power Research Institute (EPRI) and a group of utility compan ies 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 perform ance of ACI, including the uncontrolled mercury emission rate or concentration, the sorbent injecti on rate, the flue gas temperature, and the sorbent characteristics. Other factors also affect mercury removal, in cluding fabric filter baghouse and bag design, and baghouse operation. For ACI, the sorbent injection rate is typically expressed in pounds ofAir 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
- 38 - 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 AC I 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 Elec tric 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 + COHPAC TM 0 25 – 90%
Univ. of Illinois - Abbott Bituminous Coal CS-ESP 0 73%

Finally, the sorbent characteristics can have a signi ficant 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 chlo rine (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 gas 2

. While we are not aware of the use of activated car bon injection on any biomass-fueled boiler, based on the current coal-fired utility boiler and municipal wa ste combustor experience, activated carbon injection is a technically feasible mercury control alternative fo r biomass-fueled boilers. However, several factors may severely limit the ability of ACI to actually re duce mercury emissions from biomass-fueled boilers. The concentration of mercury in biomass is much lo wer than in coal, municipal solid waste, or refuse derived fuel, which means the concentration of mercur y 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 ultimat e 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 Technologi es Corporation. Presented at the Combined Power Plant Air Pollutant Control Mega Symposium Washington, DC, Aug. 30 – Sept. 2, 2004.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
- 39 - remove the diminishing amounts of mercury. For ex ample, the uncontrolled mercury concentrations at municipal waste combustors have historically been at 100 μ g/dscm and higher (60 lb/trillion Btu); uncontrolled mercury at coal fired boilers are at 5 to 20 μ g/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 mo lar basis to achieve similar mercury removal efficiencies– perhaps as much as 10 times more. This can result in cont rol costs which increase exponentially, or it may simply mean that ACI woul d 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 genera ting 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 we t FGD systems. These approaches are undergoing fullscale evaluation. However, the sulfur dioxide contro l technology review for this biomass-fueled boiler concluded that a wet FGD system is not an ec onomically 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 SO 2 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 biomas s-fueled boilers, the addition of oxidizing chemicals is not a demonstrated, technically feasible mercury control option.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
- 40 - 

### 7.4.3 Rank of the Technically Feasible Control Technologies.
Based upon available information, the only mercury cont rol 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 cont rol 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 merc ury 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 ve ry low mercury levels, The use of low mercury containing biomass fuels combin ed 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 activ ated carbon injection on any biomass-fueled boiler. Because the concentration of mercury in biomass is e xpected to be much lower than in coal, municipal solid waste, or refuse derived fuel, the reaction kine tics 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 ca rbon injection has not been demonstrated on similar biomass-fueled boilers, We Energies has concluded th at 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 fe asible 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 2.9Air 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
- 41 - 

### 7.4.4 Evaluate the Most Effective Controls.

From Table 8, we have concluded that based on the av ailable 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 ba ghouse. Even if we could conclude otherwise, the use of activated carbon injection does not repr esent 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 boiler 3 . 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 contro l 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 th ere is no evidence that this level of control could actually be achieved.
The use of activated carbon injection may also adver sely impact the potential reuse of the boiler flyash which could have substantial envir onmental impacts and additional econom ic 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 am endment or fertilizer. However, if sorbent injection were to adversely impact the reuse of this ash, the as h 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 sorben t 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 poun d of mercury controlled.


### 7.4.5 Beyond the Floor M ACT Mercury Conclusion.
Based upon available information, the only mercury cont rol 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-fu eled 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 co al, 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 co ntrol costs which increase exponentially, or it simply may mean that ACI w ould have little effect in reducing mercury emission rates. Based on this review and the fact that ac tivated 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, FigureAir 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
- 42 - similar biomass-fueled boilers, we have concluded th at 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 merc ury emissions by 50%, the cost effectiveness of the activated carbon injection system, based only on th e 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 ha ve substantial environmen tal 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 merc ury controlled. This is an extremely high cost, especially since there is no evidence that this le vel 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 circ ulating fluidized bed boiler shall be controlled using biomass fuels in comb ination 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.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
- 43 - 

# 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 polluta nts. 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 th is boiler is expected to be infrequent.



## 8.1 Hazardous Air Pollutant Emissions.

As with the biomass-fueled boiler, hazardous air pollu tants (HAP) emitted from natural gas-fueled boilers may be classified in 4 broad categories, including in organic, 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 summa rized 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, 5 th 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 bo iler 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 Septembe r 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. Th is subcategory included the following limits:

Carbon Monoxide.............. 400 ppm by volume on a dry basis corrected to 3% O 2 (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.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
- 44 - TABLE 9. Potential hazardous air pollutant em issions for the natural gas-fueled package boiler.

Emission Factor Heat Input Potential to Emit Pollutant CAS No. lb/10 6 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 0.0 00000 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 , 5 th Edition, Natural Gas Combustion, Tables 1.4-3 and 1.4-4Air 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
- 45 - 

## 8.3 Inorganic Solid Phase HAPs.

Inorganic, solid phase HAP emissions occur from natu ral 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 s ubstances 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 PM 10 for this boiler includes a detailed discussion on PM control for this boiler. We Energies has proposed a particulate matter and PM 10 emission limit for the auxiliary boiler of 0.0075 pounds per million Btu of heat input, averag ed over any 3-hour period. This limit is more stringent than the now vacated applicable PM/PM 10 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 standard s for natural gas-fueled boilers. Based on this analysis, the use of PM 10 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 informa tion, 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 th e use of natural gas is not technically feasible.


### 8.3.2 Proposed Case-by-Case MACT fo r Inorganic, Solid Phase HAPs.
Based on this analysis, We Energies has concluded th at the use of natural gas and the proposed BACT
PM 10 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 PM 10 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 a nd hydrofluoric acids are formed from chlorine and fluorine in the fuel. From the memo from Christ y 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 fu el boilers of 0.0009 lb/mmBtu. Potential HCl emissions are only 16.3 pounds (0.008 tons) per year.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
- 46 - 

### 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 natu ral gas or distillate fuel oil-fired boilers. Even if FGD was used, there is no data or information to s uggest that HCl emissions could be reduced below the expected emission rate of 0.0000124 lb/MMBtu. Ther efore, 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 M ACT HCl Emission Limit.
This package boiler will fire only natural gas. Restri cting the fuels used in th ese 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 combus tion are expected to be extremely small. We Energies was not able to identify actual fluoride emi ssions 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 met hod used to control acid gas emissions from natural gas-fueled boilers is the use of natu ral gas as the fuel. We Energies h as concluded that the further control beyond the use of natural gas is not technically feasible.


### 8.4.5 Proposed Case-by-Case M ACT HF Emission Limit.
This package boiler will fire only natural gas. Restric ting the fuels used in this boiler to only natural gas represents MACT for HF emissions. Therefore, We En ergies 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 or ganic compound (VOC) emissions is included in the control technology review. Acco rding to the U.S. EPA’s AP-42, potential organic HAPs resulting from natural gas combustion include 24 organic com pounds, including polycyclic aromatic compounds, formaldehyde, hexane, and toluene. Hexane act ually accounts for approximately 94% of all HAP emissions from natural gas combustion. These orga nic 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 th e control of organic HAP emissions is consistent with the U.S. EPA’s practice when establishing MACT standards for combustion source categoriesAir 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
- 47 - emitting organic HAP’s. For example, in the preamble for the “ National Emission Standards for Hazardous Air Pollutants for Industrial, Comme rcial, 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 expensiv e 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 packag e boiler, We Energies has proposed a best available control technology CO emission limit of 0.0375 lb/mmBtu, and a VOC emi ssion 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 combusti on 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 Orga nic 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 prac tices. Based on the information available to We Energies, no post combustion controls have been re quired 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 co mbustion 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. Ther mal 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 co mbustion 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-fire d boiler, and because there is no evidence that itAir 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
- 48 - 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 th at 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 requireme nts 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 /LAE R Clearinghouse to determine the best performing similar units did not show any similar natural gas-fu eled boilers with specific mercury emission limits. To limit mercury emissions from similar sources, regulat ory 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 in formation, used to control mercury emissions from natural gas-fueled boilers is the use of thes e low mercury containing fuels. We Energies has concluded that the further control beyond the use of na tural 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. Restric ting 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.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
- 49 - 

# Attachment 1.

TABLE 1. Potential hazardous air pollutant emi ssions 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 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 0.095Inorganic, Solid Phase

Selenium 2.8E-06 800 0.002 0.010 Hydrogen chloride 0.018 800 14.4 63.1 Inorganic 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 0.000Organic

1,2-Dibromoethene 5.5E-05 800 0.044 0.193Air 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
- 50 - TABLE 1. Potential hazardous air pollutant emi ssions 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 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 0.063Organic

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 , 5 th Edition, Wood Residue Combustion, Tables 1.6-3 and 1.6-4.

## Prevention of Significant Deterioration
Air Pollution Control Construc tion 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 E NVIRONMENTAL A SSOCIATES I NC .®
903 Superior Avenue, Suite 6 Tomah, WI 54660We 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
2 

# Executive Summary

This document is the Prevention of Significant Deteri oration (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 ne w 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 ne w cooling tower, and a new diesel engine driven feed water pump. Under the Prevention of Signifi cant Deterioration (PSD) program in NR 405.02(22)(a), Wis. Adm. Code, the major stationary source threshold for this facility is 100 to ns 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 (NO X ), particulate matter (PM/PM 10 ), particulate matter less than 2.5 microns in size (PM 2.5 ), and sulfur dioxide (SO 2 ).
The air quality analysis utilizes air quality dispersion computer models along with monitored background air quality data to evaluate compliance with the Na tional 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 n ecessary, Class I visibility and air quality related values (AQRV) analyses. The procedures used for all air qua lity impact analyses were consistent with relevant EPA and DNR guidance.
PSD modeling analyses are typically conducted in two st eps: 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 Leve l (“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 emi ssions 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 u se of background air quality data.
The significant impact analysis of the Project emissions indicates that CO, NO 2 , and the annual SO 2 impacts are all below the corresponding SILs. Theref ore, no further analysis is necessary for these pollutants. Cumulative impact modeling was performed for SO 2 3-hr and 24-hr averages, all PM 10 and
PM 2.5 averaging periods, and the 24-hr state TSP standard. EPA has not developed 1-hr NO 2 SILs to determine when a cumulative 1-hr NO 2 NAAQS analysis is required. Therefore, even though the annual NO 2 impacts from the Project are insignificant, a cumulative 1-hr NO 2 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 summa rized in Table ES-2. These analysis results demonstrate that the Project will not cause or cont ribute to air quality impacts that exceed the NAAQS, PSD increments, or the Wisconsin TSP standard.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
3 TABLE ES-1. Cumulative NAAQS modeling results.

Pollutant Averaging Interval Cumulative Impact, μg/m3 Background, μg/m 3 Total, μg/m 3 NAAQS μg/m3 % of NAAQS

NO 2 1-hour 61 11.9 73.2 188 39%

24-hour 249 11.2 260.2 365 71% SO 2 3-hour 951 11.8 962.8 1300 74%

PM 10 24-hour 41.8 29.4 71.2 150 47%

Annual 2.3 8.7 11 15 73% PM 2.5 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/m 3 PSD Increment μg/m 3 % of PSD Increment

Annual 5.7 17 34% PM 10 24-hour 21.0 30 70%

24-hour 86.1 91 95% SO 2 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 exp ected to have a measurable effect on residential, commercial, or industrial growth because of the cu rrent large local population and amount of industrial and commercial activity in the Project area.

Wisconsin has two Class I PSD areas, the Rainbow La ke 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.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
4 

# Table of Contents

Chapter 1. Introduction. ........................................................................................6
Chapter 2. Summary of Modelin g 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 NO 2 Conversion Methodology.......................................................................................................1 7

2.7 Background Air Quality Data .................................................................................................... ....17

2.8 Model Design Concentrations.................................................................................................... ....19


## Chapter 3. Emission and Sta ck Data. .................................................................20

3.1 Project Emission and Stack Data. ............................................................................................... ...20

3.2 Other Nearby Sources for Cumulative An alyses. ..........................................................................20

3.2.1 Domtar Sources................................................................................................................. 23 3.2.2 Lignotech Sources............................................................................................................. 2 5 3.2.3 Weston Power Plant Boilers. ............................................................................................ 25 3.3 PSD Increment Emissions and Baseline Dates..............................................................................25


## Chapter 4. Air Quality Analys is 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 Impact s Analys is. ...........................................................29

5.1 Analysis on Soils, Vegetation, and Visibility. ...............................................................................29

5.2 Associated Growth and Secondary Emissions...............................................................................30


## Chapter 6. Class I Air Qualit y Analys is. ............................................................31We 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
5 

# Table of Contents (continued)

Figures

FIGURE 1-1. Locus map for We Energies’ propo sed 50 MW biomass-fired c ogeneration 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-Dimensi on 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 Con centration Data, μg/m3. .............................................................................1 8 TABLE 3-1. Project Stack Para meters and Emission Data. ......................................................................21

TABLE 3-2. Domtar PM 2.5 Emission Calculations. ..................................................................................23

TABLE 3-3. Weston PM 2.5 Emission Calculations. ..................................................................................25



# Appendices

Appendix A – Summary of Cumulative Source Inventory Emissions and Stack parametersWe 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
6 

# 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 insta llation 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 equi pment, a new cooling tower, and a new diesel engine driven emergency feed water pump. A list of th ese 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 Road s (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 co mbined with F125 emissions in the dispersion modeling analysis. )

S141 P141 Cooling Tower
S151 P151 Emergency Diesel Engine Feed Water PumpWe 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
7 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 Wiscons in 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 (NO X ), particulate matter (PM/PM 10 ), fine particulate matter (PM 2.5 ), sulfur dioxide (SO 2 ), 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 NO x 350.4 21.7 0.13 372 40 YES

Particulate Matter PM 10 105.1 8.2 0.007 17.1 0.3 131 15 YES

Particulate Matter PM 2.5 80.6 8.2 0.005 8.4 0.0009 97 10 YES

Sulfur Dioxide SO 2 315.4 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 H 2 SO 4 6.3 0.007 0.000025 6.3 7 NO

Based on this PSD applicability analysis, PSD ai r quality impact analyses are required for SO 2 , NO X , PM 10 /PM 2.5 , and CO. The generation of the regional polluta nt 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 disp ersion modeling analysis is not required.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
8 FIGURE 1-1. Locus map for We Energies’ propo sed 50 MW biomass-fired cogeneration facility.

We Energies Biomass Cogeneration Facility

NORTH

Scale, miles 5 0 5 10We 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
9 FIGURE 1-2. USGS location map for We Energ ies’ 50 MW biomass-fired cogeneration facility.

We Energies Biomass Cogeneration FacilityWe 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
10 FIGURE 1-3. Artist Rendering of the Facility Layout.

Biomass Fuels Storage Building

New Boilerhouse
and Stack S01

New Cooling
Tower Existing Mill

Existing MillWe 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
11 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 visibilit y analysis, an associated growth analysis, and if necessary, Class I visibility and ai r 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

Annual 100 1 25 Nitrogen Oxides (NO 2 ) 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 (PM 10 ) 24-hour 150 5 30

Annual 15 0.3 n/a Particulate Matter (PM 2.5 ) 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 (SO 2 ) 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 PM 2.5 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.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
12 

# 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 Gu ide”, 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 Ju ly 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 st eps: 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 sour ce are not expected to have a significant impact on ambient air concentrations and further air quality an alysis is not required. If the source's ambient impacts exceed the SIL for any pollutant and averagi ng interval, the extent of the geographical area in which the source exceeds the SIL is determined (refe rred to as the Significant Impact Area [SIA]), and a cumulative impact analysis is performed for that po llutant, 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 s ources, and also considers the combined effect of emissions from natural, distant, and unidentified s ources through the use of background air quality data.
If the cumulative impact analysis demonstrates viola tions 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 th at 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 th e facility (i.e., the near-field analys is). 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 pr ecise input data, including representative hourly meteorological data, and result in more accurate estimates of the source ambient air impacts.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
13 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-st ate plume dispersion model that simulates transport and dispersion from multiple point, area, or volume s ources 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 convectiv e 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, a nd flow above this height rises up and over terrain. AERMOD also uses the advanced PRIME algorithm to accoun t for building wake effects.
The regulatory DFAULT option requires the use of terr ain elevation data, stac k-tip downwash, sequential date checking, and does not permit the use of the mode l 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 Pr ogram –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) requir ements 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 th at 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 op tions, which affect the dispersion rates used in calculating ground-level pollutant con centrations. A methodology was developed by the EPA to classify an area as either rural or urban for dispersion m odeling 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.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
14 

## 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 wh ich 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 Ai rport 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 th e model estimates pollutant concentrations only at receptor locations.
The main receptor network used for the air modeli ng consisted of 5010 receptors based on "discrete" rectangular grids (with UTM "x–y" coordinates and rece ptor "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 di stance 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 sp aced 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.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix E: Air Quality Impact Analysis.March, 201015FIGURE 2-1. Main AERMAP Receptor Grid.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix E: Air Quality Impact Analysis.March, 201016FIGURE 2-2. Close-in PM AERMAP Receptor Grid.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
17 

## 2.6 NO 2 

## Conversion Methodology

The majority of NO X emissions from combustion sources are in the form of nitric oxide (NO), whereas EPA has established air quality standards for NO 2 . Therefore, an approved methodology must be used to convert model estimates of ambient NO con centrations into equivalent ambient NO 2 concentrations. EPA's GAQM provides a three-tiered approach to calculating annual average NO 2 impacts. The Tier 2 ARM method was used with the default ratio of 0.75 for the NO 2 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 disper sion model, and any uni dentified 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 th e “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 PM 2.5 and 1-hr NO 2 NAAQS, and is in the process of developing implementation and modeling guidance for both standa rds. DNR provided background concentrations for PM 2.5 and averaging intervals in a draft guidance memo randum, dated October 1, 2009. This is a draft update to the September 15, 2008 memora ndum. DNR has not tabulated 1-hour NO 2 background concentrations, therefore the available NO 2 monitoring data for Wisconsin (available on EPA’s Airdata web site) was evaluated to dete rmine the appropriate 1-hr NO 2 background concentration. There are two NO 2 monitoring stations, one in Milwaukee and one in Two Rivers. The Two Rivers site is more representative of the project site, and the calculated 98 th percentile value for the years of 2006-2008 is 11.9 μg/m3. This value was used for the 1-hr NO 2 background concentration. The PM 2.5 and 1-hr NO 2 background concentrations may be revised in the future as EPA issues additional guidance on implementation of the two standards.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
18 

### TABLE 2-1. Background Concentration Data, μg/m 3



### .

Pollutant Averaging Period Background Value

Annual 8.0 Nitrogen Oxides (NO 2 ) 1-hour 11.9

8-hour 904.7 Carbon Monoxide (CO) 1-hour 950.5

Annual 10.1 Particulate Matter (PM 10 ) 24-hour 29.4

Annual 8.7 Particulate Matter (PM 2.5 ) 24-hour 25.6
Total Suspended Particulate (TSP) 24-hour 39.7

Annual 5.4

24-hour 11.2 Sulfur Dioxide (SO 2 )

3-hour 11.8

3-month 0.01 Lead Quarterly 0.01We 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
19 

## 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 incremen ts. 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 SO 2 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 NO 2 , the annual average NAAQS and PSD increment design concentration is the highest of the annual averages calculated from each of the individual years,

• For PM 10 , the 24-hr NAAQS design concentration is th e “n+1” highest concentration over the n year modeling period (high 6 rd highest for the five year meteorological data set), the 24-hr PSD increment design concentration is the highest, sec ond-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 PM 2.5 , 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 ei ghth-highest concentrations across the number of years of data, and then selects the highest, acro ss 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 concentr ation, AERMOD calculates the annual PM 2.5 design concentration based on the highest of the multi-y ear averaged annual means across the receptor domain for multi-year meteorological data input,

• For the Wisconsin TSP standard, the 24-hr desi gn concentration is the highest, second-highest concentration from each of the individual years that are modeled.

EPA recently promulgated the 1-hr NO 2 NAAQS, and is in the process of developing implementation and modeling guidance. Because EPA has not yet deve loped 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 y ear in the meteorological data set as the 1-hr NO 2 design concentration was used, based on discussions with DNR.
EPA recently issued preliminary revised guidance for performing PM 2.5 analyses. Until EPA finalizes this revised guidance, the PM 2.5 NAAQS analyses have been performed using the standard design concentration calculation procedures that are directly programmed into AERMOD.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
20 

# Chapter 3. Emission and Stack Data.

3.1 Project Emission and Stack Data.

The PSD Air Pollution Control Construction Permit appli cation 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 va ry over a range of operati ng conditions, the modeling analysis also considered operating load scenario s for the boilers, as recommended in EPA’s GAQM. Section 9.1.2 of the GAQM recommends that an assess ment of both full load and partial load conditions for emission units be performed to determine the wo rst-case source configuration for use in subsequent modeling. Stack parameter and em issions vendor data was available for the biomass boiler for 100%, 80%, 60%, and 40% loads. For the natural gas fire d 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 ra te 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 th e BPIP-PRIME analysis. Even though the gas-fired Project boilers are intended to operate only when th e biomass boiler is down, both the gas-fired boilers and the biomass boiler were modeled as operating si multaneously. 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 great er 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 i nventory for other facilities in the impact area, which included the nearby Domtar and Lignotech fac ilities, as well as the main boiler sources at the Weston Power Plant. The data was transmitted as IS CST3, AERMOD, and BPIP input data files, so all necessary information including locations, stack para meters, nearby structures, and emission rates was available.We Energies - Air Pollution Control Construction Permit Application for a50 MW Biomass Fuels-Fired Cogeneration FacilityRTP Environmental Associates, Inc.Appendix E: Air Quality Impact Analysis.March, 201021TABLE 3-1. Project Stack Parameters and Emission Data.StackIDProcessIDDescriptionPollutant Emission Rate, lb/hrUTMEasting,metersUTMNorthing,metersDischargeTypeDischargeHeight,feetDia.,feetTemp,oFExitVelocityfpsCONOXPMPM10PM2.5SO2PbS01 B01Biomass Fuel-Fired CirculatingFluidized Bed Boiler B01160.0 80.0 24.0 24.0 18.4 72.0 0.02400 292,337 4,973,906 Vertical 250 10.0 288 27.6S02 B02Natural Gas-Fired Package BoilerB0210.5 3.5 1.3 1.33 1.33 0.11 0.00008 292,3404,973,873 Vertical 200 6.6 365 32.8S03 B03Natural Gas-Fired Package BoilerB0310.5 3.5 1.3 1.33 1.33 0.11 0.00008 292,3404,973,873 Vertical 200 6.6 365 32.8S121 P121 Biomass Fuels Dust Collector3.75 3.75 1.87292,297 4,973,831 Vertical 100 6.0 Ambient 66.3S122 F122 Self Unloading Fuels Truck0.00524 0.00248 0.00038292,252 4,973,763 VolumeS123 F123 Biomass FuelsStorage and Reclaim0.00043 0.00020 0.00003292,214 4,973,675 VolumeS124 P124 Boilerhouse Fuel Storage Silos (2)0.0206 0.0206 0.0103292,307 4,973,882 Vertical 110 1.0 Ambient 6.4S125 F125 Fuels Delivery Truck Roads0.889 0.173 0.026Various Various VolumeS131 P131 CFB Boiler Bed Material Silo0.034 0.034 0.017292,325 4,973,900 Vertical 110 2.0 Ambient 10.6S132 P132 CFB Boiler Ash Silo0.034 0.034 0.017292,367 4,973,932 Vertical 75 2.0 Ambient 10.6S133 F133 Boiler Ash Haul Roads0.178 0.035 0.0051Various Various VolumeS141 P141 Cooling Tower0.088 0.072 0.000292,401 4,973,972 Vertical 70 25.0 50 25.0S151 P151Emergency Diesel Engine Feed WaterPump2.300 2.643 0.132 0.132 0.106 0.0050 0.00003 292,324 4,973,862 Vertical 195 0.7 800 130FootnotesB02 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, S124Aand S124B, and the stack data listed is for each stack.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
22 FIGURE 3-1. Modeled Layout and 3-Dime nsion BPIP-PRIME View of the Project.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
23 Because the Project boilers are intended to replace th e 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, NO X , TSP, PM 10 , and SO 2 emission data. Since DNR has not yet established allowable PM 2.5 emission rates for permitted sources, it was necessary to estimate PM 2.5 emissions for the cumulative PM 2.5 NAAQS analysis (note that PM 2.5 emissions have been directly calculated for all Project emission units). An initial assumption was made that PM 2.5 emissions were equal to the allowable PM 10 emissions. This was overly conservative for some emission units, and so the following refinements were made to the PM 2.5 emission rates for the cumulative inventory.



## 3.2.1 Domtar Sources

For the Domtar facility, the refine ments made to the estimated PM 2.5 emission rates, and some minor stack configuration changes, are listed below.



### TABLE 3-2. Domtar PM 2.5 

### 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 PM 10 and PM 2.5 rates, and these emissions are split between th e 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%
PM 2.5 /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 ope rations, 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 PM 10 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 PM 2.5 emissions were calculated by multiplying the normal system flow rate (1000 acfm) by a conservative PM 2.5 outlet grainWe 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
24 Domtar Source ID Comments

loading of 0.01 gr/dscf. The calculated PM 2.5 emission rate is 0.0857 lb/hr.

S56 The allowable Lime Silo PM 10 emissions in the facility Title V permit were based on AP42 Section 8.15. This AP-42 section included both PM and PM 2.5 emissions factors, so the ratio of the PM 2.5 versus PM factors was used to adjust the PM 10 rate of 0.72 lb/hr to a
PM 2.5 rate of 0.0384 lb/hr (without consider ation of the 60% wet scrubber control efficiency). Also, this stack h as been converted to a vertical release at a height of 26.5 feet.

S70 The starch silo PM 10 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 PM 2.5 emissions were calculated by multiplying the normal system flow rate (750 acfm) by a conservative PM 2.5 outlet grain loading of 0.01 gr/dscf. The calculated PM 2.5 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 thr ee physical stacks (S90A, S90B, and S90C) for the Pulper Cyclone, Pulper Vent, and Shredder Cyclone emission units. The
PM 2.5 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 Applicati on 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 PM 2.5 emissions based on the AP-42 paved and unpaved road emission e quations. The Domtar Title V Renewal application haul road emission calculations u sed the AP-42 equations and did not subtract the factor “C” for exhaust, brake wear and tire wear (which conservatively overestimates the PM 10 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
PM 10 emissions that are PM 2.5 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 PM 10 emissions provided in the DNR cumula tive emission inventory modeling files were multiplied by 15% to calcu late the Domtar haul road PM 2.5 emission rates

In addition to estimating PM 2.5 emissions at the Domtar sources, one additional change was made to the Domtar source inventory. For S82, the Pulp Mill Lift Station, the modeled SO 2 emissions rate was based on the maximum theoretical rate of 0.367 lb/hr versus th e code allowable rate of 1.63 lb/hr. Also, the stack for S82 will be converted from a hori zontal release to a vertical release.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
25 

## 3.2.2 Lignotech Sources.

Based on limited stack test data and discussions with the equipment manufacturer, the PM 2.5 emission rate for source S16, the Spray Dryer #2, were set to 4 lb /hr, which is equal to the Spray Dryer #3 allowable
PM 10 emission rate. For all other emission units, the PM 2.5 emissions were conservatively assumed to be equal to the allowable PM 10 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 SO 2 and PM 10 emissions rates. The PM 2.5 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 com bustion of Powder River Basin (PRB) coal. The PM 2.5 emission rate for unit 4 was set equal to the allowable PM 10 emission rate. The following table presents the PM 2.5 emission rates modeled for Weston units 1 throug h 4. The final modeled cumulative inventory, including emission rates and stack parameters, is presented in Appendix A of this report.

TABLE 3-3. Weston PM 2.5 Emission Calculations.

Parameter/Unit # 1 2 3 4
Controls ESP ESP FF FF/FGD Current PM 10 emission rates lb/hr 87.8 100 390.6 103.5 Size mmBtu/hr 858 1000 3423 5173 Calculated PM 10 lb/mmBtu 0.102 0.100 0.114 0.020 Condensable lb/mmBtu 0.020 0.020 0.020 included
PM 10 Filterable lb/mmBtu 0.082 0.080 0.094 n/a
PM 10 Filterable Size Fraction 67 67 92 n/a
PM 2.5 Filterable Size fraction 29 29 53 n/a
PM 2.5 Filterable lb/mmBtu 0.036 0.035 0.054 included Total PM 2.5 lb/mmBtu (Filterable and Condensable) 0.056 0.055 0.074 0.020

Modeled PM 2.5 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 a pplicable baseline date. The Project is located in Marathon County, and the PSD baseline for Marath on County has been set at various times for PM 10 , SO 2 , and NO X . The SO 2 and PM 10 baseline dates were established in December 27, 1987, and the NO X baseline date was established as of September 2, 1993.
The nearby source inventory that DNR provi ded included the PSD increment consuming SO 2 , PM 10 , and NO X emissions for the Domtar, Ligotech, and Weston facilities, and these rates were modeled as necessary in the cumulative PSD increm ent analyses. In addition, all of the Project emission sources were modeled as increment consuming emission sources.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
26 

# Chapter 4. Air Quality Analysis Results.

4.1 Significant Impact Analysis.

In this dispersion modeling analysis, a significant imp act analysis was first performed to determine the increases in ambient air concentrations due only to th e 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 (“SI L”) for all averaging periods, the emissions from the proposed source are not expected to have a significan t 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, NO 2 , and the annual SO 2 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, cumu lative impact modeling was performed for SO 2 3-hr and 24-hr averages, and all PM 10 , and PM 2.5 averaging periods. EPA has not developed 1-hr NO 2 SILs to determine when a cumulative 1-hr NO 2 NAAQS analysis is required. Therefore, even though the annual NO 2 impacts from the Project are insignificant, a cumulative 1-hr NO 2 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 provide d the cumulative NAAQS and PSD source inventory for other facilities in the impact area, which include d 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 li mited to the project’s significant impact area, the Project modeling utilized the same large receptor gr ids for the cumulative analyses as for the project significant impact analyses.
The results of the cumulative NAAQS analysis ar e summarized in Table 4-2. The NAAQS results demonstrate that the Project will not cause or contri bute to air quality concentrations that exceed the NAAQS or Wisconsin TSP standard.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
27 TABLE 4-1. Results of the significant impact analysis.

Pollutant Averaging Period Significant Impact Level, μ g/m 3 Highest Modeled Concentration, μ g/m 3

8-hour 500 99 CO 1-hour 2,000 209

NO 2 Annual 1 0.92

Annual 1 0.98

24-hour 5 12.6 SO 2

3-hour 25 55.6

Annual 1 5.6 PM 10 24-hour 5 20.4

Annual 0.3 1.2 PM 2.5 24-hour 1.2 6.4

Footnotes
The SILs listed for PM 2.5 are the lowest of EPA’s currently proposed values.

TABLE 4-2. Cumulative NAAQS modeling results.

Pollutant Averaging Interval Cumulative Impact, μg/m 3 Background, μg/m 3 Total, μg/m 3 NAAQS μg/m 3 % of NAAQS

NO 2 1-hour 61 11.9 73.2 188 39%

24-hour 249 11.2 260.2 365 71% SO 2 3-hour 951 11.8 962.8 1,300 74%

PM 10 24-hour 41.8 29.4 71.2 150 47%

Annual 2.3 8.7 11 15 73% PM 2.5 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%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
28 

### 4.2.1 

## Cumulative PSD Increment Analysis

.
The results of the cumulative Class II PSD incremen t 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/m 3 PSD Increment μg/m 3 % of PSD Increment

Annual 5.7 17 34% PM 10 24-hour 21.0 30 70%

24-hour 86.1 91 95% SO 2 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 E: Air Quality Impact Analysis. March, 2010
29 

# 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 Federa l 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 gene ral commercial, residential, and industrial growth associated with the proposed project.



## 5.1 Analysis on Soils, Veg etation, 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 “h ealth and welfare”, includi ng “welfare” effects on water, vegetation, and soils, and are a useful benchm ark for evaluating soil and vegetation impacts. In addition, model predicted concentra tions 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” Vo lume II, August 1993, EPA 600/8-91/049bF. The maximum modeled annual NO 2 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 NO 2 averages. The maximum modeled 1-hr NO 2 concentrations were 73 μg/m3, which is far below the EPA direct effects screening concentration of 3,760 μg/m3 for 4-hr NO 2 averages. The maximum modeled ambient SO 2 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 scree ning concentrations of 786 μg/m3 for 3-hr and 18 μg/m3 for annual averages. Since the ambient im pacts from the Project do not exceed the NAAQS nor EPA screening thresholds for sensitive vegetati on and soils, the dispersion modeling analysis demonstrates that there are no harmful effects to vegetation and soils.
Near the proposed project site, under certain meteor ological conditions, the combustion source stacks will emit a visible steam plume which, after traveling a re latively 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 associ ated 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 exp ected to be reduced. Therefore, this Project will have a positive overall impact on so ils, 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, commercia l, 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, Cens us 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 Plan t 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 servi ces for the construction and operation of the Project. 

### The Project will be located entirely within an exis ting 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, Congr ess 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 na tional 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 ai r 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 notificati on 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 ar eas, the federal Rainbow Lake Ar ea located in the Chequamagon National Forest (located approximately 200 km dist ant 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 w ithin 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 pe rformed 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 SO 2 , NO X , PM 10 , and H 2 SO 4 , 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 th e Federal Land Managers do not require Class I impact analyses. Based on the emissions of the proposed f acility 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 ParametersSource 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 20.00Source ID Source Description PM25 PM10TSP SO2ST NOXST CO PSDPM24 PSDPMANN PM-2.5 SO2ANN NOXANN PSDSO2(lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) (tpy) (tpy) (lb/hr)S01Biomass Boiler Flow @ 50%1.84E+01 2.40E+01 2.40E+01 7.20E+01 8.00E+01 1.60E+022.40E+01 1.05E+02 8.06E+01 3.15E+02 3.50E+02 7.20E+01S02_03GasOil Boilers Flows@50%2.66E+00 2.66E+00 2.66E+00 2.20E-01 7.00E+00 2.10E+012.66E+00 1.17E+01 8.20E+00 1.66E+00 2.18E+01 2.20E-01S151Back up Feedwater Pump1.06E-01 1.32E-01 1.32E-01 5.00E-03 2.64E+00 2.30E+001.32E-01 6.61E-03 5.30E-02 4.00E-04 1.32E-01 5.00E-03S121Dust Control System1.87E+00 3.75E+00 3.75E+00 3.75E+00 1.64E+01 8.19E+00S124AFuel Silo 1 Bin Vent5.15E-03 1.03E-02 1.03E-02 1.03E-02 4.51E-02 2.25E-02S124BFuel Silo 2 Bin Vent5.15E-03 1.03E-02 1.03E-02 1.03E-02 4.51E-02 2.25E-02S131CFB Bed Silo Bin Vent1.71E-02 3.43E-02 3.43E-02 3.43E-02 1.50E-01 7.51E-02S132Ash Silo Bin Vent1.71E-02 3.43E-02 3.43E-02 3.43E-02 1.50E-01 7.51E-02S141~1Cooltower Cell 13.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04S141~2Cooltower Cell 23.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04S141~3Cooltower Cell 33.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04S141~4Cooltower Cell 43.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04S141~5Cooltower Cell 53.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04S141~6Cooltower Cell 63.22E-05 1.17E-02 1.47E-02 1.17E-02 5.14E-02 1.41E-04DS20OOld S20 Configuration-1.3E+00 -5.6E+00DS21Solid Fuel Storage/Receiving2.80E-02 2.80E-02 5.90E-02 1.23E-01DS22Refuse Bin and Feed System1.30E-02 1.30E-02 2.70E-02 5.69E-02DS44Wood Chip Cyclone2.30E-01 7.80E-01 7.80E-01 4.30E-01 1.88E+00 1.01E+00DS45Wood Room Operations8.85E-02 3.00E-01 3.00E-01 3.88E-01DS50Acid Plant Process6.50E-01 6.50E-01 6.50E-01 3.80E+016.50E-01 2.85E+00 2.85E+00 1.66E+02DS51Acid Plant Miscellaneous1.40E-01 6.13E-01 5.00E-03DS52Limestone Unloading Silo8.57E-02 5.00E-01 5.00E-01 5.00E-01 2.19E+00 3.75E-01DS53Digester Operations6.00E-02 2.63E-01 5.80E-02DS542903Unbleached Pulp Processes9.00E-03 9.00E-03 1.60E-02 5.00E-01 8.88E-03 3.89E-02 3.94E-02 2.19E+00 3.30E-01DS542907Unbleached Pulp Processes2.00E-03 2.00E-03 3.00E-03 5.30E-01 1.90E-03 8.32E-03 8.76E-03 2.32E+00 5.40E-01DS542908Unbleached Pulp Processes5.00E-04 5.00E-04 1.00E-03 6.00E-01 5.08E-04 2.23E-03 2.19E-03 2.63E+00 1.93E+00DS543001Unbleached Pulp Processes6.00E-03 6.00E-03 1.00E-02 2.52E+00 5.58E-03 2.45E-02 2.63E-02 1.10E+01 7.80E-01DS543003Unbleached Pulp Processes2.00E-03 2.00E-03 4.00E-03 1.01E+00 2.16E-03 9.46E-03 8.76E-03 4.42E+00 8.50E-01DS543307Unbleached Pulp Processes3.00E-03 3.00E-03 5.00E-03 1.13E+00 2.54E-03 1.11E-02 1.31E-02 4.95E+00DS56White Lime Silo3.84E-02 7.20E-01 7.20E-01 1.68E-01DS70Bulk Starch Storage6.43E-02 4.10E-01 4.10E-01 2.82E-01DS80Wastewater Treatment Plant6.70E-01 2.93E+00Source ID Source Description PM25 PM10TSP SO2ST NOXST CO PSDPM24 PSDPMANN PM-2.5 SO2ANN NOXANN PSDSO2(lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) (tpy) (tpy) (lb/hr)DS82Pulp Mill Lift Station3.67E-01 1.61E+00 3.10E-01DS90APulper Cyclone1.48E-01 5.00E-01 5.00E-01 6.48E-01DS90BPulper Vent2.80E-02 9.40E-02 9.40E-02 1.23E-01DS90CShredder Cyclone9.70E-02 3.30E-01 3.30E-01 4.25E-01L16_80Lignotech4.00E+00 1.28E+01 1.28E+01 7.00E-01 1.75E+01 3.10E+00L17Lignotech4.00E+00 4.00E+00 4.00E+00 2.30E+00 1.75E+01 1.01E+01L22Lignotech5.00E+00 2.19E+01L26Lignotech6.20E-01 2.72E+00L27Lignotech3.80E+00 1.66E+01L29Lignotech1.00E+01 4.38E+01WES01Weston Unit 14.77E+01 8.78E+01 8.78E+01 7.64E+02 2.09E+02 3.34E+03WES02Weston Unit 25.46E+01 1.00E+02 1.00E+02 8.90E+02 2.39E+02 3.90E+03WES03Weston Unit 32.54E+02 3.91E+02 3.91E+02 4.69E+03 3.91E+02 1.71E+03 1.11E+03 2.05E+04 4.69E+03WES04NWeston Unit 41.04E+02 1.04E+02 1.04E+02 3.49E+03 1.04E+02 4.53E+02 4.53E+02 2.04E+03 3.49E+03State 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
; Form 4530-101, Facility Plot Plan This application contains 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, RecordkeepingState 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-Fuel ed 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 "nona ttainment", indicate the pollutant for the nonattainment designation. N/A

11. List all air pollution permits and orders issued to this f acility (if a renewal application, just list those issued since t he issuance date of your existing operation permit). No permits – this is a new facility.
12. If Renewal Application: List all air pollution control pe rmit applications you have submitted on which the Department has not yet taken action. (If no permit number has been assigne d yet, indicate the date of the application) N/A
13. If Renewal Application: List all permit exemptions receive d from the Department since the issuance date of your existing operation permit. (Reference these by the date of the exempti on letter or the exemption number if one was assigned.) N/AState 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 po llution control permit application filed pursuant to ss. 285.61, 2 85.62 or 285.66, Wis Stats. Completion of this form is mandatory. Th e Department will not consider or act upon your application unless you complete and submit this form. It is not the Department's in tention to use any personally identifiable information from this f orm for any other purpose.

In order for a comprehensive air quality analysis to be accomplis hed, a facility plot plan MUST be included with the permit application. If the application is for an initial operation pe rmit, 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 applicati on 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 sin ce 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 ; NoState 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 po llution control permit application filed pursuant to ss. 285.61, 2 85.62 or 285.66, Wis Stats. Completion of this form is mandatory. Th e Department will not consider or act upon your application unless you complete and submit this form. It is not the Department's in tention to use any personally identifiable information from this f orm 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/modifi ed 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 installe d at the facility since the last operation permit issuance date an d include the following information. Attach supplemental forms as needed.

a. List the Department issued construction and/or operation pe rmit number as applicable (iden tifying 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 applicati on forms were submitted for the new emissions unit(s) covered by the construction permit mentioned above, comp lete the appropriate forms 4530-118 through 4530-125.

b. Include the Department issued construction permit exemption num ber, if one was assigned, or reference the date of the letter of the exemption.

2. Site Description

The facility is located in Rothschild, Wisconsin di rectly 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 po llution control permit application filed pursuant to ss. 285.61, 2 85.62 or 285.66, Wis Stats. Completion of this form is mandatory. Th e Department will not consider or act upon your application unless you complete and submit this form. It is not the Department's in tention to use any personally identifiable information from this f orm for any other purpose.

1. List all significant existing or proposed air pollution units, operations, a nd activities at the facility. A short narrative of the inventory of air pollution emissions unit (e.g., boiler, printi ng 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 bookle t for an example Unit description.)

Please refer to the permit applicatio n 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 issuanc e date:

a. If any of these new/modified units were exempt from cons truction 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 insignifi cant 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 po llution control permit application filed pursuant to ss. 285.61, 2 85.62 or 285.66, Wis Stats. Completion of this form is mandatory. Th e Department will not consider or act upon your application unless you complete and submit this form. It is not the Department's in tention to use any personally identifiable information from this f orm 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 em issions unit (e.g., boiler, printing line, etc.) followed by equi pment 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 Build ings (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 em ergency 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, fo rest 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 fi ring 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 cont rol 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 (%O 2 )

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 DETERMI NING 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 th e system. Attached? Please refer to the permit application Control technology review.

9. List the pollutants to be controlled by this equipment and th e expected control efficiency for each pollutant on the table b elow. ; Documentation is attached?

Pollutant Inlet pollutant concentration Hood capture efficien cy (%) Outlet pollutant concentration Efficiency (%)

gr/acf ppmv gr/acf ppmv Nitrogen oxides (NO x ) 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 re quired 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 m onitored in order to detect a malfunction or breakthrough, the correct operating range of these variables, and a detailed descri ption of monitoring or surveillance procedures that will be used to show compliance. c. What type of monitoring equipment will be provide d (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 th e expected control efficiency for each pollutant on the table b elow. 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, Proce ss P132. The ash will then be loaded into fully enclosed tanker trucks for shipment offsite.

11. Pressure drop across the filter (inches of H 2 O): 12. Prepare a malfunction prevention and abatement plan (if re quired 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 de tect a malfunction or breakthrough, the correct operating range of these variables, and a detailed description of monitoring or su rveillance 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/ft 2 ):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 po llutants. 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 ca pacity, each boiler will have a maximum de sign 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 NO x burners and flue gas recirculation to cont rol emissions of CO, NO x , PM, PM 10 , PM 2.5 , and VOCs.

5. Indicate the boiler/furnace control technology status. ; Uncontrolled □ Controlled

If the boiler/furnace is controlled, enter the cont rol 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 (%O 2 )

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 DETERMI NING 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 po llutants. 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 att ach a flow diagram of the process).

This is a dust collector for the biomass fu els 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 DETER MINING 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 th e expected control efficiency for each pollutant on the table b elow. 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 retur ned to the Biomass fuels conveying syst em, or it will be disposed of in a landfill. 11. Pressure drop across the filter (inches of H 2 O):

12. Prepare a malfunction prevention and abatement plan (if re quired 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 de tect a malfunction or breakthrough, the correct operating range of these variables, and a detailed description of monitoring or su rveillance 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/ft 2 ):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 po llutants. 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 att ach a flow diagram of the process).
This is self unloading semi trailer truck unload ing 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 DETER MINING 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 po llutants. 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 att ach 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 DETER MINING 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 po llutants. 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 att ach 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 DETER MINING 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 Ve nt Filter
9. List the pollutants to be controlled by this equipment and th e expected control efficiency for each pollutant on the table b elow. 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 ret urned to the Biomass fuels day bins, or it will be disposed of in a landfill.

11. Pressure drop across the filter (inches of H 2 O):

12. Prepare a malfunction prevention and abatement plan (if re quired 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 de tect a malfunction or breakthrough, the correct operating range of these variables, and a detailed description of monitoring or su rveillance 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/ft 2 ):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 po llutants. 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 att ach 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 DETER MINING 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 po llutants. 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 att ach a flow diagram of the process).

This is the CFB Boiler bed material silo bin vent s. Please refer to th e 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 DETER MINING 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 Ve nt Filter
9. List the pollutants to be controlled by this equipment and th e expected control efficiency for each pollutant on the table b elow. 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 H 2 O):

12. Prepare a malfunction prevention and abatement plan (if re quired 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 de tect a malfunction or breakthrough, the correct operating range of these variables, and a detailed description of monitoring or su rveillance 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/ft 2 ):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 po llutants. 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 att ach 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 DETER MINING 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 Ve nt Filter
9. List the pollutants to be controlled by this equipment and th e expected control efficiency for each pollutant on the table b elow. 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 H 2 O):

12. Prepare a malfunction prevention and abatement plan (if re quired 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 de tect a malfunction or breakthrough, the correct operating range of these variables, and a detailed description of monitoring or su rveillance 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/ft 2 ):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 po llutants. 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 att ach 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 DETER MINING 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 po llutants. 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 coo ling 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 att ach 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 DETER MINING 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 po llutants. 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 En gine 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 att ach 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 DETER MINING 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 po llutants. 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 applicatio n 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/PM 10 ) n/a 131
Particulate Matter (PM 2.5 ) 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