# Application for a Permit to Construct and Operate an Integrated Steel Plant

Volume II Appendix C Best Available Control Technology Review

Prepared for Minnesota Steel Industries, LLC Nashwauk, Minnesota

May 2007

# Application for a Permit to Construct and Operate an Integrated Steel Plant

Volume II Appendix C Best Available Control Technology Review

Prepared for Minnesota Steel Industries, LLC

May 2007

4700 West 77 th 

## Street M

inneapolis, MN 55435-4803
P hone: (952) 832-2600
F ax: ( 952 ) 832-2601

## Minnesota Steel Page - 

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# Minnesota Steel Industries Best Available Contro l Technology Review

Table of Contents

1.0 Executive Summary.............................................................................................................. ................1

2.0 Introduction................................................................................................................... ......................11

3.0 Methodology.................................................................................................................... ...................12 3.1 PSD Applicability .............................................................................................................. .......12 3.2 BACT Methodology ............................................................................................................... ..13 3.3 Emission Limits ................................................................................................................ ........15 3.4 Emission Units and Pollutants .................................................................................................. 16 3.5 Identification of Applicable Standards unde r 40 CFR Parts 60 (NSPS), 61 (NESHAP), and 63 (NESHAP/MACT).................................................................................................................. ..18 3.5.1 40 CFR 60 Subpart Dc, Standards of Perfo rmance for Small Industrial-CommercialInstitutional Steam Generating Units........................................................................... 19 3.5.2 Subpart LL, Standards of Performance for Metallic Mineral Processing .................... 19 3.5.3 Subpart AAa, Standards of Performance fo r Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels C onstructed After August 17, 1983 ............ 20 3.5.4 40 CFR Part 60 Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion Engines......................................................................... 21 3.5.5 Subpart RRRRR, National Emission Standards for Hazardous Air Pollutants: Taconite Iron Ore Processing ...................................................................................... 22 3.5.6 Subpart DDDDD, National Emission Standards for Hazardous Air Pollutants: Industrial, Commercial, and Institutio nal Boilers and Process Heaters....................... 22

4.0 Emission Control Technologies.................................................................................................. ........24 4.1 Overview of Emission Control Technologies...........................................................................24 4.2 Particulate Matter (PM & PM 10 

# ), Fluoride (F-), Particulate, and Lead (Pb) Emission Control Technologies................................................................................................................... ..........24 4.2.1 Fabric Filter.................................................................................................................. 26 4.2.2 Electrostatic Precipitators (ESP).................................................................................. 27 4.2.3 Wet Electrostatic Precipitators (WESP) ...................................................................... 28 4.2.4 Wet Scrubbers.............................................................................................................. 28 4.2.5 Mechanical Collectors ................................................................................................. 29 4.2.6 Good Design Methods and Operating Practices .......................................................... 30 4.3 Visible Emissions.............................................................................................................. ........30 4.4 Sulfur Dioxide (SO 2 

# ), Sulfuric Acid Mist and Gaseous Fluoride Emission Control Technologies................................................................................................................... ..........31 4.4.1 Flue Gas Desulfurization (FGD).................................................................................. 31 4.4.2 Dry Scrubbing - Lime/Limestone Injection ................................................................. 31 4.4.3 Dry Scrubbing - Spray Dryer Absorption .................................................................... 31 4.4.4 Wet Lime/Limestone Scrubbing .................................................................................. 32 4.4.5 Good Design Methods and Operating Practices .......................................................... 32 4.5 Nitrogen Oxides (NO
x 

# ) Emission Control Technologies..........................................................32 4.5.1 Sources of NOx Emissions .......................................................................................... 32 4.5.2 Identification of NO
x 

# Control Technologies................................................................ 33

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# 4.6 Carbon Monoxide (CO) and Volatile Or ganic Compound (VOC) Emission Control Technologies................................................................................................................... ..........39 4.6.1 Catalytic Incineration................................................................................................... 39 4.6.2 Thermal Oxidation....................................................................................................... 39 4.6.3 Good Design Methods and Operating Practices .......................................................... 40 4.7 Hydrogen Sulfide (H 2 

# S) Emission Control Technologies ........................................................40 4.7.1 Sulfur Recovery - LoCAT............................................................................................ 41 4.7.2 Absorption – Zinc Oxide ............................................................................................. 41 4.7.3 Oxidation...................................................................................................................... 41 4.7.4 Flue Gas Desulfurization (FGD) Following Oxidation ............................................... 42 4.8 Compliance with BACT during Startu p, Shutdown and Malfunction......................................42

5.0 Mining and Crushing ............................................................................................................ ..............44 5.1 Overview of Mining and Crushing ...........................................................................................44 5.2 Mining and Crushing Material Handling Process and Emission Description...........................44 5.2.1 BACT Selection Summary for Mining and Crushing Material Handling ................... 45 5.3 Fugitive Dust Emissions ........................................................................................................ ...45 5.3.1 BACT Selection Summary of Mining and Crushing Operations Fugitive Emissions. 45

6.0 Concentrator ................................................................................................................... ....................46 6.1 Concentrator Plant Overview.................................................................................................... 46 6.2 Ore Concentrator Material Handling Process and Emission Description.................................46 6.2.1 BACT Selection Summary for Crushed Ore Material Handling ................................. 47 6.2.2 BACT Selection Summary for Material Ha ndling in Ore Concentrator Plant ............ 47 6.3 Ore Concentrator Fugitive Dust Emissions ..............................................................................47 6.3.1 BACT Selection Summary for Ore Concentrator Fugitive Dust Emissions................ 47

7.0 Pelletizer ..................................................................................................................... ........................48 7.1 Pellet Plant Overview .......................................................................................................... .....48 7.2 Indurating Furnace Process and Emission Description.............................................................48 7.3 Pellet Plant Control Selection Considerations ..........................................................................51 7.4 Pellet Plant Particulate Matter (PM and PM 10 

# ) Emissions........................................................52 7.4.1 Sources of Induration Furnace Particulate Matter Emissions ...................................... 52 7.4.2 Identification of Potential PM/PM 10 

# Control Technologies......................................... 52 7.4.3 Elimination of Technically Infeasible PM/PM 10 

# Control Options............................... 52 7.4.4 Evaluation of Most Effective Control Technologies ................................................... 54 7.4.5 Pellet Plant Indurating Furnace PM/PM 10 

# BACT Selection ........................................ 56
7.5 Pellet Plant Visible Emissions ................................................................................................. .57 7.5.1 Pellet Plant Visible Emissions BACT Selection.......................................................... 58 7.6 Pellet Plant Sulfur Dioxides (SO 2 

# ) Emissions ..........................................................................58 7.6.1 Sources of Induration Furnace SO 2 

# Emissions ............................................................ 58 7.6.2 Identification of Potential SO 2 

# Control Technologies ................................................. 59 7.6.3 Elimination of Technically Infeasible SO 2 

# Control Options........................................ 59 7.6.4 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness.............. 61 7.6.5 Evaluation of Most Effective SO 2 

# Control Technologies ............................................ 61 7.6.6 Pellet Plant Indurating Furnace SO 2 

# BACT Selection................................................. 63
7.7 Pellet Plant Nitrogen Oxides (NO
x 

# ) Emissions.........................................................................64 7.7.1 Sources of Induration Furnace NO
x 

# Emissions............................................................ 64 7.7.2 Identification of Potential NO
x 

# Control Technologies................................................. 64 7.7.3 Elimination of Technically Infeasible NO
x 

# Control Options....................................... 65 7.7.4 Ranking of Remaining NO
x 

# Control Technologies by Control Effectiveness............. 72
7.7.5 Evaluation of Most Effective NO
x 

# Control Technologies ........................................... 72

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# 7.7.6 Pellet Plant Indurating Furnace NO
x 

# BACT Selection ................................................ 73
7.7.7 NOx Emission Control Technology Testing................................................................ 73 7.8 Pellet Plant Carbon Monoxide (CO) Emissions .......................................................................76 7.8.1 Sources of Induration Furnace CO Emissions ............................................................. 76 7.8.2 Identification of Potential CO Control Technologies .................................................. 76 7.8.3 Elimination of Technically Infeasible CO Control Options ........................................ 77 7.8.4 Ranking of Remaining CO Control Technologies by Control Effectiveness .............. 79 7.8.5 Evaluation of Most Effective CO Control Technologies............................................. 79 7.8.6 Pellet Plant Indurating Furnace CO BACT Selection.................................................. 80 7.8.7 Sources of Induration Furnace VOC Emissions .......................................................... 81 7.8.8 Identification of Potential VOC Control Technologies ............................................... 81 7.8.9 Elimination of Technically Infeasible VOC Control Options...................................... 81 7.8.10 Ranking of Remaining VOC Control Technologies by Control Effectiveness ........... 83 7.8.11 Evaluation of Most Effective VOC Control Technologies .......................................... 83 7.8.12 Pellet Plant Indurating Furnace VOC BACT Selection............................................... 84 7.9 Fluoride (F) Emissions......................................................................................................... .....85 7.9.1 Sources of Induration Furnace Fluoride Emissions ..................................................... 85 7.9.2 Identification of Potential Fluoride Control Technologies .......................................... 85 7.9.3 Elimination of Technically Infeasible Fluoride Control Options................................. 85 7.9.4 Ranking of Remaining Fluoride Control Technologies by Control Effectiveness ...... 87 7.9.5 Evaluation of Most Effective Fluoride Control Technologies..................................... 88 7.9.6 Pellet Plant Indurating Furnace Fluoride BACT Selection.......................................... 89 7.10 Pellet Plant Sulfuric Acid Mist Emissions................................................................................90 7.10.1 Sources of Induration Furnace Sulfuric Acid Mist Emissions..................................... 90 7.10.2 Identification of Potential Sulfuric Acid Mist Control Technologies.......................... 90 7.10.3 Elimination of Technically Infeasible Sulfuric Acid Mist Control Options ................ 91 7.10.4 Ranking of Remaining Sulfuric Acid Mist Control Technologies by Control Effectiveness................................................................................................................ 92 7.10.5 Evaluation of Most Effective Sulfuric Acid Mist Control Technologies..................... 93 7.10.6 Pellet Plant Indurating Furnace Sulfuric Acid Mist BACT Selection ......................... 94 7.11 Pellet Plant Lead (Pb) Emissions..............................................................................................9 5 7.11.1 Sources of Induration Furnace Lead Matter Emissions ............................................... 95 7.11.2 Identification of Potential Pb Control Technologies.................................................... 95 7.11.3 Elimination of Technically Infeasible Pb Control Options.......................................... 96 7.11.4 Ranking of Remaining Pb Control Technologies by Control Effectiveness................ 97 7.11.5 Evaluation of Most Effective Control Technologies ................................................... 98 7.11.6 Pellet Plant Indurating Furnace Pb BACT Selection ................................................... 99 7.12 Combined Control Selection Considerations and Costs .........................................................100 7.13 Pellet Plant Material Handling BACT Selection Summary....................................................103 7.14 Additive Material Handling ....................................................................................................1 04 7.14.1 Process Description.................................................................................................... 104 7.14.2 Summary of BACT for Additive Handling in the Pellet Plant .................................. 104 7.15 Pellet Plant Fugitive Dust Emissions BACT Selection Summary ..........................................104

8.0 Direct Reduced Iron Plant...................................................................................................... ...........106 8.1 Direct Reduced Iron Plant Overview......................................................................................106 8.1.1 Direct Reduced Iron (DRI) Plant ............................................................................... 106 8.2 DRI Packag e Boiler ............................................................................................................. ...110 8.3 DRI Boiler Particulate MatterPM/PM 10 

# Emission..................................................................110 8.3.1 Identification of Potential PM/PM 10 

# Control Technologies....................................... 110 8.3.2 Elimination of Technically Infeasible PM/PM 10 

# Control Options ............................. 110

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# 8.3.3 Rank Remaining PM/PM 10 

# Control Technologies by Control Effectiveness ............ 112 8.3.4 Evaluation of Most Effective PM Control Technologies........................................... 112 8.3.5 DRI Boiler PM/PM 10 

# BACT Selection ...................................................................... 112 8.4 DRI Package Boiler Vi sible Emissions ..................................................................................114 8.4.1 DRI Package Boiler Visible Emissions BACT Selection.......................................... 114 8.5 DRI Boiler Sulfur Dioxide (SO 2 

# ) emission.............................................................................115 8.5.1 Identification of Potential SO 2 

# Control Technologies ............................................... 115 8.5.2 Elimination of Technically Infeasible SO 2 

# Control Options...................................... 115 8.5.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness............ 116 8.5.4 Evaluation of Most Effective SO 2 

# Control Technologies .......................................... 117 8.5.5 DRI Boiler SO 2 

# BACT Selection............................................................................... 117 8.6 DRI Boiler Nitrogen Oxides (NO
x 

# ) Emissions .......................................................................118 8.6.1 Elimination of Technically Infeasible NO
x 

# Control Options..................................... 118 8.6.2 Ranking of Remaining NO
x 

# Control Technologies by Control Effectiveness........... 120 8.6.3 Evaluation of Most Effective NO
x 

# Control Technologies ......................................... 121 8.6.4 DRI Boiler NO
x 

# BACT Selection .............................................................................. 122 8.7 DRI Boiler Carbon Monoxide (CO) Emissions......................................................................124 8.7.1 Identification of Potential CO Control Technologies ................................................ 124 8.7.2 Elimination of Technically Infeasible CO Control Options ...................................... 124 8.7.3 Ranking of Remaining CO Control Technologies by Control Effectiveness ............ 125 8.7.4 Evaluation of Most Effective CO Control Technologies........................................... 126 8.7.5 DRI Boiler CO BACT Selection................................................................................ 126 8.8 DRI Boiler Volatile Organic compound (VOC) Emissions....................................................127 8.8.1 Identification of Potential VOC Control Technologies ............................................. 128 8.8.2 Elimination of Technically Infeasible VOC Control Options.................................... 128 8.8.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness ......... 129 8.8.4 Evaluation of Most Effective VOC Control Technologies ........................................ 129 8.8.5 DRI Boiler VOC BACT Selection............................................................................. 129 8.9 DRI Process Heaters ............................................................................................................ ...131 8.10 DRI Process Heater Particulate Matter (PM/PM 10 

# ) Emissions...............................................131 8.10.1 Identification of Potential PM/PM 10 

# Control Technologies....................................... 131 8.10.2 Elimination of Technically Infeasible PM/PM 10 

# Control Options............................. 132 8.10.3 Ranking of Remaining PM/PM 10 

# Control Technologies by Control Effectiveness ... 134 8.10.4 Evaluation of Most Effective Control Technologies ................................................. 134 8.10.5 DRI Process Heater PM/PM 10 

# BACT Selection ........................................................ 135 8.11 DRI Process Heater Visible Emissions...................................................................................136 8.11.1 DRI Process Heater Visible Em issions BACT Selection .......................................... 136 8.12 DRI Process Heater Sulfur Dioxide (SO 2 

# ) Emissions.............................................................136 8.12.1 Identification of Potential SO 2 

# Control Technologies ............................................... 136 8.12.2 Elimination of Technically Infeasible SO 2 

# Control Options...................................... 137 8.12.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness............ 138 8.12.4 Evaluation of Most Effective DRI Process Heater SO 2 

# Control Technologies.......... 139 8.12.5 DRI Process Heater SO 2 

# BACT Selection ................................................................. 139 8.13 DRI Process Heater Nitrogen Oxides (NOx) Emissions.........................................................140 8.13.1 Identification of Potential NOx Control Technologies .............................................. 140 8.13.2 Elimination of Technically Infeasible NOx Control Options .................................... 141 8.13.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness .......... 143 8.13.4 Evaluation of Most Effective NOx Control Technologies......................................... 144 8.13.5 DRI NOx BACT Selection ........................................................................................ 145

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# 8.14 DRI Process Heater Carbon Monoxide (CO) Emissions ........................................................148 8.14.1 Identification of Potential CO Control Technologies ................................................ 148 8.14.2 Elimination of Technically Infeasible CO Control Options ...................................... 148 8.14.3 Ranking of Remaining CO Control Technologies by Control Effectiveness ............ 149 8.14.4 Evaluation of Most Effective CO Control Technologies........................................... 149 8.14.5 DRI CO BACT Selection........................................................................................... 150 8.15 DRI Process Heater Volatile Organic Compound (VOC) Emissions.....................................152 8.15.1 Identification of Potential VOC Control Technologies ............................................. 152 8.15.2 Elimination of Technically Infeasible VOC Control Options.................................... 152 8.15.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness ......... 153 8.15.4 Evaluation of Most Effective VOC Control Technologies ........................................ 153 8.15.5 DRI VOC BACT Selection........................................................................................ 154 8.16 DRI Process Heater Fluoride (F) Emissions...........................................................................155 8.16.1 Identification of Potential Fluoride Control Technologies ........................................ 155 8.16.2 Elimination of Technically Infeasible Fluoride Control Options............................... 156 8.16.3 Ranking of Remaining Fluoride Control Technologies by Control Effectiveness .... 157 8.16.4 Evaluation of Most Effective Fluoride Control Technologies................................... 158 8.16.5 DRI Fluoride BACT Selection................................................................................... 158 8.17 DRI Process Heater Lead (Pb) Emissions...............................................................................159 8.17.1 Identification of Potential Pb Control Technologies.................................................. 159 8.17.2 Elimination of Technically Infeasible Pb Control Options........................................ 159 8.17.3 Ranking of Remaining Pb Control Technologies by Control Effectiveness .............. 161 8.17.4 Evaluation of Most Effective Control Technologies ................................................. 161 8.17.5 DRI Pb BACT Selection............................................................................................ 161 8.18 DRI Top Gas Purification System ..........................................................................................162 8.19 DRI Top Gas Purification Hydrogen Sulfide (H 2 

# S) Emissions ..............................................163 8.19.1 Identification of Potential H 2 

# S Control Technologies ............................................... 163 8.19.2 Elimination of Technically Infeasible H 2 

# S Control Options...................................... 163 8.19.3 Ranking of Remaining H 2 

# S Control Technologies by Control Effectiveness............ 164 8.19.4 Evaluation of Most Effective H 2 

# S Control Technologies .......................................... 165 8.19.5 DRI Top Gas Purification H 2 

# S BACT Selection........................................................ 165 8.20 Pneumatic Transport System (PTS) Gas Heaters ...................................................................166 8.21 PTS Gas Heater Particulate MatterPM/PM 10 

# Emission ..........................................................166 8.21.1 Identification of Potential PM/PM 10 

# Control Technologies....................................... 166 8.21.2 Elimination of Technically Infeasible PM/PM 10 

# Control Options ............................. 167 8.21.3 Evaluation of Most Effective PM Control Technologies........................................... 169 8.21.4 PTS Gas Heater PM/PM 10 

# BACT Selection .............................................................. 169 8.22 PTS Heater Visible Emissions ................................................................................................171 8.22.1 PTS Heater Visible Emissions BACT Selection........................................................ 171 8.23 PTS Heater Sulfur Dioxide (SO 2 

# ) emissions ..........................................................................172 8.23.1 Identification of Potential SO 2 

# Control Technologies ............................................... 172 8.23.2 Elimination of Technically Infeasible SO 2 

# Control Options...................................... 172 8.23.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness............ 173 8.23.4 Evaluation of Most Effective SO 2 

# Control Technologies .......................................... 174 8.23.5 PTS Gas Heater SO 2 

# BACT Selection....................................................................... 174 8.24 PTS Gas Heater Nitrogen Oxides (NOx) Emissions ..............................................................175 8.24.1 Elimination of Technically Infeasible NOx Control Options .................................... 176 8.24.2 Ranking of Remaining NOx Control Technologies by Control Effectiveness .......... 177 8.24.3 Evaluation of Most Effective NOx Control Technologies......................................... 178 8.24.4 PTS Gas Heater NOx BACT Selection...................................................................... 179

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# 8.25 PTS Gas Heater Carbon Monoxide (CO) Emissions ..............................................................181 8.25.1 Identification of Potential CO Control Technologies ................................................ 181 8.25.2 Elimination of Technically Infeasible CO Control Options ...................................... 181 8.25.3 Ranking of Remaining CO Control Technologies by Control Effectiveness ............ 182 8.25.4 Evaluation of Most Effective CO Control Technologies........................................... 183 8.25.5 PTS Gas Heater CO BACT Selection........................................................................ 183 8.26 PTS Gas Heater Volatile Organic compound (VOC) Emissions............................................184 8.26.1 Identification of Potential VOC Control Technologies ............................................. 185 8.26.2 Elimination of Technically Infeasible VOC Control Options.................................... 185 8.26.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness ......... 186 8.26.4 Evaluation of Most Effective VOC Control Technologies ........................................ 186 8.26.5 PTS Gas Heater VOC BACT Selection..................................................................... 186 8.27 DRI Cooling Towers............................................................................................................. ..188 8.27.1 Process Description.................................................................................................... 188 8.27.2 Cooling Water Blowdown Vents Description/Emissions.......................................... 188 8.27.3 Identification of Potential Cooling Towe r Blowdown Vent Control Technologies .. 189 8.27.4 Elimination of Technically Infeasible Cooling Tower Blowdown Vents Control Options ...................................................................................................................... 18 9 8.27.5 Ranking of Remaining Cooling Tower Bl owdown Vents Control Technologies by Control Effectiveness ................................................................................................ 189 8.27.6 Evaluation of Most Effective Cooling To wer Blowdown Vents Control Technologies190 8.27.7 Cooling Tower Blowdown Vents BACT Selection................................................... 190 8.28 DRI Material Handling .......................................................................................................... .191 8.28.1 DRI Material Handling Process Description ............................................................. 191 8.28.2 BACT Summary for DRI Plant Material Handling ................................................... 191 8.29 Fugitive Dust Emissions ........................................................................................................ .192 8.29.1 DRI Fugitive Dust Pr ocess Description ..................................................................... 192 8.29.2 Summary of Fugitive Emissions BACT .................................................................... 192

9.0 Steel Mill ..................................................................................................................... .....................193 9.1 Steel Mill Overview............................................................................................................ ....193 9.2 Electric Arc Furnace (EAF) and Ladle Metallurgy Furnaces .................................................193 9.2.1 Process Description.................................................................................................... 193 9.3 EAF Particulate Matter (PM and PM 10 

# ) Emissions ................................................................197 9.3.1 Identification of Potential PM/PM 10 

# Control Technologies....................................... 198 9.3.2 Elimination of Technically Infeasible PM/PM 10 

# Control Options ............................. 198 9.3.3 Rank Remaining PM/PM 10 

# Control Technologies by Control Effectiveness ............ 200 9.3.4 Evaluation of Most Effective PM/PM 10 

# Control Technologies.................................. 200 9.3.5 EAF PM/PM 10 

# BACT Selection................................................................................. 201 9.4 EAF Visible Emissions.......................................................................................................... .203 9.4.1 EAF Visible Emissions BACT Selection................................................................... 203 9.5 EAF Sulfur Dioxide (SO 2 

# ) Emissions.....................................................................................204 9.5.1 Identification of Potential SO 2 

# Control Technologies ............................................... 204 9.5.2 Elimination of Technically Infeasible SO 2 

# Control Options...................................... 204 9.5.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness............ 206 9.5.4 Evaluation of Most Effective SO 2 

# Control Technologies .......................................... 206 9.5.5 EAF SO 2 

# BACT Selection ......................................................................................... 207 9.6 EAF Nitrogen Oxides (NOx) Emissions.................................................................................210 9.6.1 Identification of Potential NOx Control Technologies .............................................. 210 9.6.2 Elimination of Technically Infeasible NOx Control Options .................................... 210 9.6.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness .......... 216

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# 9.6.4 Evaluation of Most Effective NOx Control Technologies......................................... 217 9.6.5 EAF NOx BACT Selection........................................................................................ 217 9.7 EAF Carbon Monoxide (CO) Emissions ................................................................................221 9.7.1 Identification of Potential CO Control Technologies ................................................ 221 9.7.2 Elimination of Technically Infeasible CO Control Options ...................................... 222 9.7.3 Ranking of Remaining CO Control Technologies by Control Effectiveness ............ 224 9.7.4 Evaluation of Most Effective CO Control Technologies........................................... 224 9.7.5 EAF CO BACT Selection.......................................................................................... 225 9.8 EAF Volatile Organic Compound (VOC) Emissions .............................................................229 9.8.1 Identification of Potential VOC Control Technologies ............................................. 229 9.8.2 Elimination of Technically Infeasible VOC Control Options.................................... 229 9.8.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness ......... 231 9.8.4 Evaluation of Most Effective VOC Control Technologies ........................................ 232 9.8.5 EAF VOC BACT Selection ....................................................................................... 232 9.9 EAF Fluoride (F) Emissions ...................................................................................................23 5 9.9.1 Identification of Fluoride Control Technologies........................................................ 235 9.9.2 Elimination of Technically Infeasible Fluoride Control Options............................... 235 9.9.3 Ranking of Remaining Fluoride Control Technologies by Control Effectiveness .... 237 9.9.4 Evaluation of Most Effective Fluoride Control Technologies................................... 238 9.9.5 EAF Fluoride BACT Selection.................................................................................. 238 9.10 EAF Sulfuric Acid Mist (SAM) Emissions ............................................................................239 9.10.1 Identification of Potential SAM Control Technologies ............................................. 239 9.10.2 Elimination of Technically Infeasible SAM Control Options ................................... 240 9.10.3 Flue Gas Desulfurization ........................................................................................... 240 9.10.4 Ranking of Remaining SAM Control Technologies by Control Effectiveness ......... 241 9.10.5 Evaluation of Most Effective SAM Control Technologies........................................ 241 9.10.6 EAF SAM BACT Selection....................................................................................... 242 9.11 EAF Lead (Pb) Emissions.......................................................................................................2 43 9.11.1 Identification of Potential Pb Control Technologies.................................................. 243 9.11.2 Elimination of Technically Infeasible Pb Control Options ........................................ 244 9.11.3 Rank Remaining Pb Control Technologies by Control Effectiveness ....................... 245 9.11.4 Evaluation of Most Effective Pb Control Technologies............................................. 246 9.11.5 EAF Pb BACT Selection............................................................................................ 247 9.12 Ladle/Tundish Preheaters....................................................................................................... .248 9.12.1 Process Descriptions .................................................................................................. 248 9.12.2 Ladle/Tundish Preheater Emissions........................................................................... 248 9.12.3 Identification of Potential Ladle/Tundi sh Pre-heater Control Technologies ............. 249 9.12.4 Elimination of Technically Infeasible Ladle/Tundish Pre-heater Control Options ... 249 9.12.5 Ranking of Remaining Ladle/Tundish Pre-heater Control Technologies by Control Effectiveness.............................................................................................................. 250 9.12.6 Evaluation of Most Effective Ladle/Tundish Pre-heater Control Technologies........ 251 9.12.7 Ladle/Tundish Preheaters BACT Selection ............................................................... 252 9.13 Vacuum Degasser ................................................................................................................ ...254 9.13.1 Vacuum Degasser Process Description...................................................................... 254 9.14 Vacuum Degasser CO Emissions Control ..............................................................................254 9.14.1 Identification of Potential CO Control Technologies ................................................ 254 9.14.2 Elimination of Technically Infeasible CO Control Options ...................................... 255 9.14.3 Ranking of Remaining CO Control Technologies by Control Effectiveness ............ 256 9.14.4 Evaluation of Most Effective CO Control Technologies........................................... 256 9.14.5 Vacuum Degasser CO BACT Selection .................................................................... 256

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# 9.15 Vacuum Degasser Boiler ........................................................................................................2 57 9.16 Vacuum Degasser Boiler Particulate MatterPM/PM 10 

# Emission............................................257 9.16.1 Identification of Potential PM/PM 10 

# Control Technologies....................................... 257 9.16.2 Elimination of Technically Infeasible PM/PM 10 

# Control Options ............................. 258 9.16.3 Rank Remaining PM/PM 10 

# Control Technologies by Control Effectiveness ............ 259 9.16.4 Evaluation of Most Effective PM Control Technologies........................................... 259 9.16.5 Vacuum Degasser Boiler PM/PM 10 

# BACT Selection................................................ 260 9.17 Vacuum Degasser Boiler Visible Emissions ..........................................................................262 9.17.1 Vacuum Degasser Package Boiler Visible Emissions BACT Selection.................... 262 9.18 Vacuum Degasser Boiler Sulfur Dioxide (SO2) emission......................................................263 9.18.1 Identification of Potential SO 2 

# Control Technologies ............................................... 263 9.18.2 Elimination of Technically Infeasible SO 2 

# Control Options...................................... 263 9.18.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness............ 264 9.18.4 Evaluation of Most Effective SO 2 

# Control Technologies .......................................... 265 9.18.5 Vacuum Degasser Boiler SO 2 

# BACT Selection......................................................... 265 9.19 Vacuum Degasser Boiler Nitrogen Oxides (NOx) Emissions ................................................266 9.19.1 Elimination of Technically Infeasible NOx Control Options .................................... 267 9.19.2 Ranking of Remaining NOx Control Technologies by Control Effectiveness .......... 268 9.19.3 Evaluation of Most Effective NO
x 

# Control Technologies ......................................... 269 9.19.4 Vacuum Degasser Boiler NOx BACT Selection ....................................................... 270 9.20 Vacuum Degasser Boiler Carbon Monoxide (CO) Emissions................................................272 9.20.1 Identification of Potential CO Control Technologies ................................................ 272 9.20.2 Elimination of Technically Infeasible CO Control Options ...................................... 272 9.20.3 Ranking of Remaining CO Control Technologies by Control Effectiveness ............ 273 9.20.4 Evaluation of Most Effective CO Control Technologies........................................... 274 9.20.5 Vacuum Degasser Boiler CO BACT Selection ......................................................... 274 9.21 Vacuum Degasser Boiler Volatile Organic compound (VOC) Emissions .............................276 9.21.1 Identification of Potential VOC Control Technologies ............................................. 276 9.21.2 Elimination of Technically Infeasible VOC Control Options.................................... 276 9.21.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness ......... 277 9.21.4 Evaluation of Most Effective VOC Control Technologies ........................................ 278 9.21.5 Vacuum Degasser Boiler VOC BACT Selection....................................................... 278 9.22 Continuous Slab Casters ........................................................................................................ .279 9.22.1 Process Descriptions .................................................................................................. 279 9.22.2 Continuous slab Casters BACT Selection ................................................................. 280 9.23 Tunnel Furnace ................................................................................................................. ......280 9.23.1 Process Description.................................................................................................... 280 9.24 Tunnel Furnace Particulate Matter (PM/PM 10 

# ) Emissions .....................................................281 9.24.1 Identification of Potential PM Control Technologies ................................................ 281 9.24.2 Elimination of Technically Infeasible PM/PM 10 

# Control Options............................. 281 9.24.3 Ranking of Remaining PM/PM 10 

# Control Technologies by Control Effectiveness... 283 9.24.4 Evaluation of Most Effective PM/PM 10 

# Control Technologies ................................. 283 9.24.5 Tunnel Furnace PM/PM 10 

# BACT Selection............................................................... 283 9.25 Tunnel Furnace Visible Emissions .........................................................................................284 9.25.1 Tunnel Furnace Visible Emissions BACT Selection................................................. 284 9.26 Tunnel Furnace Sulfur Dioxide (SO 2 

# ) Emissions ...................................................................285 9.26.1 Identification of Potential SO 2 

# Control Technologies ............................................... 285 9.26.2 Elimination of Technically Infeasible SO 2 

# Control Options...................................... 285 9.26.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness............ 286 9.26.4 Evaluation of Most Effective SO 2 

# Control Technologies .......................................... 287

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# 9.26.5 Tunnel Furnace SO 2 

# BACT Selection........................................................................ 287 9.27 Tunnel Furnace Nitrogen Oxides (NO
x 

# ) Emissions................................................................288 9.27.1 Identification of Potential NOx Control Technologies .............................................. 288 9.27.2 Elimination of Technically Infeasible NOx Control Options .................................... 288 9.27.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness .......... 291 9.27.4 Evaluation of Most Effective NO
x 

# Control Technologies ......................................... 292 9.27.5 Tunnel Furnace NOx BACT Selection ...................................................................... 292 9.28 Tunnel Furnace Carbon Monoxide (CO) Emissions...............................................................294 9.28.1 Identification of Potential CO Control Technologies ................................................ 294 9.28.2 Elimination of Technically Infeasible CO Control Options ...................................... 294 9.28.3 Ranking of Remaining CO Control Technologies by Control Effectiveness ............ 295 9.28.4 Evaluation of Most Effective CO Control Technologies........................................... 295 9.28.5 Tunnel Furnace CO BACT Selection ........................................................................ 296 9.29 Tunnel Furnace Volatile Organic Compound (VOC) Emissions ...........................................297 9.29.1 Identification of Potential VOC Control Technologies ............................................. 297 9.29.2 Elimination of Technically Infeasible VOC Control Options.................................... 297 9.29.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness ......... 298 9.29.4 Evaluation of Most Effective VOC Control Technologies ........................................ 298 9.29.5 Tunnel Furnace VOC BACT Selection ..................................................................... 299 9.30 EAF Cooling Towers ............................................................................................................. .300 9.30.1 Process Description.................................................................................................... 300 9.31 Melt Shop Additive Material Handling ..................................................................................300 9.31.1 Process Description.................................................................................................... 300 9.31.2 Summary of BACT for Additive Handling in the Melt Shop.................................... 300 9.32 Fugitive Dust Emissions ........................................................................................................ .301 9.32.1 Process Description.................................................................................................... 301 9.32.2 Summary of Fugitive Emissions BACT .................................................................... 301

10.0 Slag Processing................................................................................................................ .................302 10.1 Slag Processing Overview ......................................................................................................3 02 10.1.1 Process Description.................................................................................................... 302 10.1.2 Summary of Fugitive Emissions BACT .................................................................... 302

11.0 Material Handling – Transfers of Ra w Materials Between Processes..............................................303 11.1 Raw Material Handling Process Description ..........................................................................303 11.2 Material Handling Particulate Matter (PM/PM 10 

# ) Emissions .................................................303 11.2.1 Identification of Potential PM/PM 10 

# Control Technologies....................................... 303 11.2.2 Elimination of Technically Infeasible PM/PM 10 

# Control Options ............................. 304 11.2.3 Ranking of Remaining PM/PM 10 

# Control Technologies by Control Effectiveness ... 305 11.2.4 Evaluation of Most Effective PM/PM 10 

# Control Technologies.................................. 305 11.2.5 Material Handling PM/PM 10 

# BACT Selection .......................................................... 306 11.3 Material Handling Visible Emissions .....................................................................................307 11.3.1 Material Handling Visible Emissions BACT Selection............................................. 308 11.4 Material Handling Fluoride (F-) Emissions............................................................................309 11.4.1 Identification of Potential F- Control Technologies .................................................. 309 11.4.2 Elimination of Technically Infeasible F- Control Options ........................................ 309 11.4.3 Ranking of Remaining F- Control Technologies by Control Effectiveness .............. 310 11.4.4 Evaluation of Most Effective F- Control Technologies............................................. 311 11.4.5 Material Handling F- BACT Selection ...................................................................... 312 11.5 Material Handling Lead (Pb) Emissions.................................................................................313 11.5.1 Identification of Potential Pb Control Technologies.................................................. 313

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# 11.5.2 Elimination of Technically Infeasible Pb Control Options........................................ 313 11.5.3 Ranking of Remaining Pb Control Technologies by Control Effectiveness.............. 315 11.5.4 Evaluation of Most Effective Pb Control Technologies ............................................ 315 11.5.5 Material Handling Pb BACT Selection ..................................................................... 316

12.0 Additive Material Handling..................................................................................................... .........318 12.1 Additive Material Handling Process Description ...................................................................318 12.2 Additive Material Handling Particulate Matter (PM) Emissions............................................318 12.2.1 Identification of Potential PM Control Technologies ................................................ 318 12.2.2 Elimination of Technically Infeasible PM Control Options ...................................... 318 12.2.3 Ranking of Remaining PM Control Technologies by Control Effectiveness ............ 320 12.2.4 Evaluation of Most Effective PM Control Technologies........................................... 320 12.2.5 Additive Material Handling PM BACT Selection..................................................... 321 12.3 Additive Material Handling Visible Emissions ......................................................................322 12.3.1 Additive Material Handling Visible Emissions BACT Selection.............................. 322 12.4 Additive Material Handling Fluoride (F-) Emissions .............................................................323 12.4.1 Identification of Potential F- Control Technologies .................................................. 323 12.4.2 Elimination of Technically Infeasible F- Control Options ........................................ 323 12.4.3 Ranking of Remaining F- Control Technologies by Control Effectiveness .............. 324 12.4.4 Evaluation of Most Effective F- Control Technologies............................................. 325 12.4.5 Additive Material Handling F- BACT Selection ....................................................... 326

13.0 Cooling Towers ................................................................................................................. ...............327 13.1 Cooling Tower Process Description .......................................................................................327 13.2 Cooling Towers Particulate Matter (PM) Emissions ..............................................................328 13.2.1 Identification of Potential PM Control Technologies ................................................ 328 13.2.2 Elimination of Technically Infeasible PM Control Options ...................................... 328 13.2.3 Ranking of Remaining PM Control Technologies by Control Effectiveness ............ 328 13.2.4 Evaluation of Most Effective PM Control Technologies........................................... 328 13.2.5 Cooling Towers PM BACT Selection ....................................................................... 328 13.3 Cooling Tower Visible Emissions ..........................................................................................329 13.3.1 Cooling Tower Visible Emissions BACT Selection.................................................. 329

14.0 Emergency Generators & Pumps................................................................................................... ...331 14.1 Emergency Generators and Pumps Overview.........................................................................331 14.2 Emergency Generators and Pumps Particul ate Matter (PM) Emission Controls....................332 14.2.1 Identification of Potential PM Control Technologies ................................................ 332 14.2.2 Elimination of Technically Infeasible PM Control Options ...................................... 332 14.2.3 Ranking of Remaining PM Control Technologies by Control Effectiveness ............ 333 14.2.4 Evaluation of Most Effective PM Control Technologies and Documentation of Results334 14.2.5 Emergency Generators and Pu mps PM BACT Selection.......................................... 334 14.3 Emergency Generators and Pumps Visible Emissions ...........................................................334 14.3.1 Emergency Generators and Pumps Visi ble Emissions BACT Selection................... 334 14.4 Emergency Generators and Pumps SO 2 

# Emission Controls ...................................................335 14.4.1 Identification of Potential SO 2 

# Control Technologies ............................................... 335 14.4.2 Elimination of Technically Infeasible SO 2 

# Control Options...................................... 335 14.4.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness............ 336 14.4.4 Evaluation of Most Effective SO 2 

# Control Technologies and Document Results ..... 336 14.4.5 Emergency Generators and Pumps SO 2 

# BACT Selection.......................................... 337 14.5 Emergency Generators NO
x 

# Emission Controls .....................................................................337 14.5.1 Identification of Potential NO
x 

# Control Technologies............................................... 337 14.5.2 Elimination of Technically Infeasible NOx Control Options .................................... 338

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# 14.5.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness .......... 338 14.5.4 Evaluation of Most Effective NOx Contro l Technologies and Document Results.... 339 14.5.5 Emergency Generators NO x BACT Selection........................................................... 339 14.6 Emergency Generators and Pumps VOC and CO Emission Controls....................................340 14.6.1 Identification of Potential VOC and CO Control Technologies ................................ 340 14.6.2 Elimination of Technically Infeasi ble VOC and CO Control Options ...................... 340 14.6.3 Ranking of Remaining VOC and CO Control Technologies by Control Effectiveness341 14.6.4 Evaluation of Most Effective VOC and CO Control Technologies and Documentation of Results ................................................................................................................... 34 1 14.6.5 Emergency Generators VOC a nd CO BACT Selection............................................. 341

15.0 Fugitive Dust .................................................................................................................. ..................343 15.1 Fugitive Dust Process Description..........................................................................................343 15.2 Fugitive Dust PM/PM 10 

# BACT Selection ...............................................................................343 15.3 Fugitive Dust Visible Emissions.............................................................................................344 15.3.1 Fugitive Dust Visible Emissions BACT Selection .................................................... 344 15.4 Fugitive Fluoride Dust (F-) BACT Selection .........................................................................345 15.5 Fugitive Lead (Pb) Dust BACT Selection ..............................................................................346

16.0 Insignificant Activities....................................................................................................... ...............347 16.1 Insignificant Activities Pr ocess Description ...........................................................................347 16.2 Insignificant Actives Addressed within the BACT Report.....................................................347 16.3 Insignificant Activities Requiring Review..............................................................................348

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# List of Tables

Table 1-1 Indurating Furnace BACT Analysis Summary..................................................................................... 1

Table 1-2 DRI Boiler BACT Analysis Summary ............................................................................................... .. 3

Table 1-3 DRI Process Heater BACT Analysis Summary.................................................................................... 3

Table 1-4 Top Gas Purification System BACT Analysis Summary ..................................................................... 4

Table 1-5 Pneumatic Transport System Gas H eater BACT Analys is Summary .................................................. 4

Table 1-6 DRI Cooling Water Blowdown Ve nts BACT Analys is Summary ....................................................... 4

Table 1-7 Melt Shop BACT Analysis Summary................................................................................................ ... 5

Table 1-8 Vacuum Degasser BACT Analysis Summary ...................................................................................... 6

Table 1-9 Tunnel Furnace BACT Analysis Summary .......................................................................................... 6

Table 1-10 Material Handling BACT Analysis Summaries ................................................................................... 7

Table 1-11 Additive Material Handling BACT Analysis Summaries..................................................................... 8

Table 1-12 Fugitive Dust BACT An alysis Summaries.......................................................................................... . 8

Table 1-13 DRI and Steel-Mill Cooling Towers BACT Analysis Summary.......................................................... 9

Table 1-14 Emergency Equipment Diesel Powe red Generators and Pumps ........................................................ 10

Table 3-1 Summary of Emission Units and PSD Pollutants Emitted ................................................................. 17

Table 3-2 NSPS Emission Limits for Meta llic Mineral Processing.................................................................... 20

Table 3-3 NSPS Emission Limits for Steel Plants .......................................................................................... .... 21

Table 3-4 NESHAP Emission Limits for Taconite Iron Ore Processing ............................................................ 22

Table 4-1 NOx Control Technology Co mpleteness Review............................................................................... 37

Table 7-1 Evaluation of Most Effective PM/PM 10 

# Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream ....................................................................................................... .......... 53

Table 7-2 Ranking of Remaining PM/PM 10 

# Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace................................................................................................ ........... 54

Table 7-3 Evaluation of Most Effective PM/PM 10 

# Control Technologies for the Pellet Plant Indurator Waste Gas Stream............................................................................................................... ................ 55

Table 7-4 Evaluation of Most Effective PM/PM 10 

# Control Technologies for the Pellet Plant Indurator Hood Exhaust Stream ............................................................................................................ ............. 55

Table 7-5 Technical Feasibility of SO 2 

# Control Technologies for Taconite Pellet Indurating Furnace.............. 60

Table 7-6 Ranking of Remaining SO 2 

# Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace....................................................................................................... .............. 61

Table 7-7 Evaluation of Most Effective SO 2 

# Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream ....................................................................................................... .......... 62

Table 7-8 Evaluation of Most Effective SO 2 

# Control Technologies for the Pellet Plant Indurating Hood Exhaust Stream ................................................................................................................. .................. 62

Table 7-9 Technical Feasibility of NO
x 

# Control Technologies for Taconite Pellet Indurating Furnace ............. 65

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# Table 7-10 Remaining NOx Control Technologies and Control Effectiveness for the Taconite Pellet Indurating Furnace............................................................................................................. ................. 72

Table 7-11 Evaluation of Most Effective NO
x 

# Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream ....................................................................................................... .......... 72

Table 7-12 Evaluation of Most Effective NO
x 

# Control Technologies for the Pellet Plant Indurator Hood Exhaust Stream ................................................................................................................. .................. 73

Table 7-13 Technical Feasibility of CO Control Technologies for Taconite Pellet Indurating Furnace............... 78

Table 7-14 Remaining CO Control Technologies and Cont rol Effectiveness for the Taconite Pellet Indurating Furnace............................................................................................................. ................. 79

Table 7-15 Evaluation of Most Effective CO Control T echnologies for the Taconite Pellet Indurating Furnace Waste Gas Stack ........................................................................................................ ........... 79

Table 7-16 Evaluation of Most Effective CO Control T echnologies for the Taconite Pellet Indurating Furnace Hood Exhaust........................................................................................................... ............. 80

Table 7-17 Technical Feasibility of VOC Control Technologies for Taconite Pellet Indurating Furnace............ 82

Table 7-18 Remaining VOC Control Technologies and Control Effectiveness for the Taconite Pellet Indurating Furnace............................................................................................................. ................. 83

Table 7-19 Evaluation of Most Effective VOC Control T echnologies for the Taconite Pellet Indurating Furnace Waste Gas Stack ........................................................................................................ ........... 83

Table 7-20 Evaluation of Most Effective VOC Control T echnologies for the Taconite Pellet Indurating Furnace Hood Exhaust........................................................................................................... ............. 84

Table 7-21 Technical Feasibility of Fluoride Control Technologies for Taconite Pellet Indurating
Furnace ........................................................................................................................ ....................... 86

Table 7-22 Ranking of Remaining Fluoride Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace................................................................................................ ........... 87

Table 7-23 Evaluation of Most Effective Fluoride Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream ....................................................................................................... .......... 88

Table 7-24 Evaluation of Most Effective Fluoride Control Technologies for the Pellet Plant Indurating Hood Exhaust Stream ............................................................................................................ ............. 89

Table 7-25 Technical Feasibility of Sulfuric Acid Mist Control Technologies for Taconite Pellet Indurating Furnace............................................................................................................. ................. 91

Table 7-26 Ranking of Remaining Sulfuric Acid Mist Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace ........................................................................................ ....... 93

Table 7-27 Evaluation of Most Effective Sulfuric Acid Mist Control Technologies for the Pellet Plant Indurating Furnace W aste Gas Stream ............................................................................................ ... 94

Table 7-28 Evaluation of Most Effective Sulfuric Acid Mist Control Technologies for the Pellet Plant Indurating Hood Exhaust Stream................................................................................................. ....... 94

Table 7-29 Evaluation of Most Effective Lead Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream ....................................................................................................... .......... 96

Table 7-30 Ranking of Remaining Lead Control Technolog ies and Control Effectiveness for the Pellet Plant Indurating Furnace....................................................................................................... .............. 97

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# Table 7-31 Evaluation of Most Effective Pb Control Technologies for the Pellet Plant Indurator Waste Gas Stream..................................................................................................................... ..................... 98

Table 7-32 Evaluation of Most Effective Pb Control Technologies for the Pellet Plant Indurator Hood Exhaust Stream ................................................................................................................. .................. 98

Table 7-33 Wet Scrubber/Absorber/LoTOx - Combined Pollutant Control Cost Summary .............................. 101

Table 8-1 Technical Feasibility of PM/PM 10 

# Control Technologies for the DRI Boilers................................. 111

Table 8-2 Ranking of Remaining PM/PM 10 

# Control Technologies for DRI Boilers ........................................ 112

Table 8-3 Evaluation of Most Effective PM/PM 10 

# Control Technologies for the DRI Boilers ........................ 112

Table 8-4 Technical Feasibility of SO 2 

# Control Technologies for the DRI Boilers.......................................... 116

Table 8-5 Ranking of Remaining SO 2 

# Control Technologies for the DRI Boilers ........................................... 116

Table 8-6 Evaluation of Most Effective SO 2 

# Control Technologies for the DRI Boilers ................................. 117

Table 8-7 Technical Feasibility of NO
x 

# Control Technologies for the DRI Boilers......................................... 119

Table 8-8 Ranking of Remaining NO
x 

# Control Technologies for the Tunnel Furnace..................................... 121

Table 8-9 Evaluation of Most Effective NO
x 

# Control Technologies for the DRI Boilers................................. 121

Table 8-10 Technical Feasibility of CO Control Technologies for the DRI Boilers .......................................... 125

Table 8-11 Ranking of Remaining CO Technologies for the DRI Boilers ......................................................... 125

Table 8-12 Evaluation of Most Effective CO Control Technologies for the DRI Boilers.................................. 126

Table 8-13 Technical Feasibility of VOC Control Technologies for the DRI Boilers........................................ 128

Table 8-14 Ranking of Remaining VOC Control Technologies for the DRI Boilers ......................................... 129

Table 8-15 Evaluation of Most Effective VOC Control Technologies for the DRI Boilers............................... 129

Table 8-16 Technical Feasibility of PM Control Technologies for DRI Process Heaters .................................. 133

Table 8-17 Remaining PM/PM 10 

# Control Technologies and Control Effectiveness for the DRI Process
Heaters ........................................................................................................................ ...................... 134

Table 8-18 Evaluation of Most Effective PM/PM 10 

# Control Technologies for the DRI Process Heaters .......... 134

Table 8-19 Technical Feasibility of SO 2 

# Control Technologies for DRI Process Heaters.................................. 138

Table 8-20 Remaining SO 2 

# Control Technologies and Control Effectiveness for the DRI Process
Heaters ........................................................................................................................ ...................... 138

Table 8-21 Evaluation of Most Effective SO 2 

# Control Technologies for the DRI Process Heaters ................... 139

Table 8-22 Technical Feasibility of NO
x 

# Control Technologies for the DRI Process Heaters ........................... 141

Table 8-23 Ranking of Remaining NO
x 

# Control Technologies for DRI Process Heaters .................................. 143

Table 8-24 Evaluation of Most Effective NOx Control Technologies for DRI Process Heaters........................ 144

Table 8-25 Technical Feasibility of CO Control Technologies for DRI Process Heaters .................................. 148

Table 8-26 Ranking of Remaining CO Control Technologies for DRI Process Heaters.................................... 149

Table 8-27 Evaluation of Most Effective CO Control Technologies for DRI Process Heaters.......................... 150

Table 8-28 Technical Feasibility of VOC Control Technologies for DRI Process Heaters................................ 153

Table 8-29 Ranking of Remaining VOC Control Technologies for DRI Process Heaters ................................. 153

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# Table 8-30 Evaluation of VOC Control Technologies for DRI Process Heaters................................................ 154

Table 8-31 Technical Feasibility of Fluoride Control Technologies for DRI Process Heaters .......................... 157

Table 8-32 Ranking of Remaining Fluoride Control Technologies for DRI Process Heaters............................ 157

Table 8-33 Evaluation of Most Effective Fluoride Cont rol Technologies for DRI Process Heaters.................. 158

Table 8-34 Technical Feasibility of Pb Control T echnologies for DRI Process Heaters.................................... 160

Table 8-35 Remaining Pb Control Technologies and Contro l Effectiveness for the DRI Process Heaters........ 161

Table 8-36 Evaluation of Most Effective Pb Control Technologies for the DRI Process Heaters ..................... 161

Table 8-37 Technical Feasibility of H 2 

# S Control Technologies for DRI Top Gas Purification.......................... 164

Table 8-38 Remaining H 2 

# SControl Technologies and Control Effectiveness for the DRI Top Gas Purification ................................................................................................................... .................... 165

Table 8-39 Evaluation of Most Effective H 2 

# S Control Technologies for the DRI Top Gas Purification ........... 165

Table 8-40 Technical Feasibility of PM/PM 10 

# Control Technologies for the PTS Gas Heaters......................... 167

Table 8-41 Ranking of Remaining PM/PM 10 

# Control Technologies for PTS Gas Heaters ................................ 169

Table 8-42 Evaluation of Most Effective PM/PM 10 

# Control Technologies for the PTS Gas Heaters ................ 169

Table 8-43 Technical Feasibility of SO 2 

# Control Technologies for the PTS Gas Heaters.................................. 173

Table 8-44 Ranking of Remaining SO 2 

# Control Technologies for the PTS Gas Heaters ................................... 173

Table 8-45 Evaluation of Most Effective SO 2 

# Control Technologies for the PTS Gas Heaters ......................... 174

Table 8-46 Technical Feasibility of NO
x 

# Control Technologies for the PTS Heater.......................................... 176

Table 8-47 Ranking of Remaining NO
x 

# Control Technologies for the PTS Gas Heaters................................... 178

Table 8-48 Evaluation of Most Effective NO
x 

# Control Technologies for the PTS Gas Heaters......................... 178

Table 8-49 Technical Feasibility of CO Control Technologies for the PTS Gas Heater .................................... 182

Table 8-50 Ranking of Remaining CO Technologies for the PTS Gas Heater................................................... 182

Table 8-51 Evaluation of Most Effective CO Control Technologies for the PTS Gas Heater............................ 183

Table 8-52 Technical Feasibility of VOC Control Technologies for the PTS Gas Heater ................................. 185

Table 8-53 Ranking of Remaining VOC Control Technologies for the PTS Gas Heater................................... 186

Table 8-54 Evaluation of Most Effective VOC Control Technologies for the PTS Gas Heater......................... 186

Table 8-55 Technical Feasibility of Emission Control Technologies for the Ladle and Tundish Preheaters..................................................................................................................... ..................... 189
Table 8-56 Ranking of Remaining Preheater Emission Control Technologies ..................................................... 190

Table 8-57 Evaluation of Most Effective Cooling Tower Blowdown Vent Emission Control Technologies................................................................................................................... .................. 190

Table 9-1 Technical Feasibility of PM/PM 10 

# Control Technologies for the Melt Shop ................................... 198

Table 9-2 Ranking of Remaining PM/PM 10 

# Control Technologies for Melt Shop........................................... 200

Table 9-3 Technical Feasibility of SO 2 

# Control Technologies for the Melt Shop ............................................ 205

Table 9-4 Ranking of Remaining SO 2 

# Control Technologies for Melt Shop.................................................... 206

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# Table 9-5 Evaluation of Most Effective SO 2 

# Control Technology for Melt Shop ............................................ 206

Table 9-6 Technical Feasibility of NOx Control Technologies for the Melt Shop........................................... 211

Table 9-7 Ranking of Remaining NO
x 

# Control Technologies for Melt Shop................................................... 216

Table 9-8 Evaluation of Most Effective NOx Control Technologies for Melt Shop ........................................ 217

Table 9-9 Technical Feasibility of CO Control Technologies for the Melt Shop ............................................. 222

Table 9-10 Ranking of Remaining CO Control Technologies for Melt Shop .................................................... 224

Table 9-11 Evaluation of Most Effective CO Control Technologies for Melt Shop .......................................... 225

Table 9-12 Technical Feasibility of VOC Control Technologies for the Melt Shop .......................................... 230

Table 9-13 Ranking of Remaining VOC Control Technologies for Melt Shop.................................................. 232

Table 9-14 Evaluation of Most Effective VOC Control Technologies for Melt Shop........................................ 232

Table 9-15 Technical Feasibility of Fluoride Control Technologies for the Melt Shop ..................................... 236

Table 9-16 Ranking of Remaining Fluoride Control Technologies for Melt Shop............................................. 237

Table 9-17 Technical Feasibility of SAM Control Technologies for the Melt Shop.......................................... 240

Table 9-18 Ranking of Remaining SAM Control Technologies for Melt Shop.................................................. 241

Table 9-19 Evaluation of Most Effective SAM Control Technologies for Melt Shop........................................ 242

Table 9-20 Technical Feasibility of Lead Control Technologies for the Melt Shop........................................... 244

Table 9-21 Ranking of Remaining Lead Control Technologies for Melt Shop .................................................. 246

Table 9-22 Technical Feasibility of Emission Control Technologies for the Ladle and Tundish Preheaters..................................................................................................................... ..................... 250
Table 9-23 Ranking of Remaining Preheater Emission Control Technologies ..................................................... 251

Table 9-24 Evaluation of Most Effective Ladle/Tundish Pre-heater Emission Control Technologies............... 252

Table 9-25 Technical Feasibility of CO Control Technologies for Vacuum Degasser....................................... 255

Table 9-26 Ranking of Remaining CO Control Technologies for the Vacuum Degasser Systems.................... 256

Table 9-27 Evaluation of Most Effective CO Control Technologies for Vacuum Degasser Boiler ................... 256

Table 9-28 Technical Feasibility of PM/PM 10 

# Control Technologies for the Vacuum Degasser Boiler ............ 258

Table 9-29 Ranking of Remaining PM/PM 10 

# Control Technologies for Vacuum Degasser Boiler ................... 259

Table 9-30 Evaluation of Most Effective PM/PM 10 

# Control Technologies for the Vacuum Degasser Boiler ......................................................................................................................... ....................... 259

Table 9-31 Technical Feasibility of SO2 Control Technologies for the Vacuum Degasser Boiler .................... 264

Table 9-32 Ranking of Remaining SO 2 

# Control Technologies for the Vacuum Degasser Boiler ...................... 264

Table 9-33 Evaluation of Most Effective SO 2 

# Control Technologies for the Vacuum Degasser Boiler ............ 265

Table 9-34 Technical Feasibility of NO
x 

# Control Technologies for the Vacuum Degasser Boiler .................... 267

Table 9-35 Ranking of Remaining NO
x 

# Control Technologies for the Vacuum Degasser Boiler...................... 269

Table 9-36 Evaluation of Most Effective NO
x 

# Control Technologies for the Vacuum Degasser Boiler ............ 269

Table 9-37 Technical Feasibility of CO Control Technologies for the Vacuum Degasser Boiler...................... 273

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# Table 9-38 Ranking of Remaining CO Technologies for the Vacuum Degasser Boiler .................................... 273

Table 9-39 Evaluation of Most Effective CO Control Tec hnologies for the Vacuum Degasser Boiler ............. 274

Table 9-40 Technical Feasibility of VOC Control Technologies for the Vacuum Degasser Boiler................... 277

Table 9-41 Ranking of Remaining VOC Control Technologies for the Vacuum Degasser Boiler .................... 277

Table 9-42 Evaluation of Most Effective VOC Control Tec hnologies for the Vacuum Degasser Boiler .......... 278

Table 9-43 Technical Feasibility of PM/PM 10 

# Control Technologies for the Tunnel Furnace........................... 282

Table 9-44 Ranking of Remaining PM/PM 10 

# Control Technologies for the Tunnel Furnace............................. 283

Table 9-45 Evaluation of Most Effective PM/PM 10 

# Control Technologies for the Tunnel Furnace .................. 283

Table 9-46 Technical Feasibility of SO 2 

# Control Technologies for the Tunnel Furnace.................................... 286

Table 9-47 Ranking of Remaining SO 2 

# Control Technologies for the Tunnel Furnace ..................................... 286

Table 9-48 Evaluation of Most Effective SO 2 

# Control Technologies for the Tunnel Furnace ........................... 287

Table 9-49 Technical Feasibility of NO
x 

# Control Technologies for the Tunnel Furnace ................................... 288

Table 9-50 Ranking of Remaining NO
x 

# Control Technologies for the Tunnel Furnace..................................... 292

Table 9-51 Evaluation of Most Effective NO
x 

# Control Technologies for the Tunnel Furnace........................... 292

Table 9-52 Technical Feasibility of CO Control Technologies for the Tunnel Furnace.................................... 295

Table 9-53 Ranking of Remaining CO Technologies for the Tunnel Furnace ................................................... 295

Table 9-54 Evaluation of Most Effective CO Control Technologies for the Tunnel Furnace ............................ 296

Table 9-55 Technical Feasibility of VOC Control Technologies for the Tunnel Furnace.................................. 298

Table 9-56 Ranking of Remaining VOC Control Technologies for the Tunnel Furnace ................................... 298

Table 9-57 Evaluation of Most Effective VOC Control Technologies for the Tunnel Furnace ......................... 299

Table 11-1 Technical Feasibility of PM/PM 10 

# Control Technologies for Material Handling............................. 304

Table 11-2 Ranking of Remaining PM/PM 10 

# Control Technologies for Material Handling............................... 305

Table 11-3 Evaluation of Most Effective PM/PM 10 

# Control Technologies for Pelletizer—Hearth Layer Bin Material Handling .......................................................................................................... ............ 306

Table 11-4 Evaluation of Most Effective PM/PM 10 

# Control Technologies for DRI Material Handling............ 306

Table 11-5 Technical Feasibility of F- Control Technologies for Material Handling ........................................ 310

Table 11-6 Ranking of Remaining F- Control T echnologies for Material Handling.......................................... 311

Table 11-7 Evaluation of Most Effective F- Control Technologies for Pelletizer—Hearth Layer Bin Material Handing ............................................................................................................... ............... 312

Table 11-8 Evaluation of Most Effective F- Control Technologies for DRI Material Handling........................ 312

Table 11-9 Technical Feasibility of Lead Control Technologies for Material Handling.................................... 314

Table 11-10 Ranking of Remaining Lead Control T echnologies for Material Handling ..................................... 315

Table 11-11 Evaluation of Most Effective Lead Control Technologies for Pelletizer—Hearth Layer Bin Material Handing ............................................................................................................... ............... 316

Table 11-12 Evaluation of Most Effective Lead Control Technologies for DRI Material Handling ................... 316

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# Table 12-1 Technical Feasibility of PM/PM 10 

# Control Technologies for Additive Material Handling.............. 319

Table 12-2 Ranking of Remaining Control Technologies for Additive Material Handling ............................... 320

Table 12-3 Evaluation of Most Effective PM Control Tec hnologies for Additive Material Handling.............. 320

Table 12-4 Technical Feasibility of F- Control Technologies for Additive Material Handling ........................ 324

Table 12-5 Ranking of Remaining Control Technologies for Additive Material Handling ............................... 325

Table 12-6 Evaluation of Most Effective F- Control T echnologies for Additive Material Handling................. 325

Table 14-1 Technical Feasibility of PM Control Technol ogies for Emergency Diesel Generators and Pumps .......................................................................................................................... ..................... 333

Table 14-2 Ranking of Remaining Control Technologies for Emergency Diesel Generators and Pumps ......... 333

Table 14-3 Evaluation of Most Effective PM / PM 10 

# Control Technologies for Emergency Generators and Pumps...................................................................................................................... ................... 334

Table 14-4 Technical Feasibility of SO 2 

# Control Technologies for Emergency Diesel Generators and Pumps .......................................................................................................................... ..................... 336

Table 14-5 Ranking of Remaining SO 2 

# Control Technologies for Emerge ncy Generators and Pumps ............. 336

Table 14-6 Evaluation of Most Effective SO2 Control T echnologies for Emergency Generators and Pumps .......................................................................................................................... ..................... 337

Table 14-7 Technical Feasibility of NOx Control Technologies for Emergency Diesel Generators and Pumps .......................................................................................................................... ..................... 338

Table 14-8 Ranking of Remaining NOx Control Technologi es for Emergency Generators and Pumps............ 339

Table 14-9 Evaluation of Most Effective NOx Control T echnologies for Emergency Generators and Pumps .......................................................................................................................... ..................... 339

Table 14-10 Technical Feasibility of VOC and CO Control Technologies for Emergency Generators and Pumps .......................................................................................................................... ..................... 340

Table 14-11 Ranking of Remaining VOC and CO Control T echnologies for Emergency Generators and Pumps .......................................................................................................................... ..................... 341

Table 14-12 Evaluation of Most Effective VOC and CO C ontrol Technologies for Emergency Generators and Pumps...................................................................................................................... ................... 341

## Minnesota Steel Page - 

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# Attachments

Attachment A Indurator Hood Exhaust – BACT Cost Tables

Attachment B Indurator Waste Gas Stack – BACT Cost Tables
Attachment C DRI Package Boiler – BACT Cost Tables

Attachment D DRI Process Heater– BACT Cost Tables
Attachment E DRI Tail Gas Purification System – BACT Cost Tables
Attachment F Pneumatic Transport System Gas Heater – BACT Cost Tables
Attachment G Degasser Boiler – BACT Cost Tables
Attachment H Material Handling, Pellet Plant – BACT Cost Tables
Attachment I DRI, Material Handling – BACT Cost Tables
Attachment J Steel Mill, Materi al Handling – BACT Cost Tables

Attachment K Diesel Po wered Stationary Engines
Attachment L RACT/BACT/LAER Clearinghouse Summary

Attachment M BACT Limits for Startups and Shutdowns

Attachment N BACT Mass Emission Li mits for Material Handling Sources
Attachment O Fugitive Dust Control Plan

## Minnesota Steel

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# This Page Intentionally Left Blank

## Minnesota Steel Page - 

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# 1.0 Executive Summary

Any new major stationary source or major modification subject to a Prevention of Significant
Deterioration (PSD) review must conduct an analysis to ensure the application of the Best Available
Control Technology (BACT). The results of the BACT analysis for Minnesota Steel Industries, LLC
(Minnesota Steel) form the basis for the selection of control technology and the resulting annual emission

limitations at each emissions unit. The control technologies proposed as BACT at Minnesota Steel

include:

• Clean Fuels for SO 2 

# , NO
x 

# , PM and PM 10



# • Good Combustion Practices for CO, VOC, PM and PM 10



# • Enclosures with Fabric Filter for PM, PM 10



# • Enclosures with PM Wet Scrubbers for PM, PM 10



# • Low NO
x 

# , ultra low NO
x 

# and oxy fuel burners for NO
x



# • Wet Scrubbers for PM, PM 10



# • Absorber/Wet Scrubber for SO 2 

# , fluorides (F) and sulfuric acid mist (SAM)

• Pb, F and SAM control performance monitored via SO 2 

# and particulate emission limits

• Best Practices for Fugitive Dust under a Fugitive Dust Control Plan

In addition, Minnesota Steel proposes to test and in stall, if technically and economically feasible, a
LoTOx, an innovative technology, for controlling NOx emissions from the pellet plant.
Table 1-1 through Table 1-14 presents a summary of th e BACT emission limits and control technologies.

Table 1-1 Indurating Furnace BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Hood Exhaust PM Wet Scrubber 0.006 gr/dscf* 23 lb/hr PM 24-hour Average

Hood Exhaust PM 10 

## Wet Scrubber 0.012 gr/dscf* 47 lb/hr PM 10 

## 24-hour Average

Hood Exhaust Opacity Wet Scrubber <10% NA

Hood Exhaust SO 2 

## No Controls 7.8 ppm 3-hour average 36 lb/hr SO 2 

## 3-hour Average

Hood Exhaust SAM No Additional Controls
PM scrubber will

provide some control of SAM

emissions 

## 0.021 ppm 3-hour average 0.15 lb/hr SAM 3-hour average

Hood Exhaust NO x 

## No Controls 45 ppm 24-hour average 165 lb/hr NO x 

## 24-hour Average

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## Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Hood Exhaust CO/VOC No Controls 2.1 ppm CO 1-hour average 1.8 ppm VOC 24-hour average 4.4 lb/hr CO 1-hour average 2.1 lb/hr VOC 24-hour Average

Hood Exhaust Pb Wet Scrubber <11 mg/kg in greenballs 0.013 lb/hr Pb 3 hour average

Hood Exhaust F Wet Scrubber <1 mg/kg in greenballs 0.013 lb/hr F 3-hour average

Waste Gas PM Wet Scrubber 0.006 gr/dscf* 17 lb/hr PM 24-hour Average

Waste Gas PM 10 

## Wet Scrubber 0.012 gr/dscf* 33 lb/hr PM 10 

## 24-hour Average

Waste Gas Opacity Wet Scrubber <10% NA

Waste Gas SO 2 

## Wet Scrubber 3.3 ppm 3-hour average 10 lb/hr SO 2 

## 3-hour Average

Waste Gas SAM Wet Scrubber 0.018ppm 3-hour average 0.085 lb/hr SAM 3-hour average

Waste Gas NO x 

## Clean fuels Good Combustion

Practices 205 ppm 464 lb/hr NO x 

## 24-hour Average

Waste Gas (estimated limits if

on-site testing demonstrates LoTOx is feasible) NO x 

## LoTOx 25 ppm 24-hour average 46 lb/hr NO x 

## 24-hour Average

Waste Gas CO/VOC Good Combustion

Practices Clean Fuels 9 ppm CO 1-hour average 7.5 ppm VOC 24-hour average 12 lb/hr CO 1-hour average 5.9 lb/hr VOC 24-hour Average

Waste Gas Pb Wet Scrubber <11 mg/kg greenballs 0.013 lb/hr Pb 3-hour average

Waste Gas F Wet Scrubber <1 mg/kg greenballs 0.25 lb/hr F 3-hour average

Hood Exhaust & Waste Gas All Pollutants Minimize Waste Gas to Hood

Exhaust NA NA

*PM –EPA Method 5 (Filterable PM only). PM 10 

## EPA Method 201or 201A (Filterable) and 202 or EPA approved modified Method 202 procedures (Condensable)

## Minnesota Steel Page - 

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## Table 1-2 DRI Boiler BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

DRI Boiler PM / PM 10 

## Good Combustion Practices Clean Fuels 0.0075 lb/MMBtu of PM / PM 10 

## 0.7 lb/hr PM/PM 10 

## 24-hour Average

DRI Boiler Opacity Good Combustion Practices Clean Fuels 3% Opacity NA

DRI Boiler SO 2 

## Good Combustion Practices Clean Fuels Good Combustion Practices Clean Fuels 0.1 lb/hr SO 2 

## 3-hour Average

DRI Boiler NO x 

## Ultra Low NO x 

## Burners/Low NO x 

## Burners with Flue Gas Recirculation 0.035 lb/MMBtu 3.5 lb/hr NO x 

## 24-hour Average

DRI Boiler CO/VOC Good Combustion Practices Clean Fuels 0.08 lb CO/MMBtu 0.006 lb VOC/MMBtu 8.2 lb/hr CO 1 hour average 0.5 lb/hr VOC 24-hour Average



## Table 1-3 DRI Process Heater BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

DRI Process Heater PM / PM 10 

## Top Gas Scrubber System; no add-on controls. 0.015 lb/MMBtu of PM / PM 10 

## (0.01 gr/dscf) 8.8 lb/hr PM/PM 10 

## 24-hour Average

DRI Process Heater Opacity Good Combustion Practices Clean Fuels 3% Opacity NA

DRI Process Heater SO 2 

## , Clean Fuels Top Gas or Natural Gas Clean Fuels 1 lb/hr SO 2 

## 3-hour Average

DRI Process Heater NO x 

## Ultra Low NO x 

## Burners 0.04 lb/MMBtu 24 lb/hr NO x 

## 24-hour Average

DRI Process Heater CO/VOC Good Combustion Practices Clean Fuels 0.08 lb CO/MMBtu 0.006 lb VOC/MMBtu 50 lb/hr CO 1-hour average 3.3 lb/hr VOC 24-hour Average

## Minnesota Steel Page - 

# 4 Executive Summary

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## Table 1-4 Top Gas Purification Sy stem BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Top Gas Purification H 2 

## S No Controls 11.1 lb/hr DMDS injection 3-hour average 68 ppm 3-hour Average 8.2 lb/hr H 2 

## S 3-hour Average



## Table 1-5 Pneumatic Transport System Gas Heater BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

PTS Gas Heater PM / PM 10 

## Good Combustion Practices Clean Fuels 0.0075 lb/MMBtu of PM / PM 10 

## 0.09 lb/hr PM/PM 10 

## 24-hour Average

PTS Gas Heater Opacity Good Combustion Practices Clean Fuels 3% Opacity NA

PTS Gas Heater SO 2 

## Good Combustion Practices Clean Fuels Good Combustion Practices Clean Fuels 0.024 lb/hr SO 2 

## 3-hour Average

PTS Gas Heater NO x 

## Ultra Low NO x 

## Burners/Low NO x 

## Burners with Flue Gas Recirculation 0.035 lb/MMBtu 0.4 lb/hr NO x 

## 24-hour Average

PTS Gas Heater CO/VOC Good Combustion Practices Clean Fuels 0.08 lb CO/MMBtu 0.006 lb VOC/MMBtu 00.95 lb/hr CO 1 hour average 0.1 lb/hr VOC 24-hour Average



# Table 1-6 DRI Cooling Wa ter Blowdown Vents BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Blowdown Stacks CO Good Design and Operating Practices Good Design and Operating Practices Quench Cooling 6.3 lb/hr CO 3-hour average

Process Cooling

2.7 lb/hr CO 3-hour average

## Minnesota Steel Page - 

# 5 Executive Summary

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## Table 1-7 Melt Shop BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Melt Shop PM Direct –Shell Evacuation Control System Baghouse 0.0018 gr/dscf* Filterable PM 9 lb/hr PM 24-hour Average

Melt Shop PM 10 

## Direct –Shell Evacuation Control System Baghouse 0.0030 gr/dscf* Total PM 10 

## 16 lb/hr PM 10 

## 24-hour Average

Melt Shop Opacity Good Operating Practices Clean Fuels 3% Opacity NA

Melt Shop SO 2 

## Clean Fuels Low Sulfur Carbon 0.15 Lb SO 2 

## /ton liquid steel produced 33 lb/hr SO 2 

## 3-hour Average

Melt Shop SAM Clean Fuels Low Sulfur Carbon 0.0052 lbs/ton of liquid steel 0.007 lb/hr SAM 3-hour average

Melt Shop NO x 

## Oxyfuel Burners and Direct –Shell Evacuation Control System no add-on controls 0.26 Lb NO x 

## /ton liquid steel produced 30-day rolling average 53 lb/hr NO x 

## 24-hour Average

Melt Shop CO/VOC Direct–shell Evacuation Control system Air Injection 2 Lb CO/ton 0.13 lb VOC/ton

liquid steel

produced 410 lb/hr CO 1 hour average 27 lb/hr VOC 3-hour Average

Melt Shop Pb Direct –Shell Evacuation Control System Baghouse <20 mg/kg in DRI 0.2 lb/hr 3-hour average

Melt Shop F Direct –Shell Evacuation Control System Baghouse <50 mg/kg in DRI 0.6 lb/hr 3-hour average

Ladle & Tundish Preheaters NO x 

## Low NO x 

## Burners NA NA

Ladle & Tundish Preheaters All other criteria pollutants Good Combustion Practices Clean Fuels Good Combustion Practices Clean Fuels NA

*PM –EPA Method 5 (Filterable PM only). PM 10 

## EPA Method 201or 201A and 202 or EPA approved modified Method 202 procedures (Filterable + Condensable)

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# 6 Executive Summary

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# Table 1-8 Vacuum Degasser BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Vacuum Degasser CO Flare 40 CFR 60 Subpart A (60.18) NA

Vacuum Degasser Boiler PM / PM 10 

## Good Combustion Practices Clean Fuels 0.0075 lb/MMBtu of PM / PM 10 

## 0.7lb/hr PM/PM 10 

## 24-hour Average

Vacuum Degasser Boiler Opacity Good Combustion Practices Clean Fuels 3% Opacity NA

Vacuum Degasser Boiler SO 2 

## Good Combustion Practices Clean Fuels Good Combustion Practices Clean Fuels 0.1 lb/hr SO 2 

## 3-hour Average

Vacuum Degasser Boiler NO x 

## Low NO x 

## Burners with Flue Gas Recirculation 0.035 lb/MMBtu 3.5 lb/hr NO x 

## 24-hour Average

Vacuum Degasser Boiler CO/VOC Good Combustion Practices Clean Fuels 0.08 lb CO/MMBtu 0.006 lb VOC/MMBtu 8.2 lb/hr CO 1-hour average 0.5 lb/hr VOC 24 hour Average



## Table 1-9 Tunnel Furnace BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Tunnel Furnace PM / PM 10 

## Good Combustion Practices Clean Fuels Good Combustion Practices Clean Fuels 1 lb/hr PM/PM 10 

## 24-hour Average

Tunnel Furnace Opacity Good Combustion Practices Clean Fuels 3% Opacity NA

Tunnel Furnace SO 2 

## Good Combustion Practices Clean Fuels Good Combustion Practices Clean Fuels 0.1 lb/hr SO 2 

## 3-hour Average

Tunnel Furnace NO x 

## Low NO x 

## Burners 0.1 lb NOx/MMBtu 5.0 lb/hr NO x 

## 24-hour average

Tunnel Furnace CO/VOC Good Combustion Practices Clean Fuels 0.08 lb CO/MMBtu 0.006 lb VOC/MMBtu 1.9 lb/hr CO 1-hour average 0.5 lb/hr VOC 24-hour Average

## Minnesota Steel Page - 

# 7 Executive Summary

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## Table 1-10 Material Handling BACT Analysis Summaries

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Mining & Crushing PM / PM 10 

## Trace quantities of F, Pb Fabric Filter 0.0025 gr/dscf* Individual Source Limits in Attachment N

Mining & Crushing Opacity Fabric Filter 5% Opacity NA

Concentrator PM / PM 10 

## Trace quantities of F, Pb Fabric Filter 0.0025 gr/dscf* Individual Source Limits in Attachment N

Concentrator Opacity Fabric Filter 5% Opacity NA

Fabric Filter 0.0025 gr/dscf*

Pelletizer PM / PM 10 

## Trace quantities of F, Pb

Wet Scrubber 0.005 gr/dscf* Individual Source Limits in Attachment N

Pelletizer Opacity Fabric Filter 5% Opacity NA Wet Scrubbers NA

Fabric Filter 0.0025 gr/dscf*

DRI PM / PM 10 

## Trace quantities of F, Pb

Wet Scrubber 0.005 gr/dscf* Individual Source Limits in Attachment N

DRI Opacity Fabric Filter 5% Opacity NA Wet Scrubbers NA

Melt Shop See BACT for Additives

Slag Processing See BACT for Fugitive Dust

* PM as measured by EPA Method 5

## Minnesota Steel Page - 

# 8 Executive Summary

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## Table 1-11 Additive Material Handling BACT Analysis Summaries

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit Mining & Crushing No additives

Concentrator No additives

Pelletizer PM / PM 10 

## Trace quantities of F, Pb 

## Fabric Filter 0.0025 gr/dscf* NA

Pelletizer Opacity Fabric Filter 5% Opacity 

## NA

DRI No additives

Melt Shop PM / PM 10 

## Trace quantities of F, Pb 

## Fabric Filter 0.0025 gr/dscf* NA

Melt Shop Opacity Fabric Filter 5% Opacity NA
Slag Processing No additives

* PM as measured by EPA Method 5



## Table 1-12 Fugitive Dust BACT Analysis Summaries

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Mining & Crushing PM / PM 10 

## Trace quantities of F, Pb Best Practices & Dust Control Plan Follow Fugitive Dust Control Plan NA

Mining & Crushing Opacity Best Practices & Dust Control Plan 5% Opacity NA

Concentrator PM / PM 10 

## Trace quantities of F, Pb Best Practices & Dust Control Plan Follow Fugitive Dust Control Plan NA

Concentrator Opacity Best Practices & Dust Control Plan 5% Opacity NA

Pelletizer PM / PM 10 

## Trace quantities of F, Pb Best Practices & Dust Control Plan Follow Fugitive Dust Control Plan NA

Pelletizer Opacity Best Practices & Dust Control Plan 5% Opacity NA

DRI PM / PM 10 

## Trace quantities of F, Pb Best Practices & Dust Control Plan Follow Fugitive Dust Control Plan NA

DRI Opacity Best Practices & Dust Control Plan 5% Opacity NA

Melt Shop No fugitives

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# 9 Executive Summary

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## Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Slag Processing PM / PM 10 

## Trace quantities of F, Pb Best Practices & Dust Control Plan Follow Fugitive Dust Control Plan NA

Slag Processing Opacity Best Practices & Dust Control Plan 5% Opacity NA

Roads Opacity Best Practices & Dust Control Plan 10% Opacity NA



## Table 1-13 DRI and Steel-Mill Cooling Towers BACT Analysis Summary

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Mining & Crushing No cooling tower

Concentrator No cooling tower

Typing shortcuts Pelletizer No cooling tower

DRI PM / PM 10 

## Drift Eliminator 0.005% drift rate NA

DRI Opacity Drift Eliminator <20% NA

Melt Shop PM / PM 10 

## Drift Eliminator 0.005 % drift rate NA

Melt Shop Opacity Drift Eliminator <20% NA

Slag Processing No cooling tower

## Minnesota Steel Page - 

# 10 Executive Summary

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## Table 1-14 Emergency Equipment Diesel Powered Generators and Pumps

BACT Analysis Summaries

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Emergency Diesels PM / PM 10 

## Emergency Generator Classification combined with GCP Emergency Generator Classification combined with Good Combustion Practices NA

Emergency Diesels SO 2 

## Emergency Generator Classification combined with Low Sulfur Fuel Emergency Generator Classification combined with Low Sulfur Fuel NA

Emergency Diesels NO x 

## Emergency Generator Classification combined with GCP Emergency Generator Classification combined with Good Combustion Practices NA

Emergency Diesels CO/VOC Emergency Generator Classification combined with GCP Emergency Generator Classification combined with Good Combustion Practices NA

Emergency Diesels Opacity Good Combustion Practices Clean Fuels 5% Opacity NA

## Minnesota Steel Page - 11 Introduction

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# 2.0 Introduction

The Minnesota Steel Industries project involves the construction and operation of a steel mill on the
Mesabi Iron Range in Nashwauk, Itasca County, Minneso ta. The project will incorporate a taconite iron
ore mine, ore concentrator and pellet plant, two direct reduced iron (DRI) modules, two electric arc
furnaces with continuous slab casting and a rolling mill. The plant will produce slab steel and/or coiled
sheet steel as a finished product. The goal of the project is to produce high quality steel in an economical

and efficient manner, while at the same time not adve rsely impacting the environment. A key element in
pursuing this goal is the commitment by Minnesota St eel to use only natural gas for all process heat

needs.

The proposed construction requires a Prevention of Si gnificant Deterioration (PSD) permit application to

be submitted on behalf of Minnesota Steel to the Minn esota Pollution Control Agency. As part of a PSD

review for Minnesota Steel, a Best Available C ontrol Technology (BACT) analysis is required.

The following review considers air pollution contro l options for each pollutant associated with each

Minnesota Steel emissions unit. Sources consulte d for air pollution control technology include:

US EPA’s RACT/BACT/LAER Clearinghouse (RBLC) US EPA’s New Source Review (NSR) bulletin board US EPA Background documents for the EAF-NSPS AAa US EPA/State Air Quality Permits AWMA’s Air Pollution Control Technology Manual South Coast Air Quality Management District (AQMD) Best Available Control Technology Guidelines Bay Area Air Quality Management District (BAAQMD) San Joaquin Valley Unified Pollution District BACT Clearinghouse Texas Natural Resource Conservation Commissions BACT Air pollution control technology vendors Manufacturer’s recommendations

## Minnesota Steel Page - 12 Methodology

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# 3.0 Methodology

3.1 PSD Applicability

The requirement to conduct a BACT analysis and dete rmination is set forth in section 165(a) (4) of the
Clean Air Act, in federal regulations at 40 CFR 52.21 (j), the Minnesota State Implementation Plan (SIP)
at 40 CFR Part 52, Subpart A – Subpart FFF and Minnesota Pollution Control Agency regulations at MN

7007.

40 CFR 52.21(j) specifies that BACT must be applied to a new source as follows:

• (j) Control technology review. (1) A major stati onary source or major modification shall meet each applicable emissions limitation under the State Implementation Plan and each applicable emissions standard and standard of performance under 40 CFR parts 60 and 61.

• (2) A new major stationary source shall apply best available control technology for each regulated NSR pollutant that it would have th e potential to emit in significant amounts.



# 40 CFR 52.21(b) 23 defines 1 

# significant amounts as follows:

• Particulate matter: 25 tpy of particulate matter emissions; 15 tpy of PM10 emissions

• Sulfur dioxide: 40 tpy

• Nitrogen oxides: 40 tpy

• Carbon monoxide: 100 tons per year (tpy)

• Ozone: 40 tpy of volatile organic compounds

• Lead: 0.6 tpy

• Fluorides 2 : 3 tpy

• Sulfuric acid mist: 7 tpy

• Hydrogen sulfide (H2 S): 10 tpy

• Total reduced sulfur (including H2S): 10 tpy

• Reduced sulfur compounds (including H2 S): 10 tpy

• Municipal waste combustor organics (measured as total tetra- through octa-chlorinated dibenzo-p-dioxins and dibenzofurans): 3.2 × 10

− 6 mega grams per year (3.5 × 10

− 6 tons per year).

• Municipal waste combustor metals (measured as particulate matter): 14 mega grams per year (15 tons per year)

• Municipal waste combustor acid gases (measur ed as sulfur dioxide and hydrogen chloride): 36 mega grams per year (40 tons per year)

• Municipal solid waste landfills emissions (measured as non-methane organic compounds): 45 mega grams per year (50 tons per year)

1 

## Please note that the order of pollutants listed in paragraph b(23) have been re arranged to match the order that these pollutants are addressing in this BACT report.

2 

## Fluorides do not include hydrogen fluoride (HF). HF emissions are regulated under EPA MACT standards found at 40 CFR 63.

## Minnesota Steel Page - 13 Methodology

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# Minnesota Steel will be a major source as defined by PSD regulations and is expected to emit the
following PSD pollutants in significant amounts:

• Particulate Matter (PM)

• Particulate Matter less than 10 microns (PM10)

• Sulfur Dioxide (SO2)

• Nitrogen Oxides (NOx)

• Carbon Monoxide (CO)

• Volatile Organic Compounds (VOCs)

• Hydrogen Sulfide (H2S)

• Sulfuric Acid Mist (SAM)

• Fluorides (F) Please note that hydrogen fluoride is not included in this category



# The following PSD pollutants are not expected to be emitted from the Minnesota Steel facility in
significant quantities:

• Lead (Pb)

• Total Reduced Sulfur Compounds

• Reduced Sulfur Compounds

• Municipal Waste Combustor Acid Gases

• Municipal Solid Waste Landfill Gases



# 3.2 BACT Methodology

The BACT analysis for Minnesota Steel was conducte d in accordance with the requirements specified in
EPA’s draft New Source Review Workshop Manual, (O ctober 1990). The BACT analysis followed the
EPA’s top-down approach in which progressively less stringent control technologies were analyzed until

a level of control considered BACT was achieved.

The five basic steps of the top down appr oach to the BACT process are as follows:

Step 1 – Identify all Control Technologies
The first step in a top down analysis is to id entify all available control technologies for each

emission unit.

Step 2 – Eliminate Technically Infeasible Options
In the second step, the technical feasibility of each control option identified in step one is
evaluated with respect to source-specific factor s. Technologies which are determined to be

infeasible are eliminated from further consideration.

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# Step 3 – Rank Remaining Control Technologies by Control Effectiveness
In the third step, all remaining control technologies not eliminated in Step 2, are ranked and then

listed in order of over all control effectiveness for the pollutant under review, with the most
effective control alternative at the top.

Step 4 – Evaluate Most Effective Control Technologies and Document Results
In the fourth step, the energy, environmental, and economic impacts are considered for each of
the control options.

Step 5 – Select BACT
In the fifth step, the most effective control opti on, based on the impacts quantified in Step 4, is
proposed as BACT for the pollutant and emission unit under review.

Step 4 economic impacts were analyzed using the procedures found in the EPA Air Pollution
Control Cost Manual - Sixth Edition (EPA 452/B-02-001 ). Vendor cost estimates for this project
were used when available. If control equipment ve ndors did not respond to bid requests, cost data
from other recent projects were used with adjust ments for inflation and size. Equipment cost

estimates from the EPA Control Cost Manual or EPA’s Air Compliance Advisor (ACA) Air
Pollution Control Technology Evaluation Model version 7.5 were used if no vendor data were
available. The source of the control equipment co st data are noted in each of the control cost
analysis worksheets as found in Attachments A – K.

BACT is defined as:

“Best available control technology means an emissions limitation (including a visible emission standard)
based on the maximum degree of reduction for each pollut ant subject to regulation under Act which would be
emitted from any proposed major stationary source or major modification which the Administrator, on a case-bycase basis, taking into account energy, environmental, and economic impacts and other costs, determines is
achievable for such source or modification through app lication of production processes or available methods,
systems, and techniques, including fuel cleaning or treat ment or innovative fuel combustion techniques for
control of such pollutant. In no event shall application of best available cont rol technology result in emissions of
any pollutant which would exceed the emissions allo wed by any applicable standard under 40 CFR parts 60 and

61. If the Administrator determines t hat technological or economic limitations on the application of measurement
methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a
design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to
satisfy the requirement for the applicati on of best available control technolo gy. Such standard shall, to the degree

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## possible, set forth the emissions reduction achievable by implementation of such design, equipment, work
practice or operation, and shall provide for comp liance by means which achieve equivalent results.”



# 3.3 Emission Limits

While the BACT review process is used to eval uate potential control technologies and work
practices, a PSD permit must express the BACT determination as a perm it limitation, which is
federally enforceable. Suggested emission limits within this BACT review will be expressed as a
standard of performance and a ma ss emission rate (or equivalent measure) when appropriate. The
standard of performance will be expressed as emissions per unit of production, the concentration of a
pollutant emitted from the source, or a similar measure that represents the level of control achieved
by the control technology. The mass emission limit will be set at the emission unit’s potential to
emit on a 24-hour average basis with controls. This provides the source flexibility in maintaining
compliance while keeping the averaging time short enough to be practicably enfo rceable. Proposed

mass emission limits for SO 2 

# will be on a 3-hour average basis to be consistent with ambient air
quality standards, and CO limits will be on a 1-hour average basis for similar reasons. The maximum
modeled 1-hour average SO 2 

# .impact of the Minnesota Steel facility was only 14 μ g/m 3 

# . Since this
impact is well below the state 1-hour SO 2 

# standard of 1,300 μ g/m 3 

# , no 1-hour average limits are
needed to protect state air quality standards. If a mass emissi on limit is not practical, a production
limit or similar measure, which is practicably enforceable, will be proposed. Proposed emission

limits on a detailed emission unit and stack basis are provided in the CD-01 forms of the permit
application.

BACT limit data from EPA’s RACT/BACT/LAER Clearinghouse (R BLC) for taconite mining and
pellet production, Direct Reduced Iron (DRI) produc tion, steel production (via electric arc furnaces)
and other source categories associated with this project was updated on April 26, 2006. The RBLC
data was analyzed to identify current levels of emission controls considered to be BACT, and
compared to Minnesota Steel’s proposed BACT limits. RBLC data sorted by source category are
presented in Attachment L.

Although the RBLC database contains process descript ions, similar sources are not always listed by
the exact same process name for every listing. So, standardized process categories were assigned to
each of the 1,865 RBLC listings collected to simp lify the review process. Next, the summaries of
RBLC data in Attachment L were sorted to aid data analysis and review. Data from the RBLC was
placed in an MS Excel worksheet and sorted to di stinguish BACT-PSD data from other case-by-case

data. The non-BACT limits do not include economic feasibility as criteria for determining emission

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# limits (i.e. these limits can be more restrictive than BACT) and are listed only for informational
purposes. BACT limit data was then sorted in as cending order to show which of the recent BACT
determinations represent the maximum level of emission control. Emission limit data was sorted by
numerical limit values and by the units of the limit. This ensures that similar BACT limits are
ranked in the same units grouping (e.g. ppm limits are ranked separately from lb/MMBtu limits).
The RBLC data may include up to three different limits (Limit 1, Limit 2 and Standard Emission
Limit). Unfortunately, emission c ontrol performance based limits (e.g. lb/MMBtu) may appear in
any of these limit categories. Therefore, the limi t column with the highest number of relevant BACT
limits was sorted so that the majority of relevant listings were ranked. The limit column sort varies
from table to table depending up on which column cont ains the most relevant data. Please note that
the other limit columns may contain relevant info rmation and all three limits columns should be

reviewed.

A statistical analysis of the RBLC data is presented at the bottom of each table. The statistical
analysis includes the minimum, maximum, median and number of data points analyzed (count).
When appropriate, the analysis also included the to p half of the upper quartile (top 12%) of the data
and a frequency distribution to further refine the identification of BACT limits representing the

maximum levels of emission control. Only relevant data are included in the statistical analysis. For
example, only lb/MMBtu limits were analyzed when the proposed BACT limit is in lb/MMBtu. Data

from all three limit columns were in cluded in the statistical analysis. In cases where a source was
not able to demonstrate compliance with its BACT limit, that limit was not included in the analysis.
Data excluded for this reason are identified by foot note in the individual tables. Selected source and
agency contacts listed in the RBLC were called to verify whether or not a particular source was able
to meet the limit listed in the RBLC. Only those f acilities with the lowest limits were contacted for

verification.



# 3.4 Emission Units and Pollutants

Individual emission units are grouped into the eight sections as listed in Table 3-1. Within each of these
sections, the PSD pollutants emitted by the respective emission units are detailed.

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## Table 3-1 Summary of Emission Units and PSD Pollutants Emitted

Plant Section PSD Pollutants Emitted

1 Mining and Crushing PM , PM 10 

## and Fluorides

2 Pellet Plant PM, PM 10 

## , SO 2 

## , NO x 

## , CO, VOC, Fluorides, Sulfuric Acid Mist and Pb

3 DRI Plant PM, PM 10 

## , SO 2 

## , NO x 

## , CO, VOC, H 2 

## S, Fluorides, Sulfuric Acid Mist and Pb

4 Steel Mill PM, PM 10 

## , SO 2 

## , NO x 

## , CO, VOC, Fluorides, Sulfuric Acid Mist and Pb

5 Slag Handling PM, PM 10 

## 6 Cooling Towers PM and PM 10 

## , Fluorides and Pb

7 Emergency Generators and Pumps PM, PM 10 

## , SO 2 

## , NO x 

## , CO and VOC

8 Fugitive Emissions PM , PM 10 

## ,Fluorides and Pb



# Within each plant section listed in Table 3-1, the following processes are addressed:

• Each major process equipment type.

• Materials handling equipment.

• Cooling towers (where applicable) will be noted and referenced to the appropriate section of the
BACT report.

• Sources of fugitive emissions in each process will be noted and referenced to the appropriate
section of the BACT report.

• Special Operating Conditions

 

# Startup/Shutdown: In most cases, Minnesota Steel can put emission control equipment
into service prior to commencing operation of process equipment, and keep controls
operating until the process is shut down and off line. In these cases, no special permit
conditions are needed for startup and shutdow n. In those cases when emission control
equipment does not function at full efficiency or cannot be placed into service during
startup/shutdowns, a separate limit will be proposed. See Section 4.8 for additional

information.

 

# Malfunctions: Due to the sudden and unexp ected nature of malfunctions; a BACT limit
cannot be proposed for malfunctions. Ho wever, Minnesota Steel will follow best
practices for minimizing emissions during ma lfunctions. These will include continued
operation of emissions control equipment wh en feasible, repairing equipment in an
expedient manner and/or shutting down the pr ocess if the malfunction is expected to

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# continue for an extended period of time. These actions will be taken in a manner which

is consistent with Minnesota Steel’s h ealth and safety policies and standards.



# 3.5 Identification of Applicab le Standards under 40 CFR Parts 60 (NSPS), 61 (NESHAP), and 63 (NESHAP/MACT)

As noted in the definition of BACT, BACT emission limits for sources subject to emission standards
under 40 CFR Part 60 (NSPS) or 40 CFR Part 61 (N ESHAPS) cannot be less stringent than the
applicable standards. Maximu m Achievable Control Technolo gy (MACT) standards under 40 CFR

Part 63 for the control of Hazar dous Air Pollutants are not appli cable to establishing BACT.

MACT standards are intended for the regulation of HAPS; not PSD pollutants, and therefore, do not
need to be considered as establishing the mi nimum emission control re quirements for BACT.
However, in some cases, EPA has used criteria pollutant standards as MACT since the criteria
pollutants are good indicators of HAP emission controls. In thos e cases, MACT standards may be

used as an indicator of the level of emissions co ntrol which may be achieved by the best performing
units. If a MACT standard has lower emission limits than those resulting from a BACT determine the
source is still subject to the lower MACT standard.

The NSPS and NESHAP standards were reviewed for applicability at the Minnesota Steel project. No
applicable standards under Part 61 were identified. Applicable standards under Part 60 and 63 that were
identified as applicable are the following:

• 40 CFR Part 60 Subpart Dc, Standards of Pe rformance for Small Industrial-CommercialInstitutional Steam Generating Units

• 40 CFR Part 60 Subpart LL, Standards of Performance for Metallic Mineral Processing

• 40 CFR Part 60 Subpart AAa, Standards of Performance for Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessel s Constructed After August 17, 1983

• 40 CFR Part 60 Subpart IIII, Standards of Pe rformance for Stationary Compression Ignition Internal Combustion Engines

• 40 CFR Part 63 Subpart RRRRR, National Emission Standards for Hazardous Air Pollutants: Taconite Iron Ore Processing

• 40 CFR Part 63 Subpart DDDDD, National Emissi on Standards for Hazardous Air Pollutants: Industrial, Commercial, and Institu tional Boilers and Process Heaters

Each of these is discussed in the following sections in terms of specific source applicability and emission

limits.

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# 3.5.1 40 CFR 60 Subpart Dc, Standards of Performance for Small IndustrialCommercial-Institutional Steam Generating Units

Subpart Dc regulates steam genera ting units (boilers) with a heat input value between 10 and 100

MMBtu/hr.

40 CFR 60.40c (a)
(a) Except as provided in paragraph (d) of this secti on, the affected facility to which this subpart applies is each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 milli on Btu per hour (Btu/hr)) or less, but greater than or equal to 2.9 MW (10 million Btu/hr).



# The NSPS applies to the vacuum degasser boiler; however, as a gas-fired unit, the requirements are
reduced to notifications and fuel use recordkeepin g. There are no emission limits applicable to gasfired units under Subpart Dc.



# 3.5.2 Subpart LL, Standard s of Performance for Me tallic Mineral Processing
Subpart LL regulates point source emissions of par ticulate matter from material handling sources and
thermal dryers at Metallic Mineral Processing faciliti es. Metallic Mineral Processing facilities are defined

as follows in 40 CFR 60.381

“ Metallic mineral processing plant means any combination of equipment that produces metallic mineral concentrates from ore. Metallic mineral processing comm ences with the mining of ore and includes all operations either up to and including the loading of wet or dry concen trates or solutions of meta llic minerals for transfer to facilities at non-adjacent locations that will subsequently process metallic concen trates into purified metals (or other products), or up to and including all material transfer and storage operations that preced e the operations that produce refined metals (or other products) from metallic mineral c oncentrates at facilities adjacent to the metallic mineral processing plant. This definition shall not be construed as requ iring that mining of ore be conducted in order for the combination of equipment to be considered a metallic mine ral processing plant. (See also the definition of metallic mineral concentrate.)”



# Based on this definition Subpart LL applies to th e process from mining and crushing up to the point
where the taconite pellets enter the DRI unit. S ubpart LL applies to material transfer and storage
operations that precede the operation that produce refi ned metals and therefore does not apply to the DRI
or Steel Mill equipment.

Affected equipment under Subpart LL is specified in 40 CFR 60.380(a) as listed below:

“(a) The provisions of this subpart are applicable to t he following affected facilities in metallic mineral processing plants: Each crusher and screen in open-pit mines; each crusher, screen, bucket elevator, conveyor belt transfer point, thermal dryer, product packaging station, storage bin, enc losed storage area, truck loading station, truck unloading station, railcar loading stati on, and railcar unloading station at the mill or concentrator with the following exceptions. All facilities located in underground mines are exempted from the provisions of this subpart. At uranium ore processing plants, all facilities subsequent to and in cluding the beneficiation of uran ium ore are exempted from the provisions of this subpart.”

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# The stack or point source emission limits for these sources under Subpart LL are defined in 40 CFR
60.382(a) as follows:

“(a) On and after the date on which the performance test required to be conducted by §60.8 is completed, no owner or operator subject to the provisions of this subpart sh all cause to be discharged into the atmosphere from an affected facility any stack emissions that:

(1) Contain particulate matter in excess of 0.05 grams per dry standard cubic meter (0.02 g/dscm).

(2) Exhibit greater than 7 percent opacit y, unless the stack emissions are disc harged from an affected facility using a wet scrubbing emission control device.



# The fugitive source emission limits for these sources under Subpart LL are defined in 40 CFR 60.382(b)

as follows:

(b) On and after the sixtieth day after achieving the maxi mum production rate at which the affected facility will be operated, but not later than 180 days after in itial startup, no owner or operator subj ect to the provisions of this subpart shall cause to be discharged into the atmosphere from an affe cted facility any process fugitive emissions that exhibit greater than 10 percent opacity.”



# Table 3-2 summarizes the applicable NSPS limits unde r 40 CFR Part 60.382. These limits represent the

maximum allowable emissions for a BACT dete rmination for sources subject to Subpart LL.

Table 3-2 NSPS Emission Limits for Metallic Mineral Processing

Pollutant Emission Limit Reference

Particulate Matter 0.05 gr/dscf 40 CFR 60.382(a)(1)

Visible Emissions 7% opacity 1 

## 40 CFR 60.382(a)(2)

Fugitive Emissions 10% opacity 40 CFR 60.382(a)(3)



# 3.5.3 Subpart AAa, Standards of Perfo rmance for Steel Plan ts: Electric Arc Furnaces and Argo n-Oxygen Decarburizatio n Vessels Constructed After August 17, 1983
Affected equipment under Subpart AAa is specified in 40 CFR 60.270(a) and definition from 40 CFR

60.271a as listed below:

(a) The provisions of this subpart are applicable to the fo llowing affected facilities in stee l plants that produce carbon, alloy, or specialty steels: electric arc furnaces, argon- oxygen decarburization vessels , and dust-handling systems.

Argon-oxygen decarburization vessel (AOD vessel) means any closed-bottom, refractory-lined converter vessel with submerged tuyeres through which gaseous mixtures contai ning argon and oxygen or nitrogen may be blown into molten steel for further refining.

Dust-handling system means equipment used to handle particulate matter collected by the control device for an electric arc furnace or AOD vessel subject to this subpar t. For the purposes of this s ubpart, the dust-handling system shall consist of the control device dus t hoppers, the dust-conveying equipmen t, any central dust storage equipment,

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## the dust-treating equipment (e.g., pug mill, pelletizer), du st transfer equipment (from storage to truck), and any secondary control devices used with the dust transfer equipment.

Electric arc furnace (EAF) means a furnace that produc es molten steel and heats the ch arge materials with electric arcs from carbon electrodes. For the purposes of this subp art, an EAF shall consist of the furnace shell and roof and the transformer. Furnaces that continu ously feed direct-reduced iron ore pellets as the primary source of iron are not affected facilities within the scope of this definition.



# The Ladle Metallurgy Furnaces meet the definiti on of an Argon-oxygen decarburization vessel (AOD
vessel); so, they are affected facilities. The Melt Shop dust collection system meets the Dust-handling
system definition, and is subject to Subpart AAa limi ts. The EAF is designed to processes DRI pellets in

a continuous manner; therefore it is exem pt under the EAF definition listed above.

Table 3-3 lists the applicable NSPS limits under 40 CFR Part 60.382. These limits represent the
maximum allowable emissions from material handling.

Table 3-3 NSPS Emission Limits for Steel Plants

Pollutant Emission Limit Reference

Particulate Matter from the control device 0.0052 gr/dscf using EPA Method 5 40 CFR 60.272(a)(1)

Visible Emissions from the control device 3% opacity 40 CFR 60.382(a)(2)

Visible Emissions from the Melt Shop 6% opacity 40 CFR 60.382(a)(3)

Visible Emissions from dust handling equipment 10% opacity 40 CFR 60.382(b)



# 3.5.4 40 CFR Part 60 Subpart IIII, Standards of Pe rformance for Stationary Compression Ignition Inte rnal Combustion Engines

EPA issued rules for stationary compression igni tion (diesel) engines on July11, 2006. Theses rules limit

emissions of PM, NO
x 

# , CO and VOCs from diesel engines based on size, service and date of manufacture.

SO 2 

# emissions will be limited by fuel specifications. Minnesota Steel Industries stationary diesels will be
used for emergency purposes only. The new rule lim its emergency operation to 100 hours per year or
less. Standards for emergency diesels are listed in Table 2 (emergency diesels < 50 HP) and Table 4 (fire
pumps) of the regulation. Emergency diesel engines larg er than 50 HP are subject to the off road engine

standards located at 40 CFR 89.112 and 40 CFR 89 .113. The emission standards in Subpart IIII
applicable to Minnesota Steel industries may be met w ithout the use of add on controls. Minnesota Steel
Industries will follow the applicable emission limitations for stationary diesel as applicable the model
year of the engines purchased.

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# 3.5.5 Subpart RRRRR, National Emi ssion Standards for Hazardous Air Pollutants: Taconite Iron Ore Processing

As stated earlier MACT standards do not constitute a basis for a BACT determination, but they must be
met regardless of a BACT determination, even if the emission limit is lower.

HAP emissions are regulated in Subpart RRRRR by requiring the control of particulate emissions.
Subpart RRRRR applies to taconite facilities that ar e major sources of HAP emissions and therefore
applies to this project. Subpart RRRRR applies to the follow as defined in 40 CFR 63.9582

“(a) This subpart applies to each new and existing affected source at your taconite iron ore processing plant.

(b) The affected sources are each new or existing ore crushi ng and handling operation, ore dryer, indurating furnace, and finished pellet handling operation at your taconite iron ore processing plant, as defined in §63.9652.

(c) This subpart covers emissions from ore crushing and ha ndling emission units, ore dryer stacks, indurating furnace stacks, finished pellet handling emission units, and fugitive dust emissions.

(d) An ore crushing and handling operation, ore dryer, indura ting furnace, or finished pellet handling operation at your taconite iron ore processing plant is existing if you comm enced construction or reconstr uction of the affected source before December 18, 2002.

(e) An ore crushing and handling operation, ore dryer, indura ting furnace, or finished pellet handling operation at your taconite iron ore processing plant is new if you commence cons truction or reconstruction of the affected source on or after December 18, 2002. An affected source is reconstruct ed if it meets the definition of reconstruction in §63.2.”



# Table 3-4 summarizes the emission limits from Ta ble 1 of subpart RRRRR for new taconite facilities
using a straight grate indurating furnace.

Table 3-4 NESHAP Emission Limits for Taconite Iron Ore Processing

Emission Source Emission Limit

Ore crushing and handling 0.005 gr/dscf*

Straight grate indurating furnace 0.006 gr/dscf*

Finished pellet handling 0.005 gr/dscf* 

# . * PM as measured by EPA Method 5



# 3.5.6 Subpart DDDDD, National Emi ssion Standards for Hazardous Air Pollutants: Industrial, Commerci al, and Institutional Boilers and Process Heaters
As stated earlier MACT standards do not constitute a basis for a BACT determination, but they must
be met regardless of a BACT determination, even if the emission limit is lower.

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# HAP emissions are regulated in Subpart DDDDD by requiring the control of the criteria pollutants
particulate emission and CO , as well as hydrogen chloride and me rcury. Subpart DDDDD applies to
boilers and process heaters at major HAP sources a nd therefore applies to this project. Subpart
DDDDD applies to boilers and process heaters used indirect heating. The only process heater that

meets this definition is the DRI reformer.

The Subpart DDDDD emission limit for gas fired bo ilers and process heater s is 400 ppm of CO on a
dry basis corrected to 3 percent oxygen (30-day ro lling average for units 100 MMBtu/hr or greater,
3-run average for units less than 100 MMBtu/hr). There are no emission limits for PM, hydrogen
chloride, or mercury on ga s fired boilers and process heaters beca use emissions of these constituents
are not significant.

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# 4.0 Emission Control Technologies

4.1 Overview of Emission Control Technologies

Due to the size and complexity of Minnesota Steel’s proposed facility, several individual sources

must be included in this BACT review. Given that the list of potential control technologies for each
of these sources is similar, detailed descriptions of each control technology are included in this

section as a reference for the individual source BACT analysis. The emission control technologies

evaluated include add-on c ontrols and inherently lower pollution process equipment where generally
applicable (e.g. low NOx burners). Each source specific BACT analysis will contain a brief summary
of the control technologies covered in this section. Source specific emis sion controls and operating
practices will be described in the sections relating to those individual sources. In cases where a

combination of controls is feasible, those combin ations will be address in the individual BACT
analysis

Descriptions of emission control practices for fugi tive emissions are discu ssed in Section 15, which
covers fugitive emission cont rol for the entire facility.



# 4.2 Particulate Matter (PM & PM 10 

# ), Fluoride (F-), Particulate, and Lead (Pb) Emission Control Technologies

Fluoride and lead emissions will be controlled wi th particulate matter em ission controls on sources
where fluorides and lead are emitted as dust. Fluoride and lead salts are present in trace quantities in
taconite ore. These salts are emitted as particulat e matter along with ore dust during ore processing
such as ore crushing.

Most particulates are in a solid state when they are emitted. Usually these particulates are generated
as dust from material handling and dry ore proces sing. When stacks are tested using EPA test
procedures like EPA Method 5, thes e particulates are collected on a filter; hence, th ey are called
“filterable particulates”.

The control efficien cy of a particulate matt er control method depends upon the size distribution of
the particulates in the waste gas stream. Generally, the smallest particulates are the most difficult to
remove. Usually, the control efficiency of a particulate control method will be lower when
increasing amounts of small particle s are present in the exhaust gas being treated. Therefore, the

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# control efficiency of a pa rticulate control method wi ll vary when applied to different source types
(e.g. ore grinding which contains larger partic les vs. an EAF which contains relatively small
particles) because each source type will have a different size distri bution of particulates emitted.

Exhaust streams containing com bustion products, vapors from iron ore conversion processes and
steel making may also contain “condensable particulat e” matter. Condensable particulates are in a
vapor state when emitted, and change to a li quid or solid state when cooled. Condensable
particulates are measured us ing EPA Method 202 or EPA a pproved modified Method 202
procedures 3



# .

Therefore, particulate matter emission controls can only capture particulate matter when it is in a
filterable state (solid or liquid not a vapor). So, the ability of any specific type of particulate control
device is dependent upon the process conditions at the time the exhaust gas passes through the
control device. In some cases, the exhaust gas is cooled enough by the control device; so, these
control devices have a greater potential for capturi ng condensable particulat es than one which does
not reduce the temperature of the exhaust gas. Pa rticulate matter control methods which use water
may also be effective at capturing particulates which are soluble in water (e.g. sulfate salts)

Therefore, the overall emission co ntrol efficiency of any partic ulate control method for a given
source type, is dependent upon the size distribution of the filterable particul ate matter and the amount
of condensable particulate matter present in the exhaust stream. For these reasons, selection of
particulate control method is a trade off between the ability of the device to capture filterable and/or
condensable particulat es vs. the amount and size of each type of particulate matt er present in the

exhaust steam. The relative control efficiencies of particulate control de vices for filterable and
condensable particul ates can be summarized as follows:

3 

## EPA is currently evaluating modified procedures for Method 202 to improve the accuracy of the test method.

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## Summary of Particulate Control Technology Effectiveness

Technology Filterable Particulates Condensable Particulates

Wet Scrubber High Best

Wet Electrostatic Precipitator High Best

Fabric Filter (Baghouse) Best High

Electrostatic Precipitator High High

Mechanical Collectors Medium Poor



# Additional details regarding each ty pe of particulate control equipm ent are discussed in the following
sections. Included is a description of each type of pollution control equipment, operating limitations,
and there effectiveness at controlling fi lterable and condens able particulates.



# 4.2.1 Fabric Filter
A fabric filter or baghouse consists of a number of fabric bags placed in parallel inside of an

enclosure. Particulate matter is collected on the su rface of the bags as the gas stream passes through
them. The dust cake which forms on the filter from the collected particulate can contribute
significantly to increasing the collection efficiency.

Two major fabric filter types are th e reverse-air fabric filter and the pulse-jet fabric filter. In a
reverse-air fabric filter, the flue gas flows upwar d through the insides of vertical bags which open
downward. The particulate matter thus collects on the insides of the bags, and the gas flow keeps the
bags inflated. To clean the bags, a compartment of the fabric filter is taken off-line, and the gas flow
in this compartment is reversed. This causes the bags to collapse , and collected dust to fall from the
bags into hoppers. (Shaking, or another method, is sometimes employed to dislodge the dust from
the bags.) The cleaning cycle in a reverse-air fabric filter typically lasts about three minutes per
compartment. Because reverse-air cleaning is gentle, reverse-air fabric filters typically require a low

air-to-cloth ratio of 2 ft/min.

In a pulse-jet fabric filter, dirty air flows from the outside of the bags inward, and the bags are
mounted on cages to keep them from collapsing. Dust that collects on the outsides of the bags is
removed by a reverse pulse of high-pressure air. This cleaning does not require isolation of the bags
from the flue gas flow, and thus may be done on-line.

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# The main operating limitation of a baghouse is that its operating temperatur e is limited by the bag

material. Most filter materials are limited to 200o F – 300o F. Some materi als like glass fiber or
nomex may be operated at 400oF, but are more expensive.

Baghouse control efficiency under normal loading condi tions typically is in the 98% - 99%+ range.
Reduced efficiencies will occur when the inlet part icle concentration is lo w. Baghouse controls do
not significantly affect the temperature of the stream being treated; so, condensable particulate matter

control is limited to condensable particulates present in a filterable form in the baghouse when it is
being treated. Outlet pa rticle concentrations typically are in the 0.005 gr/dscf range. In some cases

lower concentrations can be achieved, but the outle t concentrations achieved will depend on the size
range and nature of the particles being filtered, and th e type of filter media which can be used in that
application. Therefore, baghouses are most effective controlling sour ces with filterab le particulates

and less effective controlli ng hot exhaust streams with c ondensable particulates.



# 4.2.2 Electrostatic Precipitators (ESP)

An electrostatic precipitator applies electric forces to separate suspended particles from the flue gas

stream. In an ESP, an intense electrostatic fiel d is maintained between high-voltage discharge
electrodes, typically wires or ri gid frames, and grounded collecting electrodes, typically plates. A
corona discharge from the discharge electrodes io nizes the gas passing through the precipitator, and
gas ions subsequently ionize the particles. The electric field drives the negatively charged particles
to the collecting electrodes. Periodically, the collecting electrodes are rapped mechanically to
dislodge collected particul ate matter, which falls in to hoppers for removal. Collector dust is removed
from the precipitator for dispos al, recycling or reprocessing.

Since ESP’s use electrical forces for particle collec tion, the electrical proper ties of the particles can
adversely impact ESP operation. Particles with high resistivity may not readily accept an electric
charge and will be difficult to co llect. Particles with high conduct ivity or magnetic properties, such
as iron, will strongly adhere to the coll ection plates and be difficult to remove.

ESP control efficiency under normal loading conditi ons typically is in the 98% - 99%+ range.
Reduced efficiencies will occur when the inlet particle concentration is low. ESP controls do not
affect the temperature of the stream being treate d; so, condensable partic ulate matter control is
limited to condensable particulates already present in a filterable form in ESP. Outlet particle

concentrations can be as low as 0.005 gr/dscf; however, outlet concentrations achieved will depend
on the size range and nature of the particles. Therefore, ESPs are most effective controlling sources

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# with filterable particulates and less effective controlling hot exhaust st reams with condensable
particulates.



# 4.2.3 Wet Electrostatic Precipitators (WESP)

A wet electrostatic precipitator operates in the same manner as a dry ESP; it applies electric forces to
separate suspended particles from the flue gas stream. However, particle removal in a WESP is
accomplished with water sprays instead of mechan ical cleaning methods. In a WESP, an intense

electrostatic field is maintained between high-voltage discharge elec trodes, typically wires or rigid
frames, and grounded collecting electr odes, typically plates. A corona discharge from the discharge
electrodes ionizes the gas passing through the prec ipitator, and gas ions subsequently ionize the
particles. The electric field drives the negatively charged particles to the collecting electrodes. As a
result of using water sprays, WESPs generate wastewater which must be treated to remove suspended
particles and dissolved solids.

Since WESPs use electrical forces for particle collection, the electrical properties of the particles can
adversely impact WESP operation. Particles with high resistivity ma y not readily accept an electric
charge and will be difficult to co llect. Particles with high conduct ivity or magnetic properties, such
as iron, will strongly adhere to the collection plat es and be difficult to remove; WESP water sprays
may reduce this problem. However, WESP water sp ray systems will require more maintenance than
dry ESP’s in order to keep the water spray system working properly. The temperature of an exhaust
gas may be reduced in a wet ESP due to evaporat ive cooling by the ESP spray water. Since wet
ESP’s use water, they may also capture particul ate matter composed of water soluble salts.

Therefore, wet ESP’s are more like ly to control condensable partic ulates than a baghouse or dry ESP.

WESP control efficiency under normal loading conditions typically is in the 98% - 99%+ range.
Reduced efficiencies will occur when the inlet particle concentration is low. Outlet particle

concentrations can be as low as 0.005 gr/dscf; however, outlet c oncentrations achieved will depend
on the size range and nature of the particles being filtered.



# 4.2.4 Wet Scrubbers

Wet scrubbers, also termed par ticulate scrubbers, remove particle s from waste gas by capturing the
particles in liquid droplet s (usually water) and separating the droplets from the gas stream. The
droplets transport the particul ate out of the gas stream.

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# Scrubbers may capture particulates through the following mechanisms:

• Impaction of the particle directly into a target droplet.

• Interception of the particle by a target dr oplet as the particle comes near the droplet.

• Diffusion of the particle through the gas surrounding the target droplet until the particle is close
enough to be captured.

Scrubbers are generally classified according to the liquid contacting mechanism used. The most
common scrubber designs are spray-chamber scrubbe rs, cyclone spray chambers, orifice and wetimpingement scrubbers, and venturi scrubbers.

Operating conditions inside of a scrubber can be very corrosive if acid gases are present in the waste
gas, and highly abrasive particulate matter can ca use erosion problems. These conditions lead to
reduced equipment operating life, and/or increased capital cost for materials of construction.

Scrubber control efficiency under normal loading conditions typically is in the 98% - 99%+ range.
Scrubber efficiency is a function of pressure drop across the scrubber. So, higher collection
efficiencies will consume more electrical power to operate the scrubber blower. The temperature of
an exhaust gas may be reduced in a wet scrubber due to evaporative cooling by the scrubber water.
Since wet scrubbers use water, they may also captu re particulate matter co mposed of water soluble

salts. Therefore, wet scrubbers are more likely to control conden sable particulates than a baghouse
or dry ESP. Reduced efficiencies will occur when the inlet particle concentration is low. Outlet
particle concentrations can be as low as 0.005 gr/d scf; however, outlet concentrations achieved will
depend on the size range and nature of the particles.



# 4.2.5 Mechanical Collectors

Mechanical collectors use a variety of mechanical forces to collect particulate matter:

• Inertial separators use inertia and gravity to rem ove the larger particles from the smaller ones.

• Cyclones use centrifugal force to separat e particulate matter from gas streams.

Drop out boxes are typically used as inertial separators. Larger particles are trapped in drop out
boxes as the inertia they contain forc es them to go straight as the rest of the gas stream turns to flow
into and out of the drop out box. Particles are also removed by gravitational settling in the drop out

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# box. Inertial separators can only remove the larger dust particles (>75 microns). They are typically
used upstream of other c ontrol devices in high inlet dust loading cases.

Cyclone separators are designed to remove particle s by inducing a vortex as the gas stream enters the
chamber, causing the exhaust gas stream to flow in a spiral pattern. Centrifugal forces cause the
larger particles to concentrate on the outside of th e vortex and consequently sl ide down the outer wall
and fall to the bottom of the cyclone, where they are removed. The cleaned gas flows out of the top
the cyclone.

There are two principal types of cyclones: tangential entry and axial entry. In tangential entry
cyclones, the exhaust gas enters an opening located on the tangent at the top of the unit. In axial
flow cyclones, the exhaust gases enter at the midd le of one end of a cylinder and flows through vanes
that cause the gas to spin. A peripheral stream removes collected particles while the cleaned gas
exits at the center of the opposite end of the cylinder.

Overall cyclone control efficiencies range from 50 % to 99% with higher effi ciencies being achieved
with large particles and low efficiencies for smaller particles (< PM 10 

# ). Mechanical controls do not
affect the temperature of the stream being treated; therefore, condensable particulate matter control is
limited to condensable particulates already present in a filterable form in the exhaust when it is being
treated. Mechanical separators are often used upstream of other PM control devices to reduce the
loading on the primary control device. This impr oves overall control efficiency and may reduce the
overall cost of the control system when the waste gas is heavily laden with particulate matter.



# 4.2.6 Good Design Methods and Operating Practices
Good design includes process and mechanical equipm ent designs which are either inherently lower
polluting or are designed to minimize emissions.

Good operating practices include operating methods, procedures and selectio n of raw materials to

minimize emissions.

Since these methods are generally source specific (e.g. good operating practices for PM control), they
will be addressed for each process when such measures are available.



# 4.3 Visible Emissions

Visible emissions are the result of particulate mate rials which are present in sufficient quantities under the
appropriate weather conditions to cause the dispersion of light such that exhaust plumes are visible to the

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# human eye. i.e. plumes become partially opaque. Visible emissions have historically been used as a
surrogate for particulate emissions monitoring.

Because visible emissions are directly related to particulate emissions, BACT controls for visible

emission are the same as PM/PM 10 

# BACT control.



# 4.4 Sulfur Dioxide (SO 2 

# ), Sulfuric Acid Mist and Gaseous Fluoride Emission Control Technologies

Sulfur dioxide, sulfuric acid mist, and fluoride em issions are concurrently generated from certain
sources in the Minnesota Steel project. Sulfuric acid mist is formed from sulfur trioxide (SO 3 

# )
reacting with water in exhaust streams. SO 3 

# (and SO 2 

# ) is formed when sulfur in raw materials and/or
fuels is oxidized by either process conditions or by combustion. Fluorides are emitted in a gaseous
state from iron ore at induration temperatures. All three gases can be c ontrolled hand-in-hand with
similar, most often the same piece of pollution control equipment. Therefore, the descriptions of
technologies for controlling these pollutants ar e discussed together in this section.



# 4.4.1 Flue Gas Desulfurization (FGD)

There are many availabl e FGD systems including wet scrubbing, spray dryer absorption and dry
sorbent injection. The FGD systems currently in use to control SO 2 

# emissions can be classified as
wet and dry systems.



# 4.4.2 Dry Scrubbing - Lime/Limestone Injection

Dry sorbent injection involves the injection of a lime or limestone powder into the exhaust gas
stream. The process was developed as a lower cost FGD option because the mixing occurs directly
in the exhaust gas stream instead of in a separate tower. Sorbent injection control efficiency is
typically in the 50% range.



# 4.4.3 Dry Scrubbing - Spray Dryer Absorption

Spray dryer absorption is a dry scrubbing system that sprays a fine mist of lime slurry into an
absorption tower where the pollutants (SO 2 

# , SAM, and F) are absorbed by the droplets. The
absorption of the SO 2 

# and SAM leads to the formation of calcium sulfite (CaSO 3 

# ● 2H 2 

# O) and calcium
sulfate (CaSO 4 

# ) within the droplets. The adsorption of fluorides leads to the formation of CaF 2 

# . The
liquid-to-gas ratio is such that the heat from the exhaust gas causes the water to evaporate before the
droplets reach the bottom of the tower. This lead s to the formation of a dr y powder which is carried

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# out with the gas and collected with a fabric filter. Spray dryer absorption control efficiency is
typically in the 70% to 90% range.



# 4.4.4 Wet Lime/Limestone Scrubbing

Wet lime/limestone scrubbing involves scrubbing the ki ln exhaust gas stream with a slurry comprised
of lime (CaO) or limestone (CaCO 3 

# ) in suspension. The process takes place in a wet scrubbing tower

located downstream of a PM control device to prevent the plugging of spray nozzles and other
problems caused by the presence of pa rticulates in the scrubber. The SO 2 

# and SAM in the gas stream

reacts with the lime or limestone sl urry to form calcium sulfite (CaSO 3 

# ● 2H 2 

# O) and calcium sulfate
(CaSO 4 

# ). The F- in the gas stream reacts to form CaF 2


# .



# 4.4.5 Good Design Methods and Operating Practices
Good design includes process and mechanical equipm ent designs which are either inherently lower
polluting or are designed to minimize emissions.

Good operating practices include operating methods, procedures and selectio n of raw materials to

minimize emissions.

Since these methods are generally source sp ecific (e.g. good operating practices for SO 2 

# control),
they will be addressed for each process when such measures are available.



# 4.5 Nitrogen Oxides (NO x 

# ) Emission Control Technologies

4.5.1 Sources of NOx Emissions

There are three mechanisms by which NO
x 

# production occurs and they ar e thermal, fuel and prompt

NO
x 

# formation.

In the case of natural gas combustion, the primary mechanism of NO
x 

# production is through thermal

NO
x 

# formation. This mechanism arises from th e thermal dissociation of nitrogen and oxygen

molecules in combustion air. The thermal oxidation reaction is as follows:

N 2 

# + O 2 

# → 2NO (1)

Downstream of the flame, significant amounts of NO 2 

# can be formed when NO is mixed with air.

The reaction is as follows:

2NO + O 2 

# → 2NO 2 

# (2)

Thermal oxidation is a function of the residence time, free oxygen, a nd peak reaction temperature.

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# Prompt NO
x 

# is a form of thermal NO
x 

# which is generated at the flam e boundary. It is the result of
reactions between nitrogen and ca rbon radicals generated during combustion. Only minor amounts

of NO
x 

# are emitted as prompt NO
x 

# .

Fuel bound NO
x 

# is primarily a concern with solid and liquid fuel combustion sources; it is formed as
nitrogen compounds in the fuel are oxidized in the combustion process. Natural gas has minimal fuel
bound nitrogen which eliminates fuel bound NO
x 

# as a major concern.



# 4.5.2 Identification of NO x 

# Control Technologies

Combustion Controls

Various combustion controls exist for NO
x 

# reduction from combustion units. A few feasible
examples of these controls incl ude Low Excess Air (LEA), Low NO
x 

# Burners (LNB) and oxy-fuel

burners.

Low Excess Air (LEA)



# LEA is a good combustion practice for minimizing NOx emissions. LEA is implemented by limiting

the amount of air used in fuel combustion, and by preventing air leaks into the furnace/boiler

combustion zone. LEA reduces NO x emissions by limiting the amount of oxygen in the combustion
zone which can react with nitrogen to form NOx. The LEA control efficiency is typically in the 1% -
15% range.

Low NO x 

## Burners (LNB)



# LNB technology utilizes advanc ed burner design to reduce NO
x 

# formation through the restriction of
oxygen, flame temperature, and/or residence time. LNB is a staged combustion process that is
designed to split fuel combustion into two zones. In the primary zone, NO
x 

# formation is limited by

either one of two conditions. Under a rich (high fuel) condition, oxy gen levels and flame
temperatures are low resulting in less NO
x 

# formation. The primary zone is then followed by a
secondary zone in which the incomplete combusti on products formed in th e primary zone act as
reducing agents. Alternatively, under lean (low fuel) conditio ns, excess air will reduce flame
temperature to reduce NO
x 

# formation. In the secondary zone, combustion products formed in the
primary zone act to lower the local oxygen concentration, r esulting in a decrease in NO
x 

# formation.
Due to the reduced flame temperatures, low NO
x 

# and ultra low NO
x 

# burners have higher CO emission
rates than uncontrolled burners. Low NOx burners typically achieve NO
x 

# emission reductions of

25% - 50%.

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# Second generation low NO
x 

# burners are called Ultra Low NO
x 

# Burners (ULNB). These burners
achieve NOx reductions in the 50% - 75% range. This is accomplished by recirculating firebox flue
gas within the burner to accomplish the same effect as external flue gas recirculation. Recirculation
can be convectively induced or mechanically induced via fuel pressure. Tertiary fuel staging is

another method used in ULNB.

Oxy-fuel Burners



# Oxy-fuel burners are used in high temperature app lications like the electric arc furnaces. Oxy-fuel

burners combust natural gas using pure oxygen. Under norm al combustion, both the oxygen and
nitrogen in the combustion air must be heated up to combustion temperatures. Oxy-fuel burners use
pure oxygen instead of air. Therefore, no energy is expended in heating up atmospheric nitrogen.
Because of this, oxy-fuel burners use 70% of the fuel used by standard burners in steel production.

Theoretically, combustion with pure oxygen will lower NO
x 

# emissions because nitrogen is not
present in the combustion zone. However, some atmospheric nitrogen is present in EAFs, which

lowers the NO
x 

# control effectiveness of oxy-fuel burners. Based on the draft AP-42 emission factors
for EAFs in Chapter 12.5, Table 12.5.1-4, the use of oxy-fuel burners and oxygen lances reduces NO
x 

# emissions by approximate ly 10% on a lb of NO
x 

# per ton of steel produced basis.

Non-Selective Catalytic Reduction (NSCR)

A non-selective catalytic reduction (NSCR) syst em is a post combustion add-on exhaust gas
treatment system. NSCR catalyst is very sensitive to poisoning NSCR is usually applied primarily
in natural gas combustion applications. NSCR is often referred to as “three-way conversion” catalyst
because it simultaneously reduces NOx, unburned hy drocarbons (UBH), and CO. Typically, NSCR

can achieve NOx emission reductions of 90%. In order to operate properly, the combustion process

must be near stoichiometric conditions. Under th is condition, in the pres ence of a catalyst, NO
x 

# is
reduced by CO, resulting in nitrogen (N 2 

# ) and carbon dioxide (CO 2 

# ). The most important reactions

for NO
x 

# removal are:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (2)

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# Selective Catalytic Reduction (SCR)

Selective catalytic reduction is a post combustion NO
x 

# control technology in which ammonia (NH 3 

# )
is injected into the flue gas stream in the presence of a catalyst. SCR control efficiency is typically

70% - 90%. NO
x 

# is removed through the fo llowing chemical reaction:

4NO + 4NH 3 

# + O 2 

# → 4N 2 

# + 6H 2 

# 0 (1)

2NO 2 

# + 4NH 3 

# + O 2 

# → 3N 2 

# + 6H 2 

# 0 (2)

The catalyst bed lowers the activation energy required for NO
x 

# decomposition. The catalyst contains
metals in the platinum family and these are used for their ability to lower the activation energy
required for NO
x 

# decomposition reaction. SCR requires an optimum temperature range of 570-

850 ° F.

Selective Non-Catalytic Reduction (SNCR)
In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to
convert NO to molecular nitrogen, N 2 

# , and water. SNCR control efficiency is typically 50% - 75%.
Without the participation of a catalyst, the reac tion requires a high temper ature range to obtain
activation energy. The relevant reactions are as follows:

NO + NH 3 

# + 1⁄4O 2 

# → N 2 

# + 3/2 

# H 2 

# O (1)

NH 3 

# + 1⁄4O 2 

# → NO + 3/2 

# H 2 

# O (2)

At temperature ranges of 1470 to 1830 ° F reaction (1) dominates. At temperatures above 2000 ° F,
reaction (2) will dominate.

NO x 

## OUT ®



# NO
x 

# OUT ® is a commercially available urea based SNCR process for the reduction of NO
x 

# from
stationary sources. The process requires injection of stabilized urea liquid into the combustion flue
gas in a location where the te mperature range is 1,600 - 2,000 ° F.

Low Temperature Oxidation (LTO)

A LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including NO
x 

# . NO
x 

# in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2, and 3). Nitrogen
pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas (4). Then the nitric

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# acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium hydroxide or lime in the
scrubbing solution forming sodium nitrate (5) or calc ium nitrate. The nitrates in the scrubbing system
are discharged to an appropriate water treatment system. Commercially available LTO systems

include Tri-NO
x 

# ® and LoTOx.

NO + O 3 

# → NO 2 

# + O 2 

# (1)

NO 2 

# + O 3 

# → NO 3 

# + O 2 

# (2)

NO 3 

# + NO2 → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O → 2HNO 3 

# (4)

HNO 3 

# + NaOH → NaNO 3 

# + H 2 

# O (5)

Tri-NO x 

## ®



# This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

# in a
primary scrubbing stage. Then NO 2 

# is removed through caustic scrubbing in a secondary stage. The

reactions are as follows:

O 3 

# + NO → O 2 

# + NO 2 

# (1)

2NaOH + 2NO 2 

# + 1⁄2 O 2 

# → 2NaNO 3 

# + H 2 

# O (2)

Tri-NO
x 

# ® is a commercially available mu lti-staged wet scrubbing proce ss in industrial use. Several
process columns, each assigned a separate processi ng stage, are involved. In the first stage, the
incoming material is quenched to reduce its temp erature. The second, oxi dizing stage, converts NO

to NO 2 

# . Subsequent stages reduce NO 2 

# to nitrogen gas, while the oxy gen becomes part of a soluble
salt. A major advantage of the Tri-NO
x 

# ® process is that concurrent scrubbing of SO 2 

# can be
achieved. Tri-NOx is typically applied at small to medium sized sources with high NO
x 

# concentration in the exhaust gas (1,000 ppm NO
x 

# ). Under only these high NOx concentration

conditions control efficiencies of 99% can be achieved. Exhaust gas concentrations of NO
x 

# from this
type of source using Tri-NO
x 

# ® are in the 25 ppm to 50ppm NO
x 

# range. However, the concentration

from the Minnesota Steel sources are all much less than 1000 ppm and therefore this technology
would nto be applicable.

LoTOx



# BOC Gases’ Lo-TOx is another version of a LT O system. LoTOx is an innovative NOx control
technology which, to date, has not been applied to a taconite induration furnace or a source with

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# similar size and exhaust gas char acteristics. LoTOx technology uses ozone to oxidize NO to NO 2


# and NO 2 

# to N 2 

# O 5 

# prior to removal in a wet scrubber (absorber). The N 2 

# O 5 

# is converted to HNO 3 

# in
the scrubber, and may be treated with lime or caustic. The same scrubber may also be used for
particulate or sulfur dioxide removal. Ozone for LoTOx is generated on site with an electrically
powered ozone generator. The ozone generation rate is controlled to match the amount needed for

NO
x 

# control. Ozone is ge nerated from pure oxygen. In order fo r LoTOx to be economically feasible,
a source of low cost oxygen must be available from a pipeline or on site gene ration. Since oxygen is
needed for the steel making proce ss, Minnesota Steel will have on site oxygen producti on facilities.

The normal NO
x 

# control efficiency range for Lo-TOx is 80% to 95% with outlet NO
x 

# concentrations
in the 15ppm – 25 ppm range.

Good Design Methods and Operating Practices
Good design includes process and mechanical equipm ent designs which are either inherently lower
polluting or are designed to minimize emissions.

Good operating practices include operating methods, procedures and selectio n of raw materials to

minimize emissions.

Since these methods are generally source sp ecific (e.g. good operating practices for NO
x 

# control),
they will be addressed for each process when such measures are available.

Other NO x 

# Controls Potentially Applicable to the Minnesota Steel Project

The NO
x 

# emission controls listed above represent available technologies which are reasonably
available and are typically consid ered in a BACT review. Other potential, though less developed,
technologies exist and were also eval uated. Most of these controls were not considered because they
were not commercially available, or are variati ons on controls which were found to be technically
infeasible. Table 4-1, summarizes the applicability of each control listed in this article to the
Minnesota Steel Project:

Table 4-1 NOx Control Technology Completeness Review

NOx Control Technology Considered in Minnesota Steel NOx BACT Review?

Low NOx Burners with multi level Overfire Air Not Applicable. BACT review found OFA systems technically infeasible in Minnesota Steel sources.

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## NOx Control Technology Considered in Minnesota Steel NOx BACT Review? Rotating Opposed Fire Air Not Applicable. Variation of OFA, BACT review found OFA systems technically infeasible in Minnesota Steel

sources. Reburning Not Applicable. Requires large combustion zone similar to a coal fired utility boiler. None of the Minnesota Steel sources are configured in this manner. Advanced Gas Reburning (AGR) Not Applicable. Requires large combustion zone similar to a coal fired utility boiler. None of the Minnesota Steel sources are configured in this manner. Fuel-Lean Gas Reburning(FLGR) Not Applicable. Requires large combustion zone similar to a coal fired utility boiler. None of the Minnesota Steel sources are configured in this manner. Amine-Enhanced Fuel-Lean Gas Reburning (AEFLGR) Not Applicable. Requires large combustion zone similar to a coal fired utility boiler. None of the Minnesota Steel sources are configured in this manner. Hybrid-Selective Reduction (HSR) Variation on controls included in BACT review. HSR is a combination of SNCR and SCR.

In Duct SCR Variation on controls included in BACT review. Site specific application of SCR to address limited plot space. Layered NOx control for cyclone boilers Not Applicable. None of the Minnesota Steel sources are coal fired cyclone boilers Oxygen-enhanced combustion Not Applicable. Type of staged combustion. Uses same principles as OFA. Requires large combustion zone similar to a coal fired utility boiler. None of the Minnesota Steel sources are configured in this manner. Refinements for low NOx tangential firing systems Not Applicable. None of the Minnesota Steel sources are tangentially fired coal boilers
Preheat combustion systems Not Applicable. Variation of reburning; requires large combustion zone similar to a coal fired utility boiler. None of the Minnesota Steel sources are configured in this

manner. Electron Beam Not commercially available.

ROFA/ROTAMIX Not Applicable. Variation of OFA, BACT review found OFA systems technically infeasible in Minnesota Steel sources. ROTAMIX is a type of SNCR. SNCR was included in the BACT review SNOX Not commercially available. SOx-NOx-ROx-Box (SNRB) Not commercially available. Activated Coke Not commercially demonstrated in United States. Adverse environmental Impacts:



##  SO 2 

## generated as a byproduct of carbon regeneration.



##  Must dispose of activated carbon fines. Costly to operate:



##  High capital cost; need two reactors plus carbon regeneration system vs. one reactor for SCR.



##  High reagent costs Electro Catalytic Oxidation (ECO) Not commercially available. NOXSO Not commercially available. Copper-Oxide Not commercially available.

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# 4.6 Carbon Monoxide (CO) and Volatile Organic Compound (VOC) Emission Control Technologies

CO will be emitted as a result of incomplete combustion natural gas in heaters and boilers. It is also
formed in the EAF from charged and injected carbon, the foaming slag operating practice, and the
graphite electrodes reacting with in jected air or oxygen. CO will also be emitted from the cooling
water blowdown systems at the DRI plant.



# 4.6.1 Catalytic Incineration

Catalytic oxidation systems are designed to pass combustion gases over a catalyst bed that promotes
oxidation, e.g. convert CO to CO 2 

# . The oxidation process requires temperatures of 600 to 1,000°F to
achieve 90 to 95 percent conversion of CO. The cata lyst increases the reaction rate and allows the

conversion of CO to CO 2 

# at lower temperatures than a normal thermal incinerator. The catalyst is
typically porous noble metal material, which is suppor ted in individual compartments within the unit.
An auxiliary fuel-fired bu rner ahead of the bed heats the ente ring exhaust gases to 500°F - 600°F to
maintain proper bed temperature. Recuperative heat exchangers are used to recover the heat in the
exiting gas heat in order to reduce the auxiliary fuel consumption. Secondary energy recovery is
typically 70 percent.



# 4.6.2 Thermal Oxidation
Thermal oxidation is the process of oxidizing combustible materials by raising the temperature of the
material above its auto-ignition point in the pr esence of oxygen, and maintaining it at high
temperature for sufficient time to complete co mbustion to carbon dioxide and water. Time,
temperature, turbulence (for mixing) , and the availability of oxygen all affect the rate and efficiency
of the combustion process. These factors provide the basic design paramete rs for thermal oxidation

systems.

There are three basic types of thermal oxidation systems: direct flam e, recuperative, and
regenerative.

Direct flame systems or flares rely on contact of the waste stream with a flame to achieve oxidation.
These systems are the simplest thermal oxidizers and the least expensive to install, but require the
greatest amount of auxiliary fuel to maintain the oxidation temperature, thus incurring the highest
operating cost.

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# Recuperative thermal oxidation systems use a tube or plate heat exchanger to preheat the effluent
stream prior to oxidation in the combustion chambe r. Thermal recovery effi ciencies typically are
limited to 40-70% to prevent auto-ignition in the heat exchange package, which could damage the
equipment. Supplemental fuel ther efore is usually required to main tain a high enough temperature for
the desired destruction efficiency. Recuperative systems are more expensive to install than flares,
but have lower operating costs.

Regenerative thermal oxidation (RTO) systems typically incorporate multiple ceramic heat exchanger
beds to produce heat recovery ef ficiencies as high as 95%. An incoming gas stream passes through a

hot bed of ceramic or other material, which simult aneously cools the bed and heats the stream to
temperatures above the auto-ignition points of its or ganic constituents. Oxida tion thus begins in the
bed, and is completed in a central combustion chamber, after which the clean gas stream is cooled by
passage through another ceramic heat exchanger. Pe riodically the flow through the beds is reversed

to recover the heat from the hot bed, while c ontinuous flow through the unit is maintained.



# 4.6.3 Good Design Methods and Operating Practices
Good design includes process and mechanical equipm ent designs which are either inherently lower
polluting or are designed to minimize emissions.

Good operating practices include operating methods, procedures and selectio n of raw materials to

minimize emissions.

Since these methods are generally source specific (e.g. good operating practices for minimizing CO
emissions), they will be addressed for each process when such measures are available.



# 4.7 Hydrogen Sulfide (H 2 

# S) Emission Control Technologies

Hydrogen Sulfide (H 2 

# S) is a byproduct of the DRI process. It is not emitted from any other process
at Minnesota Steel Industries. Each of the DRI plants has a Tail Gas Purification unit to treat the
spent DRI reducing gas (top gas). The main pur pose of the purification units is to remove CO 2 

# from
the top gas in order to concentrate the reductants in the top gas. A chemical solution used to remove

CO 2 

# from the reducing gas. H 2 

# S present in the top gas is also captured by this solution. When the
solution is regenerated, the CO 2 

# and H 2 

# S are released. This off gas steam is treated to control H 2 

# S
emissions prior to releasing it to the atmosphere. See the DRI process description in Section 8.1 for

additional information.

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# 4.7.1 Sulfur Recovery - LoCAT

One method of controlling H 2 

# S emissions is to convert the H 2 

# S to elemental sulfur. LoCAT is one
commercially available sulfur recovery process which has been successfully applied to the DRI
process. LoCAT uses an iron based catalyst. The reactions take place in water, and elemental sulfur
is recovered in solid form. In the process H 2 

# S is first absorbed by a slightly basic aqueous LoCAT

solution and ionizes to bisulfide. Next the reduct ion of the iron catalyst oxidizes the bisulfide to
elemental sulfur. Oxygen from the atmosphere then re-oxidizes the iron to regenerate the catalyst.
The overall isothermal reaction is a less expensive way of performing a modified Claus reaction.

The reactions are as follows:

H 2 

# S (g) + H 2 

# O ↔ H 2 

# S (l) (1)

H 2 

# S (l) → HS - 

# + H + 

# (2)

HS - 

# + 2Fe +++ 

# → S 0 

# (s) + 2Fe ++ 

# + H + 

# (3)

1/2O 2 

# (g) + H 2 

# O → 1/2O 2 

# (l) (4)

1/2O 2 

# (l) + 2Fe ++ 

# + H 2 

# O → 2Fe +++ 

# + 2OH - 

# (5)



# 4.7.2 Absorption – Zinc Oxide
Absorption is another means of controlling H 2 

# S emissions. In this case, the H 2 

# S chemically reacts
with the sorbent and is removed from the gas stream. Zinc oxide is commonly used as a sorbent for

H 2 

# S removal when H 2 

# S is present in low concentrations. Typically, two or more sorbent vessels are
employed. During the majority of operations , the second vessel is a backup to the primary
absorption vessel. When the sorbent in the primary vessel is spent, the second absorber is used for
treatment while the sorbent in the primary vessel is being replaced. Spent zinc oxide is disposed of

as a solid waste.



# 4.7.3 Oxidation

Like CO and VOCs, H 2 

# S can be destroyed by oxidation. Oxidation is used to eliminate the odor

issues associated with H 2 

# S, which H 2 

# S can cause odor problems at lo w ppm concentrations. In an

oxidizer, H 2 

# S is oxidized to form SO 2 

# . SO 2 

# emissions are much less odorous and therefore, less
objectionable than H 2 

# S emissions. There are many available oxidation systems as described in
Section 4.5. Catalytic oxidations systems are not applicable in this application as the catalysts are
susceptible to poisoning by H 2 

# S.

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# 4.7.4 Flue Gas Desulfurization (FGD) Following Oxidation

There are many availabl e FGD systems including wet scrubbing, spray dryer absorption and dry
sorbent injection as described in Section 4.3. FG D would be employed downstream of an oxidizer to

minimize collateral SO 2 

# emissions.



# 4.8 Compliance with BACT during Startup, Shutdown and Malfunction

For periods of startup, shutdown and malfuncti on, Minnesota Steel proposes to follow Good Air

Pollution Control Practices for Minimizing Emissions as BACT. To achieve this, Minnesota Steel
Industries will at all times, including periods of startup, shutdown, and malfunction, operate and
maintain the facility’s operating equipment, associated air pollution control equipment and
monitoring equipment, in a manner consistent with safety and good air pollution control practices for
minimizing emissions.

Startups and, shutdowns are infrequent events associated with maintenance of the facility which
usually occur no more than two or three times per year on any individual operating unit. Typically,
operating equipment is taken out of service once pe r year for inspection, repair and preventative
maintenance. Other startup and shutdown events during the year are associated with planned
shutdowns to repair equipment which cannot be fixe d while the unit is operating or shutdowns due to
unplanned equipment failures (malfunctions). Ac tions taken during annual maintenance inspections
are designed to minimize the numb er of shutdowns due to malfunctions and maintenance during the
remainder of the year.

During periods of startup, shutdown and malfunct ion, temperatures, pressures and flows in process
equipment vary significantly over time. As the process transitions into/ out of normal operation
conditions, it is not possible to keep emissi on control equipment operating at optimum control
efficiency due to changing conditions. In additio n, some emissions control equipment must reach
proper operating temperatures befo re it can achieve the desired emissions control efficiency.
Therefore, compliance with BACT limitations for normal operations cannot be guaranteed at all
times during startup, shutdown and malfunction conditions. By following good Air Pollution Control

Practices, Minnesota Steel will minimize both the extent and duration of excess emissions. In
addition to following good opera ting practices for minimizing emis sions, Minnesota Steel Industries
will operate its facility so that emissions will not exceed the emissions to the rates listed in

Attachment M, Table 1 at the emission units whic h cannot meet BACT limitations during startup and

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# shutdown. The BACT report identifies those cond itions where applicable BACT limitations for
normal operations cannot be met at all times during star tup, shutdown and malf unction. Specific

measures which Minnesota Steel will follow to minimize emissions as good air pollution control
practices include:

• 

# During startup, emission control equipment will be put into operation prior to the startup of
process equipment when it is feasible to do so.

• 

# During startup, process equipment and emissi on control equipment will be brought to proper
operating conditions as soon as practicable, and in a manner consistent with safety and process

limitations in order to minimize emissions.

• 

# During shutdown, emission control equipment will remain in service until the process is shut

down when it is feasible to do so.

• 

# During shutdown, process equipmen t will be taken out of service as soon as practicable, and in a
manner consistent with safety and process limitations in order to minimize emissions.

• 

# When practicable, planned startups and shutdown s of process units within the facility will be
phased. This will minimize the number of s ources, which at any gi ven time; have excess
emissions due to startup and shutdown activities.

• 

# During periods of malfunction, Minnesota Stee l will identify and correct the cause of the
malfunctions as soon as practi cable, and/or will consider taking the malfunctioning equipment
out of service until it can be operated in a ma nner consistent with the applicable environmental
requirements.

Minnesota Steel will prepare a startup, shutdown and malfunction plan spec ifying the actions to be
taken during startup, shutdown a nd malfunctions, and when the re quirements of the startup,
shutdown and malfunction plan are applicable. Specifics of the startup shutdown and malfunction
plan cannot be determined at this time because th e facility has not been completely designed. A
startup shutdown and malfunction plan will be prepared prior to the initial startup of the facility. As
noted above, plans for startup, shutdown and ma lfunction will follow all safety requirements.

The proposed startup and shutdown emission limits for emission units which cannot meet the normal
operation BACT during startup and shutdown are listed in BA CT Attachment M Table 1.

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# 5.0 Mining and Crushing

5.1 Overview of Mining and Crushing

Mining and crushing are sources of particulate matter emissions. The processes analyzed in this
section are materials handling and fugitive emissions.

The taconite ore is extracted from the earth in an op en pit mine. First the earth and rock on top of the
ore (overburden) are removed with controlled blasting, diesel-hyd raulic shovels and 205-ton haul
trucks. These materials will be stockpiled near the mine pits to minimize the time for haul truck
round trips. Stripping rates will va ry, but the general goal is to st rip one ton of overburden and waste
rock per ton of ore for the life of the mine. Afte r overburden stripping, wast e rock and taconite ore
will be blasted and then loaded into mine trucks by diesel-hydraulic shovels. The raw ore will be
trucked out of the pit to the crushers. Crushed or e will be conveyed to the concentrator plant ore
barn or stockpiled next to the crushers. Waste rock from the crusher operation will be categorized
for use in dike construction, haul road construction or for stockpiling.

The mining and crushing operations are sources of fugitive particulate ma tter emissions. Point

source emissions from mi ning operations include the ore crushers, screeners and conveyor drops.
Fugitive sources include ore loading, truck traffic, stockpiling of overburden, waste rock and ore, and
wind erosion of stockpiles.

Liberation of iron minerals is the first step in pr ocessing crude taconite ore and consists mostly of
crushing and milling (grinding). This step will redu ce mined ore to the appr opriate size for further
processing. Primary and secondar y crushers crush dry ore and are sources of particulate matter.



# 5.2 Mining and Crushi ng Material Handling Process and Emission Description

In the mining section of the plant, material ha ndling equipment include ore crushing equipment, ore
screening and ore conveyor drops. Primary and sec ondary crushers operate on dry ore and are subject
to BACT requirements for particulate control. Tertiary ore size reduc tion takes place in an
autogenous grinder which is a wet pr ocess; therefore, it is not a s ource of particulate emissions.

In order to simplify the BACT report, emission controls for material handling equipment throughout
the facility are reviewed in Section 11 of this report. Material handing equipment reviewed in

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# Section 11 includes conveyor drops, crushing and gr inding operations and scre ening of raw materials
and intermediate products. Sect ion 11 also contains a list of sources covered by the material
handling BACT analysis.



# 5.2.1 BACT Selection Summary for Mi ning and Crushing Material Handling
BACT for material handling in the mining and crushing ar ea of the facility is the use of a fabric filter
in conjunction with a ventilated enclosure of the emission source. The proposed BACT limit for
particulate emissions is 0.0025 gr/dsc f as measured by EPA Method 5.

For periods of startup and shutdown, Minnesota St eel will put material handling particulate emission
control equipment into service prior to commencing operation of process equipment, and keep controls
operating until the process is shut dow n and off line. No excess emissions will occur as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 5.3 Fugitive Dust Emissions

Sources of fugitive particulate emissions from mi ning operations at Minnesota Steel include drilling,
unpaved roads, storage piles, loading and unloadi ng operations, and materi al drops from mobile
equipment.

In order to simplify the BACT report, fugitive s ources throughout the facility are reviewed in Section
15 of the BACT report including mining operations, tailings basins, unpaved roads, storage piles,
loading and unloading operations, and material drop s from mobile equipment. Section 15 also

contains a list of sources covered in the fugitive dust BACT analysis.



# 5.3.1 BACT Selection Summary of Mini ng and Crushing Operations Fugitive Emissions
Minnesota Steel will follow industry best practices for controlling fugitive dust emissions. Minnesota
Steel has prepared a fugitive dust control plan (Attachment O) which describes the measures
Minnesota Steel will take to control these emissions. Dust control measures listed in the plan are
consistent with dust control techniques used by other mining facilities in the area.

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# 6.0 Concentrator

6.1 Concentrator Plant Overview

The present day ore concentration process, the process being employed by Minnesota Steel, uses the
magnetic property of magnetite (FE 3 

# O 2 

# ) to achieve separation from waste rock. That separation is
also enhanced by milling the ore to a very fine consistency.

From the storage area, crushed ore wi ll be conveyed to a series of wet semi-autogenous mills and ball
mills to be ground to a flour-like consistency (>90% at 325-minus mesh). Concentration is the second
step in taconite ore processing. After the milling steps liberate the iron ore minerals, the iron-bearing
particles must be concentrated. Magnetic separation is used to separate the magnetite form of iron
(Fe 3 

# O 4 

# mineral) from the waste rock (tailings). The concentrate will be further refined by flotation,

which will remove the more silica-rich material, leaving nearly pure iron oxide minerals. The iron
concentrate will be pumped in slurry form to the pellet plant for pellet fo rmation and induration.

Because only about 33 percent of the crude taconi te ore becomes concentrate for iron making, about
67 percent must be transferred to stockpiling as tai lings. Tailings rejected by primary and secondary
magnetic separation processes will be pumped as 30 percent slurry to the tailings basin located
several miles southeast of the plant. When the slurry reaches and spreads out into the tailings basin,
flow velocity decreases and the tailings settle out of the water to form a tailings stockpile. Water
will form a reservoir at the center of the basin and will be recycled back to the plant as process water.

Emission sources associated with the concentrator plant operations include fugitive emissions from
the storage piles and from conveyor loading and unloading. The concentrator plant has relatively few
air emission points because the processes involved are wet under normal oper ations and there are no
significant combustion emissions. Air emission point sources at the concentrator plant are all related
to ore conveying. Fugitive air emission sources are related to coarse ore storage and reclaim, cobber
(lean ore) rejects stockpi ling and handling, and tailings basin wind erosion.



# 6.2 Ore Concentrator Material Handling Proces s and Emission Description

In the ore concentration section of the plant, material handling equipment includes crushed ore
conveyors and conveyor drops and concentrate conv eyors and conveyor drops. Crushed ore entering
the concentrator is dry, and particulate controls will be needed at the entry point to the concentration

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# process. After this point, the ore concentrate is moist; so material handling in this area is not a
source of particulate emissions.

In order to simplify the BACT report, emission controls for material handling equipment throughout
the facility are reviewed in Section 11 of this report including conveyor drops, crushing and grinding
operations and screening of raw mate rials and intermediate products. Section 11 also contains a list
of sources covered by the material handling BACT analysis.



# 6.2.1 BACT Selection Summary for Crushed Ore Material Handling

BACT for material handling of dry crushed ore in the concentrator area of the facility is the use of a
fabric filter in conjunction with a ventilated en closure of the emission source. The proposed BACT
limit for particulate emissions is 0.0025 gr/dscf as measured by EPA Method 5.



# 6.2.2 BACT Selection Summary for Mate rial Handling in Ore Concentrator Plant
BACT for material handling in the concentrator area of the facility is no controls. Ore concentrate is
wet and material handling in the concentrator plant does not produce pa rticulate emissions.



# 6.3 Ore Concentrator Fug itive Dust Emissions

Sources of fugitive particulate em issions from ore concentrator operations at Minnesota Steel include
unpaved roads, storage piles, loading and unloadi ng operations, and materi al drops from mobile
equipment.

In order to simplify the BACT report, emissions controls for fugitive dust sources throughout the
facility are reviewed in Section 15 of the BACT report. Section 15 also contains a list of sources
covered by the fugitive source BACT analysis.



# 6.3.1 BACT Selection Summary for Ore Concentrator Fugitive Dust Emissions
Minnesota Steel will follow industry best practices for controlling fugitive dust emissions. Minnesota
Steel has prepared a fugitive dust control plan (Attachment O) which describes the measures
Minnesota Steel will take to control these emissions. Dust control measures listed in the plan are
consistent with dust control techniques used by other mining facilities in the area.

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# 7.0 Pelletizer

7.1 Pellet Plant Overview

Pelletization is the third major step in taconite ore processing. The concentrate slurry from
the concentrator will be dewatered by vacuum filters to produce a filter cake, which in turn is
mixed with an organic cellulose-based binder, limestone and soda ash, and converted to
unfired pellets (“green balls”) by tumbling moiste ned concentrate in a balling drum or balling
disc. The balling process is wet, and water in these streams prevents dust formation.
Therefore, the balling process is not a source of particulate emissions.

Next the pellets are ha rdened by a process called indurat ion. The green balls are dried and
heated in an oxidizing atmosphere at a temp erature of 1290° to 1400°C (2350° to 2550°F).
The application of heat duri ng indurating triggers the oxida tion of magnetite mineral (Fe 3 

# O 4 

# )
to the hematite form of iron mineral (Fe 2 

# O 3 

# ).



# 7.2 Indurating Furnace Process and Emission Description

The Minnesota Steel indurating furnace will be a “straight grate” system. The induration
process involves pellet pre-heating, drying, hard ening, oxidation and cooling. Each of these
steps is accomplished in different sections of the induration furnace as the grate system
moves pellets through the induration furnace.

Pellet drying and preheating are accomplished using waste heat from other sections of the
induration furnace. Air and induration furnace flue gas flows through the induration furnace
have been designed to recover as much heat as possible via recuperative heat exchange. The
front section of the traveling grate system cont ains green pellet drying and preheating zones,
which are heated with the hot gases generated in the pellet oxidation and pellet cooler grate
sections. Each of these sections is designe d to maximize heat re covery with process
constraints. Airflow across the pe llet cooling grates is directed to the updraft drying section.
Pellet cooling air is also utili zed as an air pre-heat system for the induration furnace burners
to minimize fuel consumption. Firing zone gases exiting the grate and are directed to the
downdraft drying section.

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# After preheating, pellets proceed to the primar y firing zone of the furnace for hardening and
oxidation. The primary firing zone includes the main burners in the indurating system; it is
designed to operate at 2350° to 2550°F. Thes e temperatures are needed to meet taconite
pellet product specifications. The application of heat during indurating triggers the oxidation
of magnetite mineral (Fe 3 

# O 4 

# ) to the hematite form of iron mineral (Fe 2 

# O 3 

# ). This reaction is

exothermic and contri butes significant heat back to the induration process.

Pellets exit the combustion zone and enter the pellet cooler where air is used for cooling. Hot
air from the cooling zone is then used to dry and preheat green pellets. Pellets exiting the
pellet cooler are screened and transferred to the oxide pellet stockpile. Finished pellet
properties include a certain degr ee of porosity that will allow the reducing gases of the DRI
process to metalize the pellet throughout.

Induration furnace exhaust is vented through a waste gas stack and a hood exhaust stack. The
induration furnace waste gas stack vents the fl ue gas from the primary combustion zone of
the grate. The waste gas stack exhaust contains most of the pollutant emissions from the

induration furnace. Based on vendor inform ation, approximately 30 percent of the
combustion gases exit through the hood exhaust. Th is is due to the diversion of some high

temperature gases asso ciated with the firing section fo r temperature control. The hood
exhaust stack vents the pellet cooler air after it serves to preheat and dry the pellets entering
the process. Emissions from the hood exhaust are primarily particulates.

Pellet handling and transfer operations consist of pellet screening and size classification,
stockpiling, transfer of product pellets to th e DRI plant oxide day bins, and transfer of

oversize and unders ize pellets and pellet fines to the re grind mill. Pellet plant additive
receiving and handling includes the railcar or tr uck unloading of materi als such as limestone,
soda ash, and binder, transfer to the additives storage silos, and the transfer of additives from
the silos to day bins. Typically, the unloading and transfer of additives will be pneumatic.

Air emission point sources associated with the material handling operations include the
binder, limestone, and soda ash bin vents during additive transfer, the grate feed and the
various pellet screening and transfer conveyo rs leading to the pellet storage bins or
stockpiling. Point source emissions for the ad ditive receiving and handling operations are the
result of venting additive silos and day bins duri ng pneumatic transfer. Da y bins vent back to
the storage silos whose vents are controlled with fabric filters.

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# Fugitive air emission sources within the pellet plant include wind erosion of concentrate
stockpiles, oxide product handling, and oxide pellet stockpiling. Inte rmittent concentrate
storage and handling operations consist of th e on-ground storage of concentrate during pellet
plant shutdown events, loading of stockpiled co ncentrate onto conveyers, and the transfer of
concentrate by conveyor. These operations occur only if downstream processing cannot

accommodate the concentr ate production rate.

Air pollutants emitted from the pelletizing operation include particulate matter, sulfur
dioxide, nitrogen oxides, carbon monoxide, volatile organic compounds, fluorides, sulfuric

acid mist and lead.

• Particulate matter emissions are primarily due to the attrition of particles (dust) from
the taconite pellets. This is caused by the abrasion of pellets rubbing against one
another and the process equipment as th e pellets move thr ough the indurating

furnace.

• The majority of su lfur dioxide (SO 2 

# ) emissions originate from the sulfur present in

the taconite ore. The emission invent ory and BACT review determined the SO 2 

# emission rate by mass balance. The mass ba lance is based on the sulfur content of
the ore concentrate, the concentrate production rate, the sulfur content of the finished
taconite pellets and the taconi te pellet production rate.

• Nitrogen oxides (NO
x 

# ) are formed by both the thermal oxidation of nitrogen in the
combustion air and the reduction and subsequent oxidation of fuel bound nitrogen.
Since the induration furnace will be natural gas fired, NO
x 

# emissions due to fuel
bound nitrogen are negligible. Thermal oxidati on is a function of the residence time,
free oxygen, and peak temperature, and produces the majority of NO
x 

# emissions from
the pellet plant. The oxidation reaction, wh ich begins to occur at a temperature of

2,600 ° F, takes place in the firing zone and during iron ore oxidation The pellet

plant furnace will operate at approximately 2,400 ° F to 2,450 ° F. The thermal

oxidation reaction is as follows:

N 2 

# + O 2 

# → 2NO (1)

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# Downstream of the flame, significant amounts of NO 2 

# can be formed when NO is mixed

with air. The reaction is as follows:

2NO + O 2 

# → 2NO 2 

# (2)

• Carbon monoxide and volatile organic compound emissions are formed by the
incomplete combustion of the natural gas. These emissions are a function of the
residence time at flame temperature, combustion zone design, burner characteristics,
and the turbulence of gases within the induration furnace combustion zone.

• Fluorides are present in the ore in trace quantities. Some fluorides are volatilized by
the heat of the induration furnace firing zo ne and are released into the waste gas.
Fluoride compounds are acidic in na ture and will be captured by SO 2 

# controls or wet
particulate scrubbing.

• Sulfuric acid mist formation is the result of oxidation of SO 2 

# to SO 3 

# . For this permit
application, an 0.4% SO 2 

# to SO 3 

# oxidation ratio has been assumed to conservatively
assess the ambient impacts of sulfate emissions. Once formed, SO 3 

# reacts with water

to form sulfuric acid mist. This reaction occurs at approximately 350oF. Sulfuric acid
mist will be captured by SO 2 

# controls or wet particulate scrubbing.



# 7.3 Pellet Plant Control Se lection Considerations

BACT selections are typically conducted for a single pollutant emitted from a source. The
pellet plant triggers the BACT evaluation for several pollutants from the same emission
points; PM, PM 10 

# , SO 2 

# , NO
x 

# , Pb, Fl, and sulfuric acid mist . Although mercury and acid gases
are not PSD pollutants and not subject to BACT, the pellet plant is the primary source of
mercury emissions, and it emits acid gases. The control selection for the pellet plant also
considers the feasibility and cost for controlli ng all of these pollutants. Although a control
technology may work for controlling one pollu tant, it may preclude control of another
pollutant, or at least reduce the effectiveness. A very complex pollution control scheme may
cause issues with reliability. A pollution control scheme that requires designing and
operating a pellet plant in a manner different than any other pellet plant in the world may
cause issues with pellet production or quality. In addition, potential reliability problems and
use of non-standard designs woul d potentially increase the risk of Minnesota Steel’s project
not moving forward.

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# Sections 7.4 – 7.11discuss the technical a nd economic feasibility of various control
technologies for each of the pollutants emitted from the pellet plant by pollutant. Per MPCA
request, Section 7.12 discusses the pellet plant control technology selection considering
multi-pollutant control within a single control device and the overall cost effectiveness for all
pollutants controlled by that device.



# 7.4 Pellet Plant Particulate Matter (PM and PM 10 

# ) Emissions

7.4.1 Sources of Induration Furn ace Particulate Matter Emissions
Particulate matter emissions are primarily due to the attrition of particles (dust) from the
taconite pellets. This is caused by the abra sion of pellets rubbing against one and other and
the process equipment as the pell ets move through the induration furnace. Part iculate matter

is emitted from both the waste gas and hood exhaust vents.

The waste gas also contains a small about of condensable partic ulate matter. The
condensable particulat es are primarily inorganic com pounds like sulfates , acid gases,
chlorides and fluorides which are generated as a byproduct of pellet induration. The waste
gas may also contain volatile organic compound s, which are products of incomplete natural
gas combustion.



# 7.4.2 Identification of Potential PM/PM 10 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step
in a top-down BACT analysis. Descriptions of the various control technologies are discussed

in Section 4.0 and Table 7-1. Potential control technologies for pellet plant particulate
emissions are the following:

• Fabric filter

• Wet scrubber

• Electrostatic precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (e.g. Cyclones)

• Inertial separators (drop out box)



# 7.4.3 Elimination of Tech nically Infeas ible PM/PM 10 

# Control Options

Table 7-1 summarizes the feasibility of PM/PM 10 

# emission control technologies for the pellet
plant.

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## Table 7-1 Evaluation of Most Effective PM/PM 10 

## Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream

Summary of Control Technology Feasibility

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

Fabric Filter (Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of

the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. No No

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. Yes Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal. Yes Yes

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. Yes Yes

Centrifugal Separation (e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down

the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes Yes



# Both the waste gas and hood exhaust contain too much moisture from pellet drying and
combustion products to effectively and reliably apply a baghouse. Condensation of moisture
and condensable particulates will form a cake on th e bags that would be difficult to remove.
In addition, it is possible to exceed filter bag temperature limits. Taconite pellets in the

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# straight grate furnace are extremely hot. The temperatur e of the hood exhaust and waste gas
will increase significantly duri ng process upsets or periods of low air flow. This will cause
bag failures because exhaust gas temperatures will exceed filter material temperature limits.
For these reasons baghouses are not employed in this service. Ranking of Remaining

PM/PM 10 

# Control Technologies by Control Effectiveness

The remaining control technologies and their cont rol efficiencies are pr esented in Table 7-2.

Table 7-2 Ranking of Remaining PM/PM 10 

## Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace

PM / PM 10 

## Control Technology Ranking

Rank Technology Typical % Efficiency Outlet Concentration

1 Wet Scrubber 95% - 99+% 0.012 gr/dscf*

1 Wet Electrostatic Precipitator 98% - 99+% 0.012 gr/dscf*

1 Dry Electrostatic Precipitator 98% - 99+% 0.012 gr/dscf*

2 Centrifugal Separation (e.g. Cyclones) 50% - 80% NA

3 Inertial Separators (Drop Out Box) < 50% NA

* Total particulate as measured by EPA Methods 201 or 201A (filterable) and Method 202 or EPA approved modified Method 202 procedures (condensable).



# Although the efficiency of cyclones and inerti al separators are low, Minnesota Steel will
employ a “multi-clone” separator in front of the selected pollution control equipment. The
multi-clone will capture larger particles. Th ese larger particles have been found to have a
high iron and low mercury content and therefore can be recycled back into the process to
recover the iron. Removal of the larger particles will also reduce the wear on downstream
duct work and control equipment and improv e the effectiveness of downstream pollution
control equipment.



# 7.4.4 Evaluation of Most E ffective Control Technologies

Table 7-3 and Table 7-4 summarize the effectiveness of PM/PM 10 

# control technologies for the
waste gas stream and hood exhaust respectively. The effectiveness evaluation for the waste

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# gas stream is based on control of the total am ount of particulate matter emitted in the waste
gas stream and does not include consideration of the particulat es removed by the multi-clone
nor the cost of the multi-clone units. The detailed control cost analyses are located in
Attachment A for the hood exhaust and Attachment B for the waste gas.

Table 7-3 Evaluation of Most Effective PM/PM 10 

## Control Technologies for the Pellet Plant Indurator Waste Gas Stream

Waste Gas Stack Control Technology Effectiveness Evaluation

Control Technology Outlet Concentration Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Wet Scrubber 0.012 gr/dscf* 

## 1116.2 $2,609,897 $1,246,444 $729

Dry ElectroStatic Precipitator (ESP) 0.012 gr/dscf* 

## 1116.2 $7,033,094 $1,450,822 $1,300

Wet Electrostatic Precipitator (WESP) 0.012 gr/dscf* 

## 1116.2 $17,343,207 $3,459,351 $3,099

* Total particulate as measured by EPA Methods 201 or 201A (filterable) and Method 202 or EPA approved modified Method 202 procedures (condensable).



## Table 7-4 Evaluation of Most Effective PM/PM 10 

## Control Technologies for the Pellet Plant Indurator Hood Exhaust Stream

Hood Exhaust Stack Control Technology Effectiveness Evaluation

Control Technology Outlet Concentration Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Wet Scrubber 0.012 gr/dscf* 

## 1058.8 $3,299,221 $1,648,867 $1,061

Dry ElectroStatic Precipitator (ESP) 0.012 gr/dscf* 

## 1058.8 $8,890,668 $1,894,712 $1,789

Wet Electrostatic Precipitator (WESP) 0.012 gr/dscf* 

## 1058.8 $21,923,877 $4,238,597 $4,003

* Total particulate as measured by EPA Methods 201 or 201A (filterable) and Method 202 or EPA approved modified Method 202 procedures (condensable).

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# The particulate control devices listed above are all highly effective and have the same

relative control effectiveness fo r total particulate matter emitte d (filterable + condensable).
This is due to the fact that some devices are more effective at controlling filterable particulate

matter vs. others which are more effective at controlling condensable pa rticulate matter (See
particulate matter control equipmen t descriptions in Section 4.2).



# 7.4.5 Pellet Plant In durating Furnace PM/PM 10 

# BACT Selection

The technical feasibility and removal effectiven ess of fabric filters is questionable when
applied to the pellet plant waste gas and hood ex haust stacks due to filt er blinding associated
with water condensation. A baghouse was deemed technically infeasib le for the hood exhaust
due to high moisture content. Currently, no taconite plants in the United States use fabric
filters for particulat e control on induration furnaces. Th e process designs for induration
furnaces include provisions for en ergy recovery by using hot process gas to pre-heat and dry
the incoming green taconite pellets. To maximize energy recovery, the furnaces are designed
so that gases leaving the indurat ion furnace are typically in the 100 °F to 150 °F range. This
leaves the stack gases at or very near to their dew points. Any free water present in the
induration furnace waste gas or water condensation on the filt er media would create a wet
and sticky filter cake that w ould not be easily removed from the filters. Application of a
baghouse to the waste gas stack would require a major re-design of the induration furnace
and would reduce the energy efficiency of the process.

Wet scrubbing and Wet ESP’s have the advantage of being able to remove other pollutants
(SO 2 

# , NO x, 

# acid gases, and some forms of merc ury) with minimal additional capital

investment. With the addition of an oxidizin g agent (e.g. ozone) to oxidize elemental
mercury, removal efficiency of mercury (particl e bound and oxidized forms) is expected to be
much higher for a scrubber when compared to a baghouse.

The capital cost for a wet ESP is estimate d to be approximately $17,000,000 and $22,000,000
more than a wet scrubber on the waste gas and hoo d exhaust, respectively. In addition, the
operating cost of a wet ESP is twice that of a wet scrubber. Wet scrubbing also has the
advantage of having a low control cost on a lb /ton basis. Water use in wet scrubbing of
particulates is limited to evaporative losses. Minnesota Steel will use mechanical separators
(e.g. rotoclones) upstream of the wet scrubber to capture and recycle the majority of iron
bearing particulate matter in the pelletizer exhaust. Process waste water from the emission

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# control scrubber will be treated in a zero disc harge system as described in Section 7.5.6.
Particulates captured by the emission control scrubb er will be disposed w ith other solids from
the waste water treatment system in appropria te manner. Therefore, a wet scrubber was
selected for control of particulate matter from the pellet plant.

The proposed BACT, for particul ate matter emissions from the induration furnace waste gas

and hood exhaust stacks, is a PM emission limit of 0.006 gr /dscf as measured by EPA

Method 5, and a PM 10 

# limit of 0.012 gr/dscf as measured by EPA Methods 201 (or 201A) and
202 or EPA approved modified Method 202 pr ocedures. Proposed BACT mass emission

limits for the hood exhaust are 23 lb/hr for PM and 47 lb/hr of PM 10 

# , and waste gas stack

limits of 17 lb/hr PM and 33 lb/hr of PM 10 

# . All mass emission limits are on a 24 hour average
basis. EPA Method 5 is the proposed test method for measurement of PM emissions
(filterable particulates). EPA Methods 201 (or 201A) and 202 or EPA approved modified
Method 202 procedures are the propos ed test methods for measuring PM 10 

# (filterable
particulates less than 10 micron s and condensable particulates). The mass emission limits are
based on operation with BACT controls and the facility running at full capacity. The
proposed BACT is consistent with the rece ntly promulgated Taconite MACT for new
sources; which represents the best level of cont rol for new sources within the Taconite source
category. The preferred me thod of meeting this goal is by wet scrubbing.

There were no BACT determinations listed in the RBLC for particulate matter or PM 10


# emissions from tac onite plants. BACT report Attachment L, Table L -1 is a summary RBLC
search finding for taconite plants

For periods of startup and shutdown, Minnesota St eel will put the pellet plant particulate emission
control equipment into service prior to commenc ing operation of process equipment, and keep
controls operating until the process is shut down and off line. No excess emissions will occur as
a result of control equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any
special permit conditions for startup and shutdown.



# 7.5 Pellet Plant Visible Emissions

Pellet Plant visible emissions are the result of particulate emissions from the hood exhaust and
waste gas stacks. The particulates are generate d by material handling equipment within the
pelletizer and by incomplete combustion in the pelletizer firing zone.

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# 7.5.1 Pellet Plant Visibl e Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of

visible emission is the same as the PM/PM 10 

# BACT.

On the pelletizer, PM/PM 10 

# emissions are controlled by we t scrubbers. Wet scrubber exhaust
contains droplets of entrained scrubber water and the exhaust gas is saturated with water vapor.
The water vapor condenses to form additional wa ter droplets when the exhaust plume comes in
contact with the atmosphere. Both of these c onditions contribute to formation of a wet plume
which is visible to the eye due solely to water dr oplets in the plume. Because of the water in the
exhaust stream it is impractical to measure opacity on these sources. Therefore, no visible
emission standard is recommended for the pellet plant hood exhaust and waste gas streams.

Proper operating practices and monitoring of the wet scrubber operating parameters will
minimize the amount of particulate emitted. Par ticulate emissions from the pelletizer will be well
controlled; so, the hood exhaust and waste gas streams will normally have negligible visible
emissions. Monitoring of scrubber operating para meters will enable Minnesota Steel to identify

conditions where visible emissions could occur, and to take corrective measures. Because

moisture in the exhaust from the wet scrubber can interfere with visible emission readings the
BACT limit is set at <10% opacity.



# 7.6 Pellet Plant Sulfur Dioxides (SO 2 

# ) Emissions

7.6.1 Sources of Induration Furnace SO 2 

# Emissions
The majority of sulfur dioxide (SO 2 

# ) emissions originate from the sulfur present in the

taconite ore. There is also a small amount of SO 2 

# emitted from natural gas combustion. The
emission inventory and BACT review determined the SO 2 

# emission rate by mass balance.

The mass balance is based on the sulfur content of the ore concentrate, the concentrate
production rate, the sulfur content of the finish ed taconite pellets and the taconite pellet
production rate.

Most of the SO 2 

# emissions emanate from the waste gas stack as the regions of the induration
furnace where sufficient temper ature exist to liberate sulfur compounds from the taconite.

The hood exhaust contains a small amount of SO 2 

# due to leakage between induration furnace
zones and the diversion of up to 30% of waste gas for temperature control.

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# 7.6.2 Identification of Potential SO 2 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step
in a top-down BACT analysis. Descriptions of the various SO 2 

# control technologies are

discussed in Section 4.0 and Table 7-5. Pote ntial control technologies for pellet plant
particulate emissions are the following:

• Absorber (Wet Scrubber)

• Wet ESP

• Spray dryer absorption

• Dry sorbent injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design and Operating Practices



# 7.6.3 Elimination of Te chnically Infeasible SO 2 

# Control Options

All of the listed technologies are technically feasible in th is application for waste gas

exhaust.

SO 2 

# concentrations in the hood exhaust however are calculated to be only 5 - 10 ppm using

the SO 2 

# mass emission rate from the Air Emission Inventory (Appendix 3B .), and stack flow

rate from form GI-04. Removal of additional SO 2 

# at these concentrations is technically and
economically infeasible. SO 2 

# control technologies use chem ical reactions to remove SO 2


# . When one of the reactants in a chemical reaction is at a very low concentration it takes an
extremely high amount of the other reactant to be present for the reaction to occur. Chemical
reaction based control technologies therefore reach a minimum concentration that can be
effectively removed. In addition, at these low concentrations, even if some SO 2 

# removal
were technically feasible, the amount removed would be so small that removal would also be
economically infeasible.

Application of Good Design and Operating Prac tices is the only feas ible emission control

method for SO 2 

# on the hood exhaust.

The technical feasibility in Ta ble 7-5 ignores the technical in feasibility of the particulate
control technology that must also be employed. The spray dryer absorption and dry sorbent
injection are typically employed with a baghous e for removal of particulates. A baghouse

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# was deemed infeasible for particulate control on the pellet plant in Section 7.4. Spray dryer
absorption and dry sorbent injection could be employed in conjunction with a wet scrubber;
however, there are no advantages to this compared to lime addition to the wet scrubber.
Spray dryer absorption and dry sorbent injec tion were carried thr ough the BACT selection
process to evaluate their cost effectiveness.

Table 7-5 Technical Feasibility of SO 2 

## Control Technologies for Taconite Pellet Indurating Furnace

SO 2 

## Emission Control Technology Feasibility Analysis

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

Absorber (Wet Scrubber) A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with SO 2 

## and removes it. Yes No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with SO 2 

## and removes it. A fabric filter is used to collect the spent sorbent. Yes No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for SO 2 

## removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For SO 2 

## removal, caustic is added to the water spray system, allowing the spray system to function as an SO 2 

## absorber. Yes No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. SO 2 

## reacts with sorbent and the solid

particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology Yes No

Clean Fuel/ Good Combustion Practices (Base Case) Use natural gas as induration fuel source to minimize SO 2 

## emissions. Yes Yes

Good Design and Operating Practices Design, operate and maintain the induration furnace in a manner which minimizes waste gas

bypasses to the hood exhaust within product quality and production constraints Yes Yes

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# 7.6.4 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness
The remaining control technologies and their cont rol efficiencies are pr esented in Table 7-6.

Table 7-6 Ranking of Remaining SO 2 

## Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace

SO 2 

## Control Technology Ranking

Rank Technology Waste Gas Control Efficiency Hood Exhaust Control Efficiency

1 Absorber (Wet Scrubber) 90% NA

3 Spray Dryer Absorption 85% NA

2 Wet Electrostatic Precipitator 80% NA

4 Dry Sorbent Injection 50% NA

5 Clean Fuel/ Good Combustion Practices (Base Case) Inherent Inherent

6 Good Design Methods and Operating Practices Inherent Inherent



# Wet scrubber control efficiency was provi ded with the cost estimate by the vendor
(Environmental Elements). A control efficiency of 85% was used for the spray dryer
absorber. The current design basis for SO 2 

# emissions from the pelletizer is 33% lower than
the amount used in vendor requests. The vendor ’s proposed dry scrubber efficiency (90%)
was the highest that devices could achieve for th e specifications in the bid request. An 85%
control efficiency is more representative of the expected control efficiency at the current
design concentration of SO 2 

# in the waste gas. Wet ElectroStatic Precipitator (Wet ESP)
control efficiency is based on Northshore Mi ning Company’s experience with Wet ESP’s.
Northshore is the only taconite plant that employs Wet ESP controls.



# 7.6.5 Evaluation of Most Effective SO 2 

# Control Technologies

The BACT technology effectiveness summary is presented in two tables; one for the waste
gas stack (Table 7-7) and one for the hood exha ust (Table 7-8). The detailed control cost
analyses are located in Attachment A for th e hood exhaust and Attach ment B for the waste

gas.

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## Table 7-7 Evaluation of Most Effective SO 2 

## Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream

Waste Gas Control Technology Effectiveness Evaluation

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Absorber (Wet

Scrubber) 90.0% 

## 342.3 $11,956,125 $2,108,175 $6,158

Baghouse w/Dry Scrubber 85.0% 

## 323.3 $26,007,235 $4,419,559 $13,670

Wet ElectroStatic Precipitator (Wet ESP) 80.0% 

## 304.3 $17,343,207 $3,459,351 $11,369

Clean Fuel/ Good Combustion Practices (Base Case) Base Case NA NA NA NA

Good Design Methods and

Operating Practices Base Case NA NA NA NA



## Table 7-8 Evaluation of Most Effective SO 2 

## Control Technologies for the Pellet Plant Indurating Hood Exhaust Stream

Hood Exhaust Control Technology Effectiveness Evaluation

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Absorber (Wet

Scrubber) 90.0% 

## 120.3 $15,113,965 $2,703,203 $22,475

Baghouse w/Dry Scrubber 85.0% 

## 113.6 $32,876,241 $5,637,085 $49,625

Wet ElectroStatic Precipitator (Wet ESP) 80.0% 

## 106.9 $21,923,877 $4,238,597 $39,646

Clean Fuel/ Good Combustion Practices (Base Case) Base Case NA NA NA NA

Good Design Methods and Operating Practices Base Case NA NA NA NA

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# 7.6.6 Pellet Plant Indurating Furnace SO 2 

# BACT Selection

As discussed earlier the feasibility of associated particul ate control technologies was ignored

in the assessment of SO 2 

# control technologies. Regardless of the particulate control
equipment selection, a wet scrubber with lime injection is the most cost effective control
option for SO 2 

# . A wet scrubber was also selected for control of particulates.

The proposed SO 2 

# BACT for the Hood Exhaust is Clean Fuel/Good Combustion Practices
(Base Case) and Good Design Methods and Opera ting Practices. This is based on combustion
of natural gas in the fired section of the pelletizer which minimized the amount of SO 2 

# which
migrates from the waste gas to the hood exhaust via wind box leakage. The proposed SO 2


# mass limit for the Hood Exhaust is 36 lb/hr SO 2 

# on a 3-hour average basis and 7.8 ppm.

The proposed SO 2 

# BACT for the Waste Gas Stack is 3.3 ppm SO 2 

# at 15% O 2 

# and 10 lb/hr

SO 2 

# on a 3 hour average basis. Both wet sc rubber and Wet ESP cont rols will generate
wastewater. The facility will have a wastewat er treatment system to handle the wastewater
steams in an environmentally acceptable manne r. Minnesota Steel Indus tries has elected to
design the facility with zero waste water discha rge for waste water generated by processing
equipment. The treatment system will include lime softening, reverse osmosis and
evaporation/crystallization of reverse osmosis reject water. Solids from the treatment system

will be tested to determine wh ether they should be managed as solid or hazardous waste and
managed accordingly. Contaminants captured in the wet scrubber will be removed in the
process water treatment system as a solid an d deposed of in and appropriate manner along
with the other compounds removed by the soften ing and reverse osmosis treatment systems.
Clean water from the treatment system will be recycled. The selection of air pollution
control alternatives that generate a wastewater streams have been considered and
incorporated into the wastewater treatment plant design and discharge water permitting.

The SO 2 

# BACT also includes good design methods a nd operating practices for minimizing
waste gas migration into the hood exhaust system. No other controls are proposed for the

Hood Exhaust. This determination is based on the low levels of SO 2 

# present in the Hood

Exhaust.

There were no BACT determinati ons listed in the RBLC for SO 2 

# emissions from taconite
plants. BACT report Attachment L, Table L -1 is a summary RBLC search finding for
taconite plants

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# For periods of startup and shutdown, Minnesota Steel will put the pellet plant SO 2 

# emission control
equipment into service prior to commencing operation of process equipment, and keep controls operating
until the process is shut down and/or off line. No excess emissions will occur as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 7.7 Pellet Plant Nitrogen Oxides (NO x 

# ) Emissions

7.7.1 Sources of Induration Furnace NO x 

# Emissions
Nitrogen oxides (NO
x 

# ) are formed by both the thermal oxidation of nitrogen in the combustion air
and the reduction and subsequent oxidation of fuel bound nitrogen. Since the indurating furnace will
be natural gas fired, NO
x 

# emissions due to fuel bound nitrogen are negligible. Thermal oxidation is a
function of the residence time, free oxygen, and peak temperature. The majority of NO
x 

# emissions
from a pellet plant are from thermal NOx formation.

The majority of combustion zone gases, including NO
x 

# , are emitted through the waste gas stack. The
hood exhaust contains up to thirty percent of the NO
x 

# due to leakage between induration furnace
zones and the diversion of some waste gas for temperature control.



# 7.7.2 Identification of Potential NO x 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various NO
x 

# control technologies are discussed in Section
4.0 and Table 7-9. Potential control technologi es for pellet plant particulate emissions are the
following:

• Low temperature oxidation

• Selective catalytic reduction

• Selective non-catalytic reduction

• External Flue Gas Recirculation

• Low-NOx Burners and Induced Fl ue Gas Recirculation Burners

• Oxyfuel burners

• Low excess air (LEA)

• Other combustion controls

• Good design methods and operating practices

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# 7.7.3 Elimination of Te chnically Infeasible NO x 

# Control Options

Table 7-9 summarizes the technical feasibility of NO
x 

# control technologies fo r the waste gas stream
and the hood exhaust. Details regarding the feas ibility of each technology are discussed in the
following sections.

Table 7-9 Technical Feasibility of NO x 

## Control Technologies for Taconite Pellet Indurating Furnace

NO x 

## Emission Control Technology Feasibility Analysis

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

1. Low Temperature Oxidation Low Temperature Oxidation is a process where NO x 

## is oxidized to form water soluble nitrate compounds which can easily be removed by absorption (wet scrubbing). Oxidation occurs at relatively low temperatures (100oF – 200oF) so it

can be effectively used as an add-on control system where the stream to be treated is not hot enough for catalytic controls. Ozone is typically used as the oxidizing agent. No No

2. Selective Catalytic Reduction Selective catalytic reduction (SCR) is a postcombustion NO x 

## control technology in which ammonia (NH 3 

## ) is injected into the flue gas stream in the presence of a catalyst. SCR requires a temperature range of 400 ° F – 800 ° F. No No

3. Selective Non-Catalytic Reduction The Selective non-catalytic reduction (SNCR) process injects urea or ammonia-based chemicals into the flue gas stream to convert NO to N 2 

## and water. The optimum operating temperature for SNCR is 1,600 ° F to 2,000 ° F. No No

4. Non-Selective Catalytic Reduction Non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NO x 

## and CO react in the presence of NSCR catalyst to form nitrogen (N 2 

## ) and carbon dioxide (CO 2 

## ). It is typically employed in clean gas services such as natural gas fired turbines. No No

5. External Flue Gas Recirculation External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame

temperatures. In an external flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air and this mixture is introduced

into the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x 

## . No No

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## NO x 

## Emission Control Technology Feasibility Analysis

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

6. Low-NOx Burners and Induced Flue Gas Recirculation Burners Low-NO x 

## burner (LNB) technology utilizes advanced burner design to reduce NO x 

## formation through the restriction of oxygen, flame temperature, and/or residence time. Induced flue gas recirculation burners are designed to draw flue gas into the burner to dilute the fuel. This reduces flame temperature and NO x 

## formation. Yes No

7. Low Excess Air (LEA) Low Excess is a combustion control method which is used to reduce the amount of oxygen in the combustion zone of a furnace or boiler. This

limits the amount of oxygen available for NO x 

## formation. No No

8. Other Combustion Controls These combustion control methods are typically employed on existing sources. They inexpensive, but have limited control efficiencies. Combustion controls include Overfire Air (OFA), Bu rners Out of Service (BOOS) and Load Reduction and Reduced Combustion Air Temperature. No No

9. Good Design Methods and Operating Practices Design, operate and maintain the induration furnace in a manner which minimizes waste gas

bypasses to the hood exhaust within product quality and production constraints Yes Yes



# NOx emissions in the hood exhaust are due to the migration of waste gas into the hood exhaust via
wind box leakage and diversion of waste gas to th e hood exhaust for temperat ure control. Since no
combustion is taking place in the hood exhaust stream, combustion cont rols are technically

infeasible.

7.7.3.1 Low Temperature Oxidation (LTO)

LoTOx is an innovative NO
x 

# control technology licensed by BO C Gases which uses low temperature
oxidataion (LTO) to control NOx. Lo TOx is not considered technically feasible at this time due to
the limited number of applications of LoTOx technology. LoTOx has not been applied to a taconite

induration furnace or a source with similar size and exhaust gas ch aracteristics. Application of
LoTOx to the pelletizer waste ga s exhaust will present technical challenges and unknowns that were
not encountered in the existing LoTOx applications . Currently, LoTOx has only been applied in
small to medium sized applications. Existng LoTOx applications include:

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# • Two gas fired boilers in California (1997-8 and 2000),

• Stainless Steel Pickling Process near Pittsburgh (Operating since late 2000),

• 25 MW Coal Fired Power Plant at Medical College of Ohio (Installed in 2001, demonstrated

NO
x 

# removal performance for 6 months (up to June 2002), and a

• Lead Recovery Furnace (Operational since 2002).

In addition, there are six more installations in various stages of engineering, fabrication and

construction, four of which are at installations at petroleum re fineries. The LoTOx technology
applications in the petroleum refining industry are for Fluid Catalytic Cracki ng (FCC) unit catalyst
regenerators. Primary differences between an FCC catalyst regenerator off gas and the taconite
pelletizer waste gas are:

• Higher flow rates: Flow rates in the pelletizer waste ga s stack are 50% higher (470,000 acfm
waste gas vs. 220,000 acfm for a typical FCC).

• Higher NOx loading: The pelletizer has much higher combustion temperat ures (2,400°F vs
1,300°F) and higher oxygen conc entrations (15% vs. 2%) than an FCC regenerator.

• Presence of reactive compounds: The pelletizer waste gas contains raw taconite ore which

could consume ozone. FCC catalyst fines in the rege nerator exhaust are inert.

• Higher PM loading in the pelletizer: The pelletizer will have a single stage rotoclone prior to
the particulate scrubber. FCC catalyst regenerator 2-stage cyclone systems are designed to
minimize catalyst loss, and have a high efficiency fo r particles > 10u. The pelletizer scrubber

water will contain lime for SO 2 

# emissions control. A sodium hydroxide solution (caustic) is
typically used to control SO 2 

# emissions in FCC catalyst regenerator scrubbers.

• Different scrubber designs: Minnesota Steel will use a venturi rod scrubber vs a standard
venturi scrubber at the FCC unit. So, mixing patterns in the scrubber will be different from
the FCC application.

BOC Gases, the licensor of LoTOx, recommends that engineering tests be performed on the
pelletizer exhaust before attempting to design a nd install LoTOx controls. All the factors noted
above have the potential to affect NOx control efficiency and reag ent consumption. Because LoTOx
has never been used on a taconite pelletizer, testing is needed to collect the data needed to determine
if a LoTOx system can be successfully designed for the taconite pelletizer waste gas application.

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# 7.7.3.2 Selective Catalytic Reduction (SCR)

The MPCA has requested consideratio n of the application of SCR for NO
x 

# control in conjunction
with dry scrubbing for SO 2 

# control on the Minnesota Steel pelletiz er. This combination of controls
affords use of dry particulate control technologi es and of activated ca rbon to control mercury

emissions. Minnesota Steel worked with a potential pellet plant vendor to evaluate the feasibility of
using SCR. Based on information obtained from the vendor a scenario was developed that employs
the use of SCR for evaluation in this BACT selection process.

Use of dry controls would imply use of a dry ESP or baghouse for particulate and SO 2 

# control. Dry
controls keep the dust collected in a dry state, which allows recycling 4 

# of SO 2 

# and mercury removal
reagents and eliminates a wastewater stream. Bagh ouses for dry controls have not been employed on

taconite furnaces due to concer ns that moisture from pellet drying and fuel combustion would
condense the baghouse and were deemed tec hnically infeasible in Section 7.4.

In evaluating the technical feasibility of SCR, Mi nnesota Steel has identified two potential locations
in the pelletizing furnace wh ere SCR could potentially be installed to control NO
x 

# emissions in the

waste gas stream:

1. In the recuperative heat recovery system duct between the pellet firing zone and the pellet
drying/ preheating zones, and

2. Downstream of partic ulate emission controls.

Waste gases exiting the bottom of the grate in the combustion zone of the induration furnace are
below the temperatures needed to operate an SCR re actor. In conventional straight grate pelletizing
furnace designs, gases exiting the bottom of the comb ustion zone grate system are at 258oF– 320oF.
The normal SCR operating temperature window is 600oF – 800oF a nd the minimum te mperature that
the newer low temperatur e catalysts can operate at is 400oF – 600oF.

At Minnesota Steel’s request, one pelletizing furnace vendor developed a conceptual design for
application of SCR downstream of the combustion zone . This design is potentially feasible, but only
treats a portion of the waste gas exhaust. Applica tion of SCR to the pellet plant would require reheating the waste gas exhaust back to the temperature necessary for SCR operation. Re-heating the

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# waste gas exhaust generates additional NO
x 

# formation from natural gas combustion. The conceptual
design balances treatment of NO
x 

# emissions with the additional amount of fuel required. This is
accomplished by applying SCR to only portions of the waste gas exhaust from wind boxes that are at
higher temperatures. In addition, the flows from the firing and post-firing wind box sections of the
pelletizer would be rearranged in a manner that would recover part of this energy and thereby
minimizes the amount of additional fuel that would be needed by recovering part of this energy.
However, a duct burner is still required to bring the waste gas temperature up to SCR operating

conditions. The NO
x 

# generated by the duct burner would also have to be treated by the SCR unit.
The waste gas exhaust from the cooler wind boxes, which would normally be routed with the waste
gas exhaust, is not treated for NO
x 

# . This reduces the overall efficiency of SCR compared to other
technologies that are able to treat the entir e waste gas exhaust stream. The overall NO
x 

# emissions
from the pellet plant (hood exhaust plus waste gas exhaust) for the conceptual SCR design is 120 to
300 lbs/hr depending upon the control efficiency achieved by the SCR unit.

Regardless of whether the temp erature requirements for SCR can be met, there are additional

technical unknowns associated with its application to a taconite pellet plant. SCR requires the use of
a catalyst. There is the potential for catalyst deactivation by catalyst poisons in the taconite pellet
dust and corrosion/plugging problems caused by ammonium sulfate salt s. Ammonia slip (un-reacted
ammonia) would react with sulfur dioxide to form ammonium sulfate salts. These compounds are
gummy and corrosive. If present in sufficient quantities, sulfur oxides and excess ammonia from the
SCR system may react to form enough ammonium sulfate compounds to have an adverse affect on
the pellet drying and preheat sections of the i ndurating furnace. Therefore, use of SCR In the
recuperative heat recovery syst em duct between the pellet firi ng zone and the pellet drying/
preheating zone is not technically feasible.

The second potential alternative for application of SCR is to install it downstream of the other
pollution control equipment for the pellet plant. To do this, the waste gas stream would require reheating the gas to SCR catalyst operating temperat ures. Re-heating the waste gas pollution control

exhaust for SCR is not feasible because it would require an exce ssive amount of energy. Based on
the temperature of the waste gas stream after other pollution control equipment (wet scrubbing),
reheating the waste gas for SCR would consume 466 million cubic feet of natural gas per year. To

4 

## Dust collected in the baghouse contai ns un-reacted reagents. Some of the ma terial collected is mixed with fresh reagent and reused in the scrubber. This is done to minimize reagent consumption.

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# put this into perspective, reheating waste gas fo r the Minnesota Steel pelletizer would require 63
MMBtu per hour assuming a 70% recuperative heat re covery system is used. An energy efficient
pellet plant requires 265,000 Btu per short ton of pellet s. The energy needed for waste gas reheat is
equivalent to the energy needed to produce 237 short tons per hour of pellets, or 38% of the design
capacity of Minnesota Steel’s pellet plant.

Another potential source of energy for re-heating the waste gas would be to recover the heat from a
hot waste gas stream elsewhere in the plant. The DRI reformer heater exhaust already includes a heat
recovery system, and is not available for this serv ice. The EAF exhaust is too dust laden before the
baghouse system and too cold after the baghouse. The tunnel furnace exhaust is hot enough, but will
be located about 2,200 ft from the pellet plant. This is too far from the pellet plant to feasibly run a
large diameter refractory lined duct. In addition, the tunnel furnace and the EAFs have cyclic
operating patterns; so, it would not be feasible to provide the steady fl ow of heat needed to operate
an SCR system. Therefore, installation of SCR downstream of particulate emission controls is not
feasible due to the excessive energy demands of this design.

Although cost considerations are not a technical feasibility issue, the use of SCR on the pelletizer
would create a significant business risk. Installation of SCR includes a signifi cant capital investment

which would be lost if SCR did not function as in tended. An SCR approach would require the redesign of the pelletizer wind box sy stem and installation of a full scale wind box duct system with
SCR controls to capture, reheat and treat pelletizer waste gas. The incremental investment for wet

NO
x 

# controls is much less. The only additional equipment needed to test wet NO
x 

# controls on a

SO 2 

# /PM wet scrubber, is an ozone injection system consisting of a temporar y ozone generator and a
temporary oxygen supply (delivered). If LoTOx te sting is unsuccessful, the LoTOx equipment can
be removed at minimal cost. Because of pot ential corrosion problems, additional energy
requirements for gas re heating, and lower NO
x 

# control efficiencies, Minnesota Steel believes that

SCR is at best an inferior alternative to LoTOx controls.

7.7.3.3 Selective Non-Catalytic Reduction (SNCR)

SNCR is not a feasible option for the pellet plant as there is no location in the flue gas circuit where
the temperatures are suitable for the installation of injection nozzles. SNCR injection points must be

at 1,600oF - 2,000oF to achieve NO
x 

# control. The combustion zone temperature of the indurating

furnace is 2,400oF. Gases leavi ng the combustion zone grates are only 258oF– 320oF, well below the
SNCR temperature window. In addition, ammonia sl ip would react with sulfur dioxide to form

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# ammonium sulfate salts. These compounds are gumm y and corrosive. If present, they would have
an adverse affect on the pellet drying and pr eheat sections of the indurating furnace.

A potential alternative for application of SNCR is to install it downstream of the other pollution
control equipment for the pellet plant. To do th is, the waste gas stream would require re-heating up
to SNCR catalyst operating temperatures. Reheating the waste gas for SNCR is not feasible because
it would require an inordinate amount of energy. SNCR operating temperatures are roughly three
times higher than SCR. So, reheating the wa ste gas for SNCR would co nsume 1,650 million cubic
feet of natural gas per year or almost 90% of the de sign capacity of Minnesota Steel’s pellet plant.

7.7.3.4 Flue Gas Recirculation (FGR)

In the induration process, it would be unacceptable to reroute the flue gas to the combustion zone
since this would lower the optimal temperature range needed for pellet indurat ion. Pellets must be
held at an optimum temperature (2400 - 2450 ° F), in the presence of excess oxygen, for a sufficient
time to allow oxidation to reach the pellet center and allow realignment of the iron oxide molecules
in the microstructure of the pellet to form a st rong pellet that meets product specifications.

Another factor affecting the feasibili ty of FGR is the high levels of oxy gen in the pelletizer furnace.
Normally flue gas is inert and has low levels of oxyge n (2% - 3%). At these levels flue injected into
the combustion zone of a burner effectively dilute s the combustion reactants (fuel and air) so the
flame temperature can be lowered fo r NOx control. Pelletizer flue gas has approximately 12% - 15%
oxygen. At these levels, injection of flue gas in to the burner combustion zone would be more like
adding combustion air into the flame instead of an inert gas. Therefore, flame temperatures can not
be effectively controlled using pe lletizer flue gas in FGR.

7.7.3.5 Low NOx Burners (LNB)
The temperature and oxygen requi rements of indurati on prevent the successf ul application of
standard LNB technology to the pellet plant. LNB techno logy is based on lowering NO
x 

# emissions by
reducing flame temperature. Thermal NO
x 

# formation starts at 2,600oF a nd begins to increase rapidly
at temperatures above 3,000oF. Pe llets must be heated to, and main tained at, a temperature of 2400 -

2450 ° F, to produce a completely oxidized, high strengt h and abrasion resistant pellet. This puts
induration temperatures near the point where thermal NO
x 

# formation begins. Thus, flame
temperature reductions for NO
x 

# control via LNB technology are li mited by temperat ure requirements

of taconite induration.

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# 7.7.3.6 Low Excess Air (LEA)

Low excess air operation is not feasible in the indurating furnace because the pelletizer must be
operated with high oxygen leve ls in order to achieve complete pell et oxidation. These oxygen levels
are much higher than LEA controls would permit.

7.7.3.7 Good Design Methods and Operating Practices
It is feasible to design, operate and maintain the indurating furnace in a manner which minimizes
waste gas bypasses to the hood exhaust within product quality and production constraints.



# 7.7.4 Ranking of Remaining NO x 

# Control Technologies by Control Effectiveness
The third of the five steps in the top-down BA CT analysis is to rank the remaining control
technologies by control effectiveness. The re maining control technologies and their control
efficiencies are presented in Table 7-10.

Table 7-10 Remaining NOx Control Technologies and Control Effectiveness for the Taconite Pellet Indurating Furnace

NOx Control Technology Ranking

Rank Technology Waste Gas Control Efficiency Hood Exhaust Control Efficiency

1 Good Design Methods and Operating Practices NA Inherent Controls NA Inherent Controls



# 7.7.5 Evaluation of Most Effective NO x 

# Control Technologies

Each of the most effective contro l technologies from Table 7-10 ar e evaluated in Table 7-11 for the

Waste Gas Stream and Table 7-12 for the Hood Exhaust.

Table 7-11 Evaluation of Most Effective NO x 

## Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream

Waste Gas NOx Control Technology Effectiveness Evaluation

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Good Design Methods and Operating Practices Base Case NA NA NA NA

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## Table 7-12 Evaluation of Most Effective NO x 

## Control Technologies for the Pellet Plant Indurator Hood Exhaust Stream

Hood Exhaust NOx Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Design Methods and Operating Practices NA Inherent Controls NA Inherent Controls NA NA



# 7.7.6 Pellet Plant Indurating Furnace NO x 

# BACT Selection

The proposed BACT emission controls for NO
x 

# emitted from the pellet plant hood exhaust and waste
gas steams are good design methods and operating prac tices. None of the add-on control technologies
evaluated are technically feasible at this time.

The proposed BACT NO
x 

# mass emission limit for the H ood Exhaust is 165 lb/hr on a 24-hour
average basis and 45 ppm. The proposed BACT NO
x 

# mass emission limit for the Wate Gas Exhaust

is 464 lb/hr NO
x 

# on a 24- hour average basis.

RBLC listings for NOx controls from taconite processing are listed in Appendix L, Table L-1. Only

one NO
x 

# determination is listed. Is pat Inland Mining installed low NO
x 

# burners as BACT. Only a lb

NO
x 

# per hour limit is listed; no perfor mance limit is specified. Per the facility, no performance test
data were collected prior to installation of the low NO
x 

# burners and insufficient information exists to

determine the effectiveness of low NO
x 

# burners in this application.

For periods of startup and shutdown, Minnesota Steel will follow good ope rating practices while
commencing operation of process equipment. However, NO
x 

# emissions during startu p will be higher
than normal due to increased fuel consumption. Additional fuel firing is needed to bring the
pelletizer furnace temperature up to operating conditions. Once st eady state conditio ns are reached,
fuel consumption will return to normal. See Attachment M, Tabl e 1, for a summary of proposed
startup/shutdown emission limits



# 7.7.7 NOx Emission Control Technology Testing

Despite the fact that LoTOx is unproven technology, Minnesota Steel is willing to conduct a trial of
LoTOx on the pellet plant waste gas stream. The purpose of the trial is to determine if LoTOx is
technically and economically feasib le on the waste gas exhaust. If feasible, the data from the trial

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# will also provide the information necessary to accura tely estimate the cost an d design for a full scale
installation. This test is necessary because no application of the tec hnology at a taconite pellet plant
has ever been tested or installed nor has the technology been applied at flowrates as high as the waste
gas exhaust. The estimated cost based on inform ation from non-taconite in stallations for LoTOx on
the waste gas stream is $18.7 million with an annual operating cost of $7.3 million which yields an
NOx control cost of $4,751 per ton of NO
x 

# removed. However, engineering test data from the trial is
needed to accurately assess the true cost of LoTOx controls. The control cost analysis of LoTOx for
the waste gas sream is located in Attachment A of the BACT report.

If the trial is not successful, Mi nnesota Steel will re-evaluate the a pplication of SCR and investigate
other emerging control te chnologies which may become commerci ally available at that time.
Although SCR would have lower control effectiveness for NO
x 

# than LoTOx, it still would reduce

NO
x 

# emissions. Due to the unanswered questions regarding the application of SCR on a pellet plant
additional, testing of SCR would al so be necessary. At that time the economic feasibility of SCR

would also be evaluated.

Based on the low levels of NO
x 

# present in the hood exhaust, LoTOx is economically infeasible. At
$18,183 per ton of NOx removed, the NO
x 

# control cost for LoTOx on the hood exhaust is well above
what is considered to be economically feasible. Therefore, a LoTOx trial on the hood exhaust stream
is not justified. A control cost analysis of LoTOx for the hood exhaust stream is located in
Attachment B of the BACT report.

The proposed LoTOx trial is based on the Lo TOx vendor’s recommendation to perform an
optimization study using their LoTO x Mobile Demonstration Trailer. The demo trailer has been
specifically designed to characterize flue gas streams with injection of ozone for NO
x 

# treatment to
allow proper sizing of equipment to and to evaluate the site specific performance of LoTOx. This

demo trailer is useful in ch aracterizing highly variable NO
x 

# streams, and the effect of other chemical
compounds (i.e. taconite dust) in the gas stream on the performanc e of LoTOx. The demonstration
would require a slip stream of flue gas to be treated in the LoTOx trailer.

The LoTOx Trailer Testing program at the site has three main purposes . (1) To provide accurate data
for upgrading the residence time - temperature oxidizer model so th at the model can be used to
determine the cost effectiveness and design for the components of the full scale LoTOx system. (2)
To characterize key process variables and the response of the control system. (3) To provide
sufficient operating experience and insight into the LoTOx system behavior to the waste gas exhaust.

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# The test will also be used to evaluate operational issues to be considered in design and operation of
the system. These are all key factors in determining the technical feasibility of the system.

The test will also be used to evaluate the economic feasibility of LoTOx. The economic feasibility is
driven by the residence time necessary for the ozone to react with the NO
x 

# and the amount of ozone
that must be injected. The amount of ozone that must be injected is a key component of both the
capital and operating cost of the technology.

The technical and economic feasibil ity of LoTOx will be evaluated based on the following criteria:

• Ability to provide at least a 70% reducti on in NOx emissions ov er a 24-hour period of
operation at a range of NOx em ission rates corresponding to those occurring during normal
operation of the pellet plant.

• Ability to achieve a cost effectiveness of less than $5,000 per ton of NOx removed.

• Blowdown from the wet scrubber are within treatment parameters of the reverse osmosis

system.

• Particulate and SO 2 

# control of the scrubber are un affected by ozone injection.

• No excessive oxygen or energy usage or significant pressure drop required.

• No excessive requirements for additional energy infrastructure.

• No significant associated environmental impacts.

• No major operational difficulties.

• No significant safety hazards.

Minnesota Steel proposes the follow ing schedule for conducting the Lo TOx trial test and installation

if deemed feasible:

• Submit LoTOx trial test plan to the MPCA 90 days before the date of the test.

• LoTOx trial trailer unit installation and testing will be completed 10 months of initial startup of the pellet plant.

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# • Submit LoTOx trial feasibility report to the MPCA 75 days after completion of testing.

• The MPCA will have 30 days to review a nd object to the conclusions of the report.

• If LoTOx is deemed economically and technicall y feasible, installation and startup of full
scale LoTOx system will be completed with in 25 months of completion of testing.

•

• If LoTOx is installed, the estimated NO
x 

# emission limit for the Wa ste Gas Exhaust is 25 ppm

NO
x 

# at 15% O 2 

# and 46 lb/hr NO
x 

# on a 24-hour average basis.

• If LoTOx is not feasible Minnesota Steel will submit a complete BACT analysis of NOx
controls for the pellet plant within 3 months of completion of the trial testing.



# 7.8 Pellet Plant Carbon Monoxide (CO) Emissions

7.8.1 Sources of Induratio n Furnace CO Emissions

Carbon monoxide and volatile organic compound emissions are formed by the incomplete
combustion of the natural gas in the combustion zone of the indurating furnace. These emissions are
a function of the residence time at flame temperature, combustion zone, burner characteristics, design
and the turbulence of gases within the indurating furnace combustion zone.

The majority of combustion zone gases, where CO is generated, are emit ted through the Waste Gas
stack. The Hood Exhaust contains up to thirty pe rcent of CO due to leakage between indurating
furnace zones and the diversion of waste gas for temperature control.



# 7.8.2 Identification of Potent ial CO Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various CO control technologies are discussed in Section
4.0 and Table 7-13. Potential control technologies for pellet plant partic ulate emissions are the
following:

• Thermal oxidizer (Recuperative and Regenerative)

• Catalytic oxidizer

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# • Good combustion controls

• Good design methods and operating practices



# 7.8.3 Elimination of Technically Infeasible CO Control Options

Table 7-13 summarizes the technical feasibility of CO control technologies for the waste gas stream
and the hood exhaust. Details regarding the feas ibility of each technology are discussed in the
following sections.

Estimated CO concentrat ions in the waste gas and hood exhaust are 9 ppm and 2 ppm respectively
using the CO mass emission rate from the Air Em ission Inventory (Appendix 3.B.), and stack flow
rate from form GI-04. Removal of additional CO at these concentrations is technically infeasible.

Even if some CO removal were technically feasible, the amount removed woul d be so small that
removal would be economically infeasible.

Application of Good Design and Oper ating Practices is the only feas ible CO emission control method

for the hood exhaust

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## Table 7-13 Technical Feasibility of CO Control Technologies for Taconite Pellet Indurating Furnace
CO Emission Control Technologie s Considered for BACT Analysis

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No



## Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize CO to CO 2


## . This may be accomplished using an add on oxidizer or a duct burner. No No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of CO at lower temperatures than a thermal incinerator. No No

Good Combustion Controls Good combustion control limits the formation of CO by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes No

Good Design Methods and Operating Practices Design, operate and maintain the indurating furnace in a manner which minimizes waste gas bypasses to the hood exhaust within product quality and production constraints 

## Yes Yes



# Catalytic oxidation is considered infeasible for the induration waste gas because particulate matter in
the waste gas would plug the catalyst bed, blind catalyst sites or sulfur in the waste gas would poison
the catalyst.

Application of a thermal oxidizer on the waste gas is technically infeasible due to the high energy
requirement for heating the waste ga s to thermal oxidizer operating temperatures. Application of a
thermal oxidizer on the waste gas would have simila r energy requirement as the application of SNCR
downstream of pellet plant pollution control equipment. Based on th e SNCR analysis, reheating the
waste gas stream would consume 1,650 million cubic feet of natural gas per year.

No add-on controls are considered feasible for the hood exhaust due to low CO concentrations. No
combustion gases are presen t in the hood exhaust.

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# 7.8.4 Ranking of Remaining CO Control Technologies by Control Effectiveness
The third of the five steps in the top-down BA CT analysis is to rank the remaining control
technologies by control effectiveness. The re maining control technologies and their control
efficiencies are presented in Table 7-14.

Table 7-14 Remaining CO Control Technologies and Control Effectiveness for the Taconite Pellet Indurating Furnace
CO Control Technology

Rank Technology Waste Gas Control Efficiency Hood Exhaust Control Efficiency



## 1 Good Combustion Controls Inherent Controls NA

1 Good Design Methods and Operating Practices 

## Inherent Controls Inherent Controls



# 7.8.5 Evaluation of Most Effect ive CO Control Technologies

Each of the most effective contro l technologies from Table 7-14 ar e evaluated in Table 7-15 for the

Indurator Waste Gas Stream and Ta ble 7-16 for the Indurator Hood Exhaust. The detailed control
cost analyses are located in Attachment A for th e hood exhaust and Attachment B for the waste gas.

Table 7-15 Evaluation of Most Effective CO Control Technologies for the Taconite Pellet Indurating Furnace Waste Gas Stack

Waste Gas CO Control Technology Effectiveness Evaluation



## Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Good Combustion Controls Base Case NA NA NA NA

Good Design Methods and Operating Practices Base Case NA NA NA NA

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## Table 7-16 Evaluation of Most Effective CO Control Technologies for the Taconite Pellet Indurating Furnace Hood Exhaust

Hood Exhaust CO Control Technology Effectiveness Evaluation



## Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Good Combustion Controls Base Case NA NA NA NA

Good Design Methods and Operating Practices Base Case NA NA NA NA



# 7.8.6 Pellet Plant Indurating Furnace CO BACT Selection

Based on the low levels of CO present in the Hood exhaust, the proposed BACT for the Hood
exhaust is good combustion practices. The propos ed mass emission limit for the hood exhaust is
4.4 lb/hr and 2.1 ppm CO on a 1-hour average basis. The mass emission limit is based on operation

with BACT controls and the facil ity running at full capacity.

The proposed BACT for the Waste Gas Stack is 12 lb/hr and 9 ppm CO on a 1-hour average basis.
No add-on controls are recommended to meet the pr oposed CO BACT limit. This BACT limit will
be achieved using good combustion practices. This is consistent with the Taconite MACT for new

sources. The Taconite MACT is a recently promulgated standard , and the MACT standard for new
taconite plants is represen tative of the best level of controls achievable. Th e mass emission limit is
based on operation with BACT controls and the facility running at full capacity.

The CO BACT also includes good combustion practic es, design methods and operating practices for
minimizing waste gas migration into the hood exhaust system.

There were no BACT determinations listed in the RBLC for CO emissions from ta conite plants.
BACT report Attachment L, Table L -1 is a su mmary RBLC search finding for taconite plants.

For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting pellet plant process equipment into service, and will continue this practice until the process is shut
down and off line. However, CO emissions during star tup will be higher than normal due to increased
fuel consumption. Additional fuel firing is needed to bring the pelletizer furnace temperature up to
operating conditions. Once steady state conditions are reached, fuel consumption will return to

normal. See Attachment M, Tabl e 1, for a summary of proposed startup/shutdown emission limits

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# 7.8.7 Sources of Induratio n Furnace VOC Emissions

Volatile organic compound emissions are formed by th e incomplete combustion of the natural gas in
the combustion zone of the indurating furnace. Thes e emissions are a function of the residence time
at flame temperature, combustion zone, burner characteristics, design and the turbulence of gases
within the indurating furnace combustion zone.

The majority of combustion zone gases, where VOC is generated, are emit ted through the Waste Gas

stack. The Hood Exhaust contains a small amount of VOC due to leakage between indurating
furnace compartments and the diversion of a smal l amount of waste gas for temperature control.



# 7.8.8 Identification of Potent ial VOC Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various VOC control technologies are discussed in Section
4.0 and Table 7-17. Potential control technologies for pellet plant partic ulate emissions are the
following:

• Thermal oxidizer (Recuperative and Regenerative)

• Catalytic oxidizer

• Good combustion controls

• Good design methods and operating practices



# 7.8.9 Elimination of Technically Infeasible VOC Control Options

Table 7-17 summarizes the technical feasibility of VOC control technol ogies for the waste gas stream
and the hood exhaust. Details regarding the feas ibility of each technology are discussed in the
following sections.

Estimated VOC concentrations in the waste gas and hood exhaust are 8 ppm and 2 ppm respectively
using the VOC mass emissi on rate from the Air Emission Inventor y (Appendix 3.B.), and stack flow
rate from form GI-04. Removal of additional VOC at these concentrations is technically infeasible.
Even if some VOC removal were technically feas ible, the amount removed would be so small that
removal would be economically infeasible.

Application of Good Design and Oper ating Practices is the only feas ible emission control method for

the hood exhaust

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## Table 7-17 Technical Feasibility of VOC Control Technologies for Taconite Pellet Indurating Furnace
VOC Emission Control Technologies Considered for BACT Analysis

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No



## Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize VOC to CO 2 

## and water. This may be accomplished using an add on oxidizer or a duct burner. No No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of VOC at lower temperatures than a thermal incinerator. No No

Good Combustion Controls Good combustion control limits the formation of VOC by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes No

Good Design Methods and Operating Practices Design, operate and maintain the indurating furnace in a manner which minimizes waste gas bypasses to the hood exhaust within product quality and production constraints 

## Yes Yes



# Catalytic oxidation is considered infeasible for the induration waste gas because particulate matter in
the waste gas would plug the catalyst bed, blind catalyst sites or sulfur in the waste gas would poison
the catalyst.

Thermal oxidation is considered infeasible for th e induration waste gas becau se of the inordinate
amount of energy which would be required to operat e a thermal oxidizer for a very large gas stream.
Natural gas consumption for a thermal oxidizer is es timated to be 1,520 millio n cubic feet of natural

gas per year

No add-on controls are considered feasible for the hood exhaust due to low VOC concentrations. No
combustion gases are presen t in the hood exhaust.

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# 7.8.10 Ranking of Remaining VOC Control Technologies by Control Effectiveness
The third of the five steps in the top-down BA CT analysis is to rank the remaining control
technologies by control effectiveness. The re maining control technologies and their control
efficiencies are presented in Table 7-18.

Table 7-18 Remaining VOC Control Technologies and Control Effectiveness for the Taconite Pellet Indurating Furnace
VOC Control Technology

Rank Technology Waste Gas Control Efficiency Hood Exhaust Control Efficiency



## 1 Good Combustion Controls Inherent Controls NA

1 Good Design Methods and Operating Practices 

## Inherent Controls Inherent Controls



# 7.8.11 Evaluation of Most Effe ctive VOC Control Technologies

Each of the most effective contro l technologies from Table 7-14 ar e evaluated in Table 7-15 for the

Indurator Waste Gas Stream and Ta ble 7-19 for the Indurator Hood Exhaust. The detailed control
cost analyses are located in Attachment A for th e hood exhaust and Attachment B for the waste gas.

Table 7-19 Evaluation of Most Effective VOC Control Technologies for the Taconite Pellet Indurating Furnace Waste Gas Stack

Waste Gas VOC Control Technology Effectiveness Evaluation



## Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Good Combustion Controls Base Case NA NA NA NA

Good Design Methods and Operating Practices Base Case NA NA NA NA

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## Table 7-20 Evaluation of Most Effective VOC Control Technologies for the Taconite Pellet Indurating Furnace Hood Exhaust

Hood Exhaust VOC Control Technology Effectiveness Evaluation



## Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton
Good Design Methods and Operating Practices Base Case NA NA NA NA



# 7.8.12 Pellet Plant Indurati ng Furnace VOC BACT Selection

The proposed BACT for the Hood exhaust is no add-on controls. This determ ination is based on the
low levels of VOC present in the Hood exhaus t. BACT also includes good design methods and
operating practices for minimizing waste gas migr ation into the hood exhaust system. The proposed

mass emission BACT limit for the Hood Exhaust Gas Stack is 2.1 lb/hr and 1.8 ppm VOC on a 24-
hour average basis

The proposed BACT for the Waste Ga s Stack is 5.9 lb/hr VOC on a 24 hour average basis. No addon controls are recommended to m eet the proposed VOC BACT limit. This BACT limit will be
achieved using good combustion practices. This is consistent with the Taconite MACT for new

sources. The Taconite MACT is a recently promulgated standard, and the MACT standards for new
taconite plants are representative of the best level of controls achievable.

The VOC BACT also includes good combustion prac tices, design methods and operating practices
for minimizing waste gas migrati on into the hood exhaust system.

There were no BACT determinations listed in the RBLC for VOC emissions from tac onite plants.
BACT report Attachment L, Table L -1 is a su mmary RBLC search finding for taconite plants.

The VOC BACT also includes good combustion prac tices, design methods and operating practices for
minimizing waste gas migration into the hood exhaust system. For periods of startup and shutdown,
Minnesota Steel will follow good combustion practices while putting pellet plant process equipment into
service, and will continue this practice until the pr ocess is shut down and off line. . However, NO
x 

# emissions during startup will be hi gher than normal due to increased fuel consumption. Additional
fuel firing is needed to bring the pelletizer fu rnace temperature up to operating conditions. Once

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# steady state conditions are reached, fuel consumption will return to normal. See Attachment M, Table
1, for a summary of proposed st artup/shutdown emission limits.



# 7.9 Fluoride (F) Emissions

7.9.1 Sources of Induration Furnace Fluoride Emissions
The majority of fluoride emissions originate from the fluoride salts present in the taconite ore.
Fluorides are released in gaseous form as a result of the high operating temperature of the induration

furnace. There is also a small amount of fluoride emission from natural gas combustion. The
emission inventory and BACT review determined the fluoride em ission rate is based on the fluoride

salt content of the ore.

Most of the fluoride emissions emanate from the waste gas stack, which vents the regions of the

induration furnace where sufficie nt temperature exist to liberate fluoride compounds from the

taconite. The hood exhaust contai ns a small amount of fluoride due to leakage between induration
furnace compartments and the diversion of a smal l amount of waste gas for temperature control.



# 7.9.2 Identification of Potentia l Fluoride Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various fluoride control technologies are discussed in

Section 4.0 and Table 7-21. Potential control techno logies for pellet plant particulate emissions are
the following:

• Wet Scrubber

• Wet ESP

• Spray dryer absorption

• Dry sorbent injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design and Operating Practices



# 7.9.3 Elimination of Technically In feasible Fluoride Control Options

All of the listed technologies are technically feasible in this appl ication for waste gas exhaust given

that some fluoride emissions control will occur as a co benefit of the SO 2 

# emission controls installed

as BACT

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# Fluoride concentrations in the hood exhaust howeve r are calculated to less than 1 ppb using the

fluoride mass emission rate from the Air Emission Inventory (Appendix 3.B.), and stack flow rate

from form GI-04. Removal of additional fluoride at these concentrations is technically infeasible.

Even if some fluoride removal were technically feasible, the amount removed would be so small that
removal would also be economically infeasible.

Table 7-21 Technical Feasibility of Fluoride Control Technologies for Taconite Pellet Indurating Furnace

Fluoride Emission Control Technology Feasibility Analysis

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with fluoride and removes it. Yes No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with fluoride and removes it. A fabric filter is used to collect the spent sorbent. Yes No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for fluoride removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For fluoride removal, caustic is added to the water spray system, allowing the spray system to function as a fluoride absorber. Yes No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. Fluoride reacts with sorbent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology Yes No

Clean Fuel/ Good Combustion Practices (Base Case) Use natural gas as induration fuel source to minimize fluoride emissions. Yes No

Good Design and Operating Practices Design, operate and maintain the induration furnace in a manner which minimizes waste gas bypasses to the hood exhaust within product quality and production constraints Yes Yes



# All control technologies are considered technically feasi ble for control of fluoride emissions in the waste
gas. However, fluorides are present only in low con centrations and measurable emission reductions may
not be quantifiable.

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# Application of Good Design and Oper ating Practices is the only feas ible emission control method for

fluoride emissions from the hood exhaust. Steam



# 7.9.4 Ranking of Remaining Fluorid e Control Technologies by Control Effectiveness
The remaining control technologies and their cont rol efficiencies are pr esented in Table 7-22.

Table 7-22 Ranking of Remaining Fluoride Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace

Fluoride Control Technology Ranking

Rank Technology Waste Gas Control Efficiency Hood Exhaust Control Efficiency

1 Wet Scrubber 90% NA

1 Spray Dryer Absorption 90% NA

2 Wet Electrostatic Precipitator 80% NA

3 Dry Sorbent Injection 50% NA

4 Clean Fuel/ Good Combustion Practices (Base Case) Inherent NA

5 Good Design Methods and Operating Practices Inherent Inherent



# SO 2 

# control efficiencies have been used as a general indicator of the emission control effectiveness
on fluoride compounds in the waste gas. Th e listed control ef ficiencies are for SO 2 

# removal, and are
presented only for example calculations of the fluo ride control cost. Fluorides are present only in
trace quantities in the taconite ore, and released as acid gases due to the temperatures of the
indurating process. Since SO 2 

# gases are acidic, SO 2 

# control efficiencies are a good indicator of

control effectiveness for fluoride emissions because fluorides are also acidic. Based on the Air
Emission Inventory (Appendix 3B.), stack flow rate from form GI-04, the uncontrolled fluoride
concentration in the waste gas is less than 1 ppb. Given the low c oncentrations of fluoride, fluoride
control efficiency may vary from the overall SO 2 

# control efficiency

As noted above, fluoride concentrations in the pelletizer exhaust streams are too low for control
equipment to be considered technically feasible.

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# 7.9.5 Evaluation of Most Effect ive Fluoride Cont rol Technologies
The BACT technology effectiveness summary is presented in two tables; one for the waste gas stack
(Table 7-23) and one for the hood exhaust (Table 7-24) . As noted above, fluoride concentrations in
the pelletizer exhaust streams ar e approximately 1 ppb; therefore, add on controls are technically
infeasible. The detailed control cost analyses ar e located in Attachment A for the hood exhaust and
Attachment B for the waste gas.

Table 7-23 Evaluation of Most Effective Fl uoride Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream
Waste Gas Control Technology Effectiveness Evaluation

Control Technology Control Eff % Emission Reduction T/yr* Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Add on Controls (absorber or dry scrubber ) 95% 1.7E+01 $11,956,125 $2,108,175 $121,264

Clean Fuel/ Good Combustion Practices (Base Case) Base Case NA NA NA NA

Good Design Methods and Operating Practices Base Case NA NA NA NA



# The lowest pollution control cost of the technically feasible control equipment was used as an
example too show that add on emission controls are economically infeasible when fluorides are
emitted in trace quantities. The results of the example calculations are summarized in Attachment B

Table B-1

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## Table 7-24 Evaluation of Most Effective Fl uoride Control Technologies for the Pellet Plant Indurating Hood Exhaust Stream
Hood Exhaust Control Technology Effectiveness Evaluation

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton
Clean Fuel/ Good Combustion Practices (Base Case) Base Case NA NA NA NA

Good Design Methods and Operating Practices Base Case NA NA NA NA



# To show that add on emission controls are economically infeasible when fluorides are emitted in
trace quantities, a 99% control efficiency was used as an example to calculate control costs for the
hood exhaust. The example calculation yields cont rol costs of $4.2 million per ton of fluoride
removed. The results of the example calculations are summarized in Attachment A Table A-1



# 7.9.6 Pellet Plant Indurating Fu rnace Fluoride BACT Selection

The proposed BACT for the waste gas stack is application of BACT SO 2 

# emission controls to

minimize fluoride emissions, use of clean fuels (natural gas or its equivalent), and good design
methods and operating practices for minimizing wast e gas migration into the hood exhaust system.

The proposed fluoride limit for the hood exhaust is 0.013 lb/hr. The proposed fluoride limit for the,
waste gas stack is 0.25 lb/hr. Compliance will be demonstrated for both limits by performance
testing for particulate matter and measurement of fluoride in the raw materials fed to the Pelletizer.
The averaging period for fluoride emissions is 3 hour s (three 1-hour test runs ).The BACT review of

SO 2 

# emissions control for the waste gas stack indicates that SO 2 

# absorption and dry scrubbing are the
top SO 2 

# control devices. Therefore, both devices are considered the best performing control devices
for waste gas fluoride emissions. Due to the low concentrations of fluorides in the uncontrolled
waste gas (< 1 ppb), performance ba sed BACT emission limits for fl uorides are not recommended.

Since fluoride emissions are related to SO 2 

# emissions, Minnesota Steel proposes to demonstrate
ongoing control of fluoride emis sions by operating its SO 2 

# emissions control equipment in
accordance with the proposed BACT limit for SO 2 

# and monitoring the fluoride content in the green

balls..

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# Due to the low concentrations of fluorides in the hood exhaust (< 1 ppb), no add on controls are
technically feasible. The proposed BACT fo r the Hood Exhaust is good design methods and
operating practices for minimizing waste ga s migration into the hood exhaust system.

There were no BACT determinations listed in the RBLC for fluoride emissions from taconite plants.
BACT report Attachment L, Table L -1 is a su mmary RBLC search finding for taconite plants

For periods of startup and shutdown, Minnesota Steel will put the pellet plant fluoride emission control
equipment into service prior to commencing operation of process equipment, and keep controls operating
until the process is shut down and off line. No excess emissions will occu r as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 7.10 Pellet Plant Sulfuric Acid Mist Emissions

7.10.1 Sources of Induration Furna ce Sulfuric Acid Mist Emissions

Sulfuric Acid Mist (SAM) is emitted from the pellet plant in trace quantities. The majority of SAM
emissions originate from the sulfur present in the taconite ore. There is also a small amount of

Sulfuric Acid Mist emission from natural gas combustion. The evaluation of add-on controls for
SAM at the pellet plant will be based on SAM co ncentrations of 0.1 ppm and 3 ppm respectively for
the hood exhaust and waste gas streams. These co ncentrations are calcul ated from the SAM mass

emission rates in the Air Emission In ventory (Appendix 3B.), and stack flow rates from form GI-04.

Most of the SAM emissions emanate from the wast e gas stack as the regions of the induration
furnace where sufficient temperatur es exist to liberate sulfur com pounds from the taconite. The hood

exhaust contains a small amount of SAM due to leakage between induration furnace compartments

and the diversion of a small amount of waste gas for temperature control.



# 7.10.2 Identification of Po tential Sulfuric Acid Mi st Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various Sulfuric Acid Mist control technologies are

discussed in Section 4.0 and Table 7-25. Potential control technologi es for pellet plant particulate
emissions are the following:

• Wet Scrubber

• Wet ESP

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# • Spray dryer absorption

• Dry sorbent injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design and Operating Practices



# 7.10.3 Elimination of Technically Infe asible Sulfuric Ac id Mist Control Options
All of the listed technologies are technically feasible in this appl ication for waste gas exhaust given

that some SAM emissions control will occur as a co-benefit of the SO 2 

# emission controls installed as

BACT

Sulfuric Acid Mist (SAM) concentrations in the hood exhaust are calculated to be less than 1 ppm based

on the SAM mass emission rate from the Air Emissi on Inventory (Appendix 3.B.), and stack flow rate

from form GI-04. Removal of additional Sulfuric Acid Mist at these concentrations is technically

infeasible.

Table 7-25 Technical Feasibility of Sulfuric Acid Mist Control Technologies for Taconite Pellet Indurating Furnace

Sulfuric Acid Mist Emission Control Technology Feasibility Analysis

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with Sulfuric Acid Mist and removes it. Yes No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with Sulfuric Acid Mist and removes it. A fa bric filter is used to collect the spent sorbent. Yes No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for Sulfuric Acid Mist removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For Sulfuric Acid Mist removal, caustic is added to the water spray system, allowing the spray system to function as an Sulfuric Acid Mist absorber. Yes No

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## Sulfuric Acid Mist Emission Control Technology Feasibility Analysis

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. Sulfuric Acid Mist reacts with sorbent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology Yes No

Clean Fuel/ Good Combustion Practices (Base Case) Use natural gas as induration fuel source to minimize Sulfuric Acid Mist emissions. Yes No

Good Design and Operating Practices Design, operate and maintain the induration furnace in a manner which minimizes waste gas bypasses to the hood exhaust within product quality and production constraints Yes Yes



# SO 2 

# control efficiencies have been used as a general indicator of the emission control effectiveness
on SAM in the waste gas. SAM is an acid gas present only in trac e quantities in the hood exhaust
and waste gas. Since SO 2 

# gases are also acidic; SO 2 

# control efficiencies ar e a good indicator of

control effectiveness for SAM emissions. Based on the Air Emission Inventory (Appendix 3B.),
stack flow rate from form GI-04, the uncontrolled SAM concentration in the waste gas is less than 1
ppm. Given the low concentrations, SAM control efficiency may vary from the overall SO 2 

# control
efficiency

As noted above, SAM concentrations in the hood exha ust streams are too low for control equipment to be
considered technically feasible.



# 7.10.4 Ranking of Remain ing Sulfuric Acid Mist Control Technologies by Control Effectiveness

As noted above, SAM concentrations in the pelletizer exhaust streams are less than 1 ppm; therefore,

add on controls are tech nically infeasible.

The remaining control technologies and their cont rol efficiencies are pr esented in Table 7-26.

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## Table 7-26 Ranking of Remaining Sulfuric Acid Mist Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace

Sulfuric Acid Mist Control Technology Ranking

Rank Technology Waste Gas Control Efficiency Hood Exhaust Control Efficiency

1 Wet Scrubber 90% NA

3 Spray Dryer Absorption 90% NA

2 Wet Electrostatic Precipitator 80% NA

4 Dry Sorbent Injection 50% NA

5 Clean Fuel/ Good Combustion Practices (Base Case) Inherent NA

6 Good Design Methods and Operating Practices Inherent Inherent



# As noted above, SAM concentrations in the pelletizer exhaust streams are too low for control
equipment to be considered technically feasible. The listed control efficiencies are for SO 2 

# removal,
and are presented only for example calc ulations of the SAM control cost.

Wet scrubber and spray dryer contro l efficiencies were provided with the cost estimate by the vendor
(Environmental Elements). Wet ElectroStatic Prec ipitator (WESP) control efficiency is based on
Northshore Mining Company’s experience with WESPs. Northshore is the only taconite plant which
employs WESP controls.



# 7.10.5 Evaluation of Most Effective Sulfuric Acid Mist Control Technologies

The BACT technology effectiveness summary is presented in two tables; one for the waste gas stack
(Table 7-27) and one for the hood exhaust (Table 7- 28). The detailed control cost analyses are

located in Attachment A for the hood exhaus t and Attachment B for the waste gas.

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## Table 7-27 Evaluation of Most Effective Sulfuric Acid Mist Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream
Waste Gas Control Technology Effectiveness Evaluation

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Add on Controls (absorber or dry scrubber) 90% 2.8 $17,343,207 $3,459,351 $1,226,251

Clean Fuel/ Good Combustion Practices Base Case NA NA NA NA

Good Design Methods and Operating Practices Base Case NA NA NA NA



# The pollution control cost of a scrubber was used as an example too show that add on emission
controls are economically infeasible when SAM is emitted in trace quantities. The results of the
example calculations are summarized in Attachment B Table B-1

Table 7-28 Evaluation of Most Effective Sulfuric Acid Mist Control Technologies for the Pellet Plant Indurating Hood Exhaust Stream
Hood Exhaust Control Technology Effectiveness Evaluation

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Good Design Methods and Operating Practices Base Case NA NA NA NA



# 7.10.6 Pellet Plant Indu rating Furnace Sulfuric Acid Mist BACT Selection

The proposed BACT for the waste gas st ack is the application of BACT SO 2 

# emission controls to

minimize SAM emissions, use of cl ean fuels (natural gas or its eq uivalent), and good design methods
and operating practices for minimizing waste ga s migration into the hood exhaust system. The

BACT review of SO 2 

# emissions control for the waste gas stack indicates that SO 2 

# absorption and dry
scrubbing are the top SO 2 

# control devices. Therefore, both devices are considered the best
performing control devices for waste gas SAM emissions. The proposed SAM limit for the hood
exhaust is 0.15 lb/hr and 0.21 ppm on a 3-hour average. The proposed SAM limit for the furnace
waste gas is 0.085 lb/hr and 0.018 ppm on a 3-hour av erage. Compliance w ill be demonstrated for

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# both limits by performance testing. The averagi ng period for SAM emission s is 3 hours, unless the

amount of material collect ed during the 3 hour period is insufficien t to accurately measure, in which
case the averaging period will be the time it takes to collect a sufficient amount of material. Due to
the low concentrations of SAM in the waste gas exhaust (< 1 ppm), BACT performance limits for

SAM are not recommended. Since control of SAM emissions is related to SO 2 

# emissions control,
Minnesota Steel proposes to demo nstrate control ongoing control of SAM emissions by operating its

SO 2 

# emissions control equipment in accordance with the proposed BACT limit for SO 2


# .

Due to the low concentrations of SAM in th e hood exhaust (< 1 ppm), no add on controls are
technically feasible. The propos ed SAM BACT for the Hood Exhaust is good design methods and
operating practices for minimizing waste ga s migration into the hood exhaust system.

There were no BACT determinations listed in the RBLC for SAM emissions from taconite plants.
BACT report Attachment L, Table L -1 is a su mmary RBLC search finding for taconite plants.

For periods of startup and shutdown, Minnesota Steel will put the pellet plant SO 2 

# emission control
equipment into service prior to commencing operation of process equipment, and keep controls operating
until the process is shut down and off line. No excess emissions will occu r as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 7.11 Pellet Plant Lead (Pb) Emissions

7.11.1 Sources of Induration Fu rnace Lead Matter Emissions
Lead is present in trace quantities in taconite ore. It is emitted as particulate matter, primarily due to
the attrition of particles (dust) fro m the taconite pellets. This is caused by the abrasion of pellets
rubbing against one and other and the process equi pment as the pellets mo ve through the induration
furnace. In addition, lead fume is generated by the high temperatures pelletizer firing zone.
However, lead fume formed in the process will be in a solid state (i.e. particulate) at the operating
temperatures of the pellet plant emission control equipment. Lead is emitted in particulate matter
form from both the waste gas and hood exhaust vents.



# 7.11.2 Identification of Pote ntial Pb Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 7-1. Potential contro l technologies for pellet plant lead emissions are the following:

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# • Fabric filter

• Wet scrubber

• Electrostatic precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (e.g. Cyclones)

• Inertial separators (drop out box)

• Good Design and Operating Practices



# 7.11.3 Elimination of Technicall y Infeasible Pb Control Options

All lead particulate emission control equipment reviewed is technically feasible in this application,
given that some lead emissions control will occur concurrently as a co-benefit of the particulate

emission controls installed as BACT.

Table 7-29 Evaluation of Most Ef fective Lead Control Technologies for the Pellet Plant Indurating Furnace Waste Gas Stream

Summary of Control Technology Feasibility

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

Fabric Filter (Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Lead

bearing particulate matter is collected on the surface of the bags as the gas stream passes through them. The lead bearing is periodically removed from the bags and collected in hoppers located beneath the bags. Yes Yes

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the lead bearing particulates out of the gas stream. Yes Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate lead bearing particles from

the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal. Yes Yes

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove lead bearing particulate matter from the collection plates. Yes Yes

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## Summary of Control Technology Feasibility

Technology Description Waste Gas Feasible? Yes or No Hood Exhaust Feasible? Yes or No

Centrifugal Separation (e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger lead bearing particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger lead bearing particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes Yes

Good Design and Operating Practices Design, operate and maintain the induration furnace in a manner which minimizes emissions of lead bearing particulate matter. Yes Yes



# 7.11.4 Ranking of Remaining Pb Control Technologies by Control Effectiveness
The remaining control technologies and their cont rol efficiencies are pr esented in Table 7-30.

Table 7-30 Ranking of Remaining Lead Control Technologies and Control Effectiveness for the Pellet Plant Indurating Furnace

Pb Control Technology Ranking

Rank Technology Typical % Efficiency Outlet Concentration

1 Baghouse 98% - 99+% 0.012 gr/dscf*

1 Wet Scrubber 95% - 99+% 0.012 gr/dscf*

1 Wet Electrostatic Precipitator 98% - 99+% 0.012 gr/dscf*

1 Dry Electrostatic Precipitator 98% - 99+% 0.012 gr/dscf*

2 Centrifugal Separation (e.g. Cyclones) 50% - 80% NA

3 Inertial Separators (Drop Out Box) < 50% NA

* Total particulate as measured by EPA Methods 201 or 201A (filterable) and Method 202 or EPA approved modified Method 202 procedures (condensable)

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# Particulate control efficiencies have been used as a general indicator of the emission control
effectiveness on lead bearing partic ulates. Lead in the hood exhaust and waste gas is present only in
trace quantities. Based on the Ai r Emission Inventory (Appendix B1.), and stack flow rate from form

GI-04, the calculated le ad concentration in the uncontrolle d hood exhaust is 0.0001 gr/dscf, and
0.00005 gr/dscf in the waste gas exhaust. Given th e extremely low concentrations of lead, control
efficiency may vary from the overall particulate control efficiency.



# 7.11.5 Evaluation of Most Effective Control Technologies

The detailed control cost analyses are loca ted in Attachment A for the hood exhaust and
Attachment B for the waste gas.

Table 7-31 Evaluation of Most Effective Pb C ontrol Technologies for the Pellet Plant Indurator Waste Gas Stream

Waste Gas Stack Control Technology Effectiveness Evaluation

Control Technology Control Efficiency Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Add on Controls (ESP, BH or wet scrubber) 95% 

## 9.4E-01 $2,609,897 $1,246,444 $1,326,561

Good Design and Operating Practices NA NA NA NA NA



# The lowest pollution control cost of the technically feasible control equipment was used as an
example too show that add on emission controls are economically infeasible when lead is emitted in
trace quantities. The results of the example calculations are summarized in Attachment B Table B-1

Table 7-32 Evaluation of Most Effective Pb C ontrol Technologies for the Pellet Plant Indurator Hood Exhaust Stream

Hood Exhaust Stack Control Technology Effectiveness Evaluation

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Good Design and Operating Practices 

## 93% 6.6E-01 $3,299, 221 $1,648,867 $2,509,625

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# The lowest pollution control cost of the technically feasible control equipment was used as an
example too show that add on emission controls are economically infeasible when lead is emitted in
trace quantities. The results of the example calculations are summarized in Attachment A Table A-1

Wet scrubbing, wet and dry EPS’s, and baghouses ca n remove particulate matter down to the 0.006
gr/dscf level as m easured by EPA Method 5. All controls are economically feasible. Based on the
control effectiveness ranking, choosing any of thes e technologies would result in selection of the top
emission control alternative, and can be considered BACT without additional economic analysis.

Wet scrubbing and Wet ESP’s have the advantage of being able to remove other pollutants (SO 2 

# and

NO
x 

# ) with minimal additional capital i nvestment. As noted in Section 7.6.6, the facility will have a
wastewater treatment system to handle process equipment wastewater with zero waste water
discharge. Since waste materi als would be managed through the wastewater system, there is no
advantage to collecting lead in a wet or dry form.



# 7.11.6 Pellet Plant Indurati ng Furnace Pb BACT Selection

The proposed BACT for lead emissions from the pellet plant is the application of BACT PM

emission controls to minimize lead emissions and good design methods and operating practices for
minimizing particulate emissions. The BACT re view of PM em issions control for both the hood
exhaust and waste gas stack indi cates that wet scrubbing, baghouses and wet and dry ESP’s are the
top PM control devices. Therefore, any of these devices can be considered the best performing
control devices for lead emissions from the pellet plan t. Due to the low concentrations of lead in the
uncontrolled waste gas exhaust (< 1 ppb), BACT emission limits for lead are not recommended.

Since control of lead emissions is related to particulate emissions control, Minnesota Steel proposes
to demonstrate control of lead emissions by operating its PM emissions control equipment in
accordance with the proposed BACT limit for particulate emissions from the pellet plant. The
preferred method of meeting the PM BACT is by wet scrubbing; however, an ESP or WESP would
be an acceptable contro l equipment alternative. The proposed emission lim it of lead for the hood
exhaust is 0.013 lb/hr. The propose d emission limit of lead for the w aste gas stream is 0.013 lb/hr.
Compliance demonstration for both limits will be determined by pe rformance testing for particulate
matter and measurement of lead in the raw materials fed to the Pelletizer. The averaging period for
lead emissions is 3 hours (t hree 1-hour test runs).

There were no BACT determinations listed in the RBLC for Pb emissions from taconite plants.
BACT report Attachment L, Table L -1 is a su mmary RBLC search finding for taconite plants

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# For periods of startup and shutdown, Minnesota St eel will put the pellet plant Pb emission control
equipment into service prior to commencing operation of process equipment, and keep controls operating
until the process is shut down and off line. No excess emissions will occu r as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 7.12 Combined Control Selectio n Considerations and Costs

Sections 7.4 through 7.11 considered the technical and economic feasibility of controlling emissions
from the hood exhaust and the waste gas exhaust on an independent pollutant basis. Although there
are several potential combinations of technologies, there are basically three potentially viable

alternatives:

• Scenario 1 - control of PM, SO 2 

# , and NO
x 

# with a wet scrubber that includes lime addition and
injection of ozone (LoTOx),

• Scenario 2 - control of NO
x 

# with SCR (on a portion of the waste gas exhaust), and control of

PM and SO 2 

# with a wet scrubber w ith lime addition, and

• Scenario 3 - control of NO
x 

# with SCR (on a portion of the waste gas exhaust), control of SO 2 

# with dry absorption, and control of PM with a baghouse or dry or wet ESP.

In some cases, emission controls ha ve the potential to be used in c ontrolling multiple pollutants. At
Minnesota Steel, the wet scrubber for the pellet pl ant has the potential for multi-pollutant control.

The wet scrubber will control PM, SO 2 

# , NO
x 

# , as well as the other less si gnificant polluta nts (fluoride,
sulfuric acid mist, and lead). Table 7-33 is a summary of the incremental costs for adding the
capacity to the waste gas scrubber to control addi tional pollutants (beyond a basic scrubber designed
for PM control). The incremental costs represent the additional equipment needed to accommodate
control of additional pollutants. No other control equipment scenarios at Minnesota Steel have these

same cost considerations.

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## Table 7-33 Wet Scrubber/Absorber/LoTOx - Combined Pollutant Control Cost Summary

Pollutant Control Eff % or Outlet Concentration Annualized Operating Cost $/yr Pollution Control Cost $/ton Incremental Operating Cost $/yr Incremental Control Cost $/ton

Particulate Matter (PM) 0.012 gr/dscf* $1,246,444 $729 Base Case Base Case

Sulfur Dioxide (SO 2 

## ) 90% $2,108,175 $6,158 $861,731 $2,517
Nitrogen Oxides (NOx) 90% $7,330,492 $4,751 $5,222,317 $3,384

* Total particulate as measured by EPA Methods 201 or 201A (filterable) and Method 202 or EPA approved modified Method 202 procedures (condensable).



# From Table 7-33 it can be seen that the cost control Scenario 1 is approximately half when the
control technologies are combined. In addition, these three technologies are as effective, if not more
effective, than any of the other control technologies . Scenario 1 would also provide co-control of
sulfuric acid mist and other acid gases, fluoride and lead. LoTOx has also been shown to increase
the control efficiency of mercury from coal fired boi lers. Most of the mercur y emitted from taconite
pellet plants is emitted from the waste gas exha ust in the form of elemental mercury. At the
temperatures in the waste gas exhaust the elemental mercury is in the form of a vapor and passes
through most control devices. Oz one used in the LoTOx process has also been shown to oxidize
mercury. Oxidized mercury can be captured by the wet scrubber and removed from the air stream.
Minnesota Steel Industries plant design includes a zero discharge waste water treatment system for
process waste water which includes lime softening and reverse osmosis treatment. Reverse osmosis
reject water will be reduced to solids in an evaporator/crystallizer system. Mercury captured in the
wet scrubber will be incorporated into the waste water treatment system solids. Solids from the
softening and reverse osmosis system will be managed and disposed of as a solid or hazardous waste
as appropriate pending test ing of the waste stream.

Control Scenario 2 represents an alternative to LoTOx. Although not as effective as LoTOx, SCR
represents a control technology that may be feasible for controlling the hotter portions of the waste
gas exhaust. However, a pellet plant has never been designed or operated in the manner that would
be necessary to employ SCR. SCR would also need to be tested be fore designed and implemented.

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# SCR may by a viable alternative to LoTOx should th e LoTOx trial fail. In addition, the pelletizer

wind boxes would have to be rec onfigured to accommodate SCR.

SCR followed by a wet scrubber with lime addition w ould still provide for co-control of sulfuric acid
mist, other acid gases, fluorides and lead. SCR has also been shown to oxidize mercury and
therefore would provide for some additional remova l of mercury in the same manner as LoTOx.
However, just as with NO
x 

# , the mercury removal efficiency woul d be less because only a portion of
the waste gas exhaust would be treated. Ammonia slip from SCR may have adverse effects on the
pellet plant. In addition, ammoni a and ammonium sulfate salts which may also be emitted as a result
of ammonia slip may contribute to visibility impacts in nearby Class I areas.

Implementation of control Scenario 3 is not feasible for the following reasons:

• The pellet plant design would be the first of its kind,

• SCR has never been demonstrated on a pellet plant and has all of the same disadvantages as

discussed for control Scenario 2,

• The use of dry control for SO 2 

# and PM would add to the need for design modifications to the
pellet plant,

• Operating all three innovative cont rol technologies at once, whil e still maintaining production
parameters and capacity at the pellet plant, would involve a complex flow and temperature
control system, risking product quality

• SCR with dry controls would not control acid ga ses or fluorides nearly as well as the other
control scenarios. SCR will gene rate additional sulfuric acid mist due to the conversion of

SO 2 

# to SAM by the SCR catalyst.

• Control of oxidized mercury from the SCR uni t would be significantly less and additional

controls would be needed to achieve the sa me level of control as scenarios 1 and 2,

Scenario 3 involves the application of 3 innova tive technologies and a major redesign of the
pellet plant. Scenario 3 represents a very risk y approach to producing quality taconite pellets
while controlling emissions. It is unlikely that financing could be secured for a project with this
degree of uncertainty and risk. If Scenario 3 is unsuccessful, a great deal of investment could be

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# stranded. Scenarios 1 and 2 involve only the application of 1 innovative technology. The wet
scrubber is a proven technology to control PM and SO 2 

# emissions from taconite pellet plants and,
regardless of the resulting feasibility of NO
x 

# control technologies, can be financed and installed
as part of the initial pellet plant configurat ion. By permitting a tr ial of LoTOx controls,
information can be obtained to evaluate their feasibility and design a system that has a higher
degree of certainty. The cost and the risk of testing LoTOx control tec hnology are much less and
can be financed or paid for with operating capital.



# 7.13 Pellet Plant Material Handling BACT Selection Summary

In the pelletizing section of the plant, material handling equipment includes ore crushing equipment,
ore screening and ore conveyor drops . Material handling equipment in the pelletizing section of the
plant includes green and fired taconi te pellet screening, pellet co nveyor drops, and finished pellet
coating operations.

In order to simplify the BACT report, emissions controls for ma terial handing equipment throughout
the facility are reviewed in Section 11 of the BACT report. Material handing equipment reviewed in
Section 11 includes conveyor drops, crushing and gr inding operations and scre ening of raw materials
and intermediate products. Section 11 also contains a list of ma terial handling sources covered by the
material handling BACT analysis.

BACT for material handling the pellet plant area of the facility is th e use of a wet scrubber or fabric
filter in conjunction with a vent ilated enclosure of the emission source. The proposed BACT limit
for particulate emissions is for we t scrubbers is 0.005 gr/dscf and for baghouses is 0.0025 gr/dscf as
measured by EPA Method 5. Attachment N specifie s the type of control applied to each emission
point. Where feasible baghouses have been specified

For periods of startup and shutdown, Minnesota St eel will put material handling particulate emission
control equipment into service prior to commencing operation of process equipment, and keep controls
operating until the process is shut dow n and off line. No excess emissions will occur as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.

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# 7.14 Additive Material Handling

7.14.1 Process Description
In order to simplify the BACT report, emissions controls for additive material handing equipment
throughout the facility are reviewed in Section 12.0 of the BACT report. Preparation of the green taconite
balls requires the use of additives. In general, additives are transferred pneumatically. This includes
transfers from delivery trucks to storage bins and tran sfers from storage bins to the process. Therefore,
the emission control requirements for additive material handling are slightly different from control
requirements for material handling of raw material s and products. BACT control requirements for
additive material handling are addressed in Section 12.0 of the BACT report.



# 7.14.2 Summary of BACT for Additi ve Handling in the Pellet Plant
BACT for additive material handling in the pellet plant of the facility is the use of fabric filter bin
vents to control particulat e emissions from pneumatic transfers of additive materials. The proposed
BACT limit for particulate emissions (PM/PM 10 

# ) is 0.0025 gr/dscf as meas ured by EPA Method 5.

Minnesota Steel will put the additive handing em ission control equipment into service prior to
commencing transfer operations, and keep controls operating until the transfer is complete. No excess
emissions will occur as a result of control equipment st artup/shutdown. Therefore, Minnesota Steel is not
proposing any special permit conditio ns for startup and shutdown.



# 7.15 Pellet Plant Fugitive Dust Em issions BACT Selection Summary

Fugitive dust emissions are partic ulate emissions which occur from the mechanical disturbance of
granular material exposed to the air. These emissions are termed “fugitive” because they are not
discharged to the atmosphere in a confined flow stream such as a duct or stack.

Sources of fugitive particulate em issions from the pellet plant operations at Minnesota Steel will
include unpaved roads, storage piles, loading and unloading operations, and material drops from
mobile equipment.

In order to simplify the BACT report, emissions controls for ma terial handing equipment throughout
the facility are reviewed in Section 15 of the BACT report. Fugitive sourc es reviewed in Section 15
include mining operations, tailings basins, unpaved roads, storage piles, loading and unloading
operations, and material drops from mobile equipment. Section 15 al so contains a list of sources
covered by the fugitive dust BACT analysis.

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# Minnesota Steel will follow industry best practi ces for controlling fugitive dust emissions.

Minnesota Steel has prepared a fugitive dust control plan (Attachment O) which describes the

measures Minnesota Steel will take to control thes e emissions. Dust control measures listed in the
plan represent best practices and are consistent with dust control techniques used by other mining

facilities in the area.

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# 8.0 Direct Reduced Iron Plant

8.1 Direct Reduced Iron Plant Overview

8.1.1 Direct Reduce d Iron (DRI) Plant

The direct reduced iron (D RI) plant converts iron oxide (taconite) pellets into highly metallized (~94
percent) iron pellets suitable for use as feedstock to the electric arc furnaces in the onsite steel mill.

The DRI Process

There are two major reaction systems within the direct reduction process, the reduction of iron in the
reduction furnace and the generation of re ducing gas in the process gas heater.

In the reduction furnace, iron oxi de (primarily hematite, with the chemical composition of Fe 2 

# O 3 

# )
reacts with carbon monoxide (CO) and hydrogen (H 2 

# ) contained in a reducing gas to produce metallic
iron (Fe) while liberating carbon dioxide (CO 2 

# ) and water vapor (H 2 

# O). The overall reduction

reactions are:

Fe 2 

# O 3 

# + 3 H 2 

# Æ 2 Fe + 3 H 2 

# O

Fe 2 

# O 3 

# + 3 CO Æ 2 Fe + 3 CO 2



# The second major reaction system within the direct reduction process is the reforming of methane to
produce the reducing gas. These reac tions take place in the DRI proc ess heater and continue in the

DRI reactor. In the DRI reactor, iron acts as a cata lyst for methane reforming reactions. Natural gas
(CH 4 

# ), the primary source of energy and reactant for the process, is converte d (reformed) to produce
a reducing gas rich in CO and H 2 

# . The important reforming reactions are:

CH 4 

# + 1⁄2 O 2 

# Æ CO + 2 H 2



# CH 4 

# + H 2 

# O Æ CO + 3 H 2



# CO + H 2 

# O Æ H 2 

# + CO 2

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# The iron reduction process is as follows.

Under normal DRI plant operations , oxide pellets are tr ansferred by conveyor from oxide pellet
storage pile to the oxide pellet screening and then to the top of the vertical reduction reactor (DRI
furnace). Oxide pellets are discharged into the DR I loading bin, which feed s four pressurized bins
that alternately discharge oxide pellets into the DRI reactor.

In the reactor, the oxide pellets move slowly downward through the reactor’s reduction zone by
gravity against a countercurrent flow of reducing ga s, which converts iron ox ide to metallic iron.
The reducing gas is a mixture of hydrogen and carbon monoxide, both of which extract oxygen from
the oxide pellets to form water and carbon dioxide. Reducing gas exiting the top of the DRI reactor
(“top gas”) is cleaned, purified and recycled by processes described below. As the pellets reach the
bottom of the reactor, they pass through a mixture of natural gas and carbon monoxide, which cools
the DRI pellets and increase s the carbon content of the product. Th e hot metallic iron also acts as a
catalyst in promoting reforming reactions to convert the natural gas to H 2 

# and CO. The DRI product
will be hot charged to the steel mill electric arc furnaces (EAFs) or, during steel mill down-time, will
be stockpiled for later use or for sale.

Hot DRI pellets are transferred to the melt shop via a Pneumatic Trans port System (PTS). The
pneumatic transfer gas is a mixture of nitrog en and purified process gas from the Tail Gas
Purification system. Clean transfer gas is compressed and heated in the PTS gas heater. The hot
transfer gas is then used to pneumatically transport hot DRI pellets to the steel mill DRI feed
hoppers. Heating the transfer gas keeps the DRI pell ets hot as they are pneu matically transported.

The DRI feed hopper system for the EAF has two de pressurization steps. Tr ansfer gas leaving the
first transport surge bin is passed through a quench orifice and venturi for cooling and particulate
removal. Water is added at the orifice for cooling and particulate removal. Particulates are separated
from the transfer gas in the PTS gas separator. Additional transfer gas cleaning occurs in the PTS
quench tower, PTS knock out drum and mechanical filter. After clea ning, the PTS gas is
compressed, re-heated and recycled. Some transfer gas is vented to the DRI process heater where it
is used as fuel. Nitrogen and process gas are added to make up for lost transport gas.

The second depressurization step occurs in the pressurized interf ace bin. Transfer gas vented from
the interface bin is primarily n itrogen. Gas leaving th e interface bin is pa ssed through a quench
orifice and venturi for cooling and particulate removal. A quench system in the base of the PTS

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# depressurization stack allows for se paration of the particulate from the gas before it is vented out the

stack.

DRI pellets leaving the pressurized interface bin then flow into the EAF surge bins, and are charged
to the EAFs from the surge bins.

DRI pellets routed to cold storage are cooled through the external cooler system. The external cooler
uses a circulating cooling gas and natural gas to co ol the hot DRI pellets. Hot pellets flow down
through the cooler while the circulating gas and natural gas flow up through the cooler counter
current to the DRI pellets. Cooling gas is inject ed near the bottom of the cooling drum, and natural
gas is injected at the bottom of the cooler to complete the cooling process. Cooling gas leaving the
top of the external pellet cooler is passed through a water quench orifice and venturi for cooling and
particulate removal. Particulates are separated fro m the cooling gas in the cooling gas separator.
Additional cooling gas cleaning occurs in the coo ling quench tower, cooling gas knock out drum and
mechanical filter. After cleaning, the cooling gas is compressed and recycled. Excess cooling gas is
vented to the process heater for use as fuel.

The reducing gas production process is as follows:

Top gas exiting the top of the DRI reactor contains carbon dioxide, water, excess (unused) carbon
monoxide and hydrogen. Top gas is cleaned and cool ed by a water quench upon exiting the reactor.
After the iron dust has been removed, the top gas stream is compressed and purified in the Top Gas
Purification absorption system. The Top Gas Purification system uses an absorption/desorption
process to remove carbon dioxide and water from th e top gas. Next, natural gas is added to the
purified top gas to replenish the reducing gases consum ed by the DRI process. This step is followed
by humidification, which aids the reforming pro cess, and controls the ca rbon content of the DRI
pellets. The process heater raises the temperature of the process gas to the temperature needed for
the reforming reactions to begin the process of converting methane to CO and H 2 

# . After exiting the
process heater, a slip stream of oxygen is added. The oxygen burns some process gas to heat the
process gas to the temperature required for direct iron reduction.

The Top Gas Purification system used to remove CO 2 

# also removes Hydrogen Sulfide (H 2 

# S) from the
top gas. Small amounts of H 2 

# S are formed from sulfur present in the top gas stream under the
reducing conditions of the DRI reactor. Sulfur is introduced to the process as a trace constituent of
the oxide pellet and by purposely injecting sulfur into the gas stream to protect heating tubes from

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# erosion by high-heat conditions. An amine scrubbing solution is used for CO 2 

# and H 2 

# S removal.
Amines are organic chemicals which include nitrogen, in a chemical form similar to ammonia,

bonded to a carbon atom. Amine solutions are commonl y used in natural gas processing to remove

CO 2 

# and H 2 

# S. In the absorber tower, amines react with CO 2 

# and H 2 

# S in an acid-base reaction to
chemically capture and remove them from the process gas. Decarbonated process gas leaving the
absorber is filtered to remove residual liquid drop lets and returned to the DRI process gas heater.
The saturated amine is regenerated in the Top Gas Pu rification stripper tower. Steam heat is used to

break the amine-CO 2 

# and amine-H 2 

# S bonds. Steam is provided by a na tural gas fired package boiler.
Once regenerated, the amine solution is recycled back to the Top Gas Purification absorber. CO 2 

# and

H 2 

# S liberated from the amine scrubbing solution in the stripper are vented to the atmosphere.

Air emission point sources for two modules in the DRI plant include:

• 

# DRI package boiler stacks (combustion emissions)

• 

# DRI process gas heater stacks (combustion emissions)

• 

# Top Gas Purification system exhaust.

• 

# PTS gas heater stacks (combustion emissions),

• 

# Material handling scrubb er stacks (particulate emissions), which control emissions from both
mechanical (conveyor) and pneumatic transfers

• 

# Cooling towers (particu late emissi ons and CO 2 

# /CO blowdown vent)

• 

# Fugitive air emission sources in the DRI plant in clude particulate relea sed from handling of
oxide pellets, DRI product, and remet (o ff spec pellets to be reprocessed).

• 

# Emergency diesel engines

• 

# Emergency flare stacks (combustion emissions).

Emergency diesel engines are addresse d in Section 14 of the BACT report.

The emergency flare is a control device for process gas emissions generated by the DRI process
during startups, shutdowns and upset s. Its use is consistent with good air pollution control practice
for minimizing emissions. The fl are is not a source of emission s during normal operations, except
for an insignificant amount of combustion related emissions associated with the operation of the flare
pilot light.

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# 8.2 DRI Package Boiler

A natural gas fired package-boiler will provide st eam to operate the Top Gas Purification scrubber
sorbent regeneration system. One boiler will be installed for each DRI line. The DRI boilers are each
rated at 99 MMBtu/hr. Air po llutants emitted from the packag e boilers include: PM, PM10, SO 2 

# , NO
x 

# , CO, VOC. All emissions result from combustion of natural gas.



# 8.3 DRI Boiler Part iculate MatterPM/PM 10 

# Emission

Particulate emissions from natural gas combustion are typically low. Particulate matter is generated
during incomplete combustion. B ecause the boilers burn natural gas all particulates are assumed to

be PM 10 

# . Uncontrolled PTS Gas Heater emissions were determined using AP-42 emission factors
(0.0075lb/MMBtu) which are equivalent to a pa rticulate concentration of 0.005 gr/dscf.



# 8.3.1 Identification of Potential PM/PM 10 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in

Section 4.0 and Table 9-28. Potential control technologies for particulate emissions are the
following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)

• Good Design Methods and Operating Practices

• Clean Fuels



# 8.3.2 Elimination of Tech nically Infeas ible PM/PM 10 

# Control Options

Table 8-1 summarizes the technical feasibility of e ach particulate control technology on the DRI
Boilers. At particulat e concentrations of 0.005 gr/dscf, us e of add-on controls for gas fired
combustion sources is technically in feasible because this particulate concentration level is at the

limits of PM emissi ons control technology. In addition, part iculates from natura l gas combustion are
primarily condensable particulat es. Condensable PM is not re adily removed by these control

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# devices. The particulate concentration of 0. 005 gr/dscf was calculated using the AP-42, 5 th 

# edition
emission factor for natural gas combustion and the EPA Method 19 “F” factor for flue gas volumes
generated by natural gas combustion. The F factor flow rate was ad justed to 3% oxygen in the flue
gas; this is typical of boiler and process heater operations.

Table 8-1 Technical Feasibility of PM/PM 10 

## Control Technologies for the DRI Boilers

Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Fabric Filter (Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. No

Wet Scrubber Wet scrubbers, remove part icles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. No

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. No

Centrifugal Separation (e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. No

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. No

Good Design Methods and Operating Practices Clean Fuels Well designed and operated burners reduce the amount of particulate matter formed as a result of incomplete combustion Yes

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# 8.3.3 Rank Remaining PM/PM 10 

# Control Technologies by Control Effectiveness
The only remaining control technology for contro l of PM emission from the DRI boilers is good
burner design and op erating practices.

Table 8-2 Ranking of Remaining PM/PM 10 

## Control Technologies for DRI Boilers

PM / PM 10 

## Control Technology Ranking
Rank Technology % Efficiency

1 Good Burner Design and Operating Practices Clean Fuels NA Base Case



# 8.3.4 Evaluation of Most Effe ctive PM Contro l Technologies
Since good burner design and operating practices is i nherent to the process no additional cost will be

incurred.

Table 8-3 Evaluation of Most Effective PM/PM 10 

## Control Technologies for the DRI Boilers

Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices Clean Fuels NA Inherent Controls NA Inherent Controls NA NA



# 8.3.5 DRI Boiler PM/PM 10 

# BACT Selection

Good Burner Design and Operati ng Practices and clean fuels are selected as BACT.

The proposed BACT PM/PM 10 

# limit for the DRI boilers is 0.0075 lb PM/PM 10 

# /MMBtu, good
combustion practices and use of natural gas. Use of natural gas, a clean fuel, limits potential
emissions of particulat es. The proposed PM/PM 10 

# mass emission limit is 0.7 lbs of PM/PM 10 

# per hour on a 24 hour average basis. The proposed lim it is based on compliance testing for PM by EPA

Method 5, and PM 10 

# measured by EPA Methods 201 (or 201 A) and 202 (or EPA approved modified
Method 202 procedures). The mass emission limit is based on operati on with BACT controls and the
facility running at full capacity.

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# Attachment L, Tables L-38A and 38B c ontain a summaries of BACT PM and PM 10 

# determinations
from the EPA RBLC database for natural gas-fired boi lers and heaters rated at 100 MMBtu/hr or less.
Statistical analyses of the RBLC data are summarized in the tables and bar charts below. The
proposed BACT particulate limit of 0.0075 lb PM/PM 10 

# /MMBtu is consistent with AP-42 and less

than the median BACT PM/PM 10 

# limits listed below. Controls listed in the RBLC for this source are
use of natural gas and good combustion practices. Therefore, specifying good combustion controls

with a limit of 0.0075 lb/MMBtu as BACT is cons istent with recent RBLC BACT determinations.

RBLC PM 10 

## BACT Limits Summary

BACT-PSD PM 10 

## lb/MMBtu Emission Limits Other (non-BACT) PM 10 

## lb/MMBtu Emission Limits

MIN 0.0019 lb/MMBtu MIN 0.007 lb/MMBtu MAX 0.6 lb/MMBtu MAX 0.4 lb/MMBtu MEDIAN 0.0085 lb/MMBtu MEDIAN 0.008 lb/MMBtu
COUNT 59 CASES COUNT 11 CASES



# RBLC PM10 BACT Limits
Small Gas Fired Heaters & Boilers

0 5 10 15 20 25

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1
BACT PM10 Limits lb/MMBtuCount 

### Propsed BACT
Limit 0.0075



## RBLC PM BACT Limits Summary
BACT-PSD PM lb/MMBtu Emission Limits Other (non-BACT) PM lb/MMBtu Emission Limits

MIN 0.005 lb/MMBtu MIN 0.007 lb/MMBtu MAX 5 lb/MMBtu MAX 0.014 lb/MMBtu MEDIAN 0.010 lb/MMBtu MEDIAN 0.00715 lb/MMBtu
COUNT 29 CASES COUNT 10 CASES

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# RBLC PM BACT Limits
Small Gas Fired Heaters & Boilers

0 2 4 6 8 10 12 14

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1 

# PM lb/MMBtuCount 

### Propsed BACT
Limit 0.0075



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the boiler into service, and will continue this practice until the process is shut down and off line.
Therefore, Minnesota Steel is not proposing any sp ecial permit conditions for startup and shutdown.



# 8.4 DRI Package Boiler Visible Emissions

Visible emissions are the result of incomplete co mbustion of fuels in the DRI Package Boilers.



# 8.4.1 DRI Package Boiler Visi ble Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

In the DRI Package Boilers, PM/PM 10 

# emissions are controlled by good combustion practices.

A 3% opacity limit is recommended as BACT for visible emissions from the DRI Package Boilers. i.e.
the average opacity of a boiler cannot exceed 3% for more the one 6-minute period during an hour. If

Minnesota Steel identifies visible emissions from a DRI Package Boiler of 3%, it will take corrective
action as soon as it is practicable to do so. An opac ity limit of 3% is consistent with recent RBLC
determinations for gas fired heaters as shown in the table below.

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## Small Natural Gas Boiler RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 10 % Opacity MIN 5 % Opacity MAX 20 % Opacity MAX 40 % Opacity MEDIAN 20 % Opacity MEDIAN 20 % Opacity
COUNT 14 CASES COUNT 13 CASES



# See Attachment L, Table L-46 for a detailed listing of recent RBLC opacity determinations for small
natural gas fired heaters and boilers.



# 8.5 DRI Boiler Su lfur Dioxide (SO 2 

# ) emission

SO 2 

# emissions from natural gas combustion are typicall y low. Based on use of natural gas as the fuel
for the DRI boilers, the expected SO 2 

# concentration in the boiler flue gas is expected to be 1 ppm

SO 2


# .



# 8.5.1 Identification of Potential SO 2 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various SO 2 

# control technologies are discussed in

Section 4.0 and Table 9-31. Pote ntial control technologies for SO 2 

# emissions are the following:

• Wet Scrubber

• Spray Dryer Absorption

• Wet Electrostatic Precipitator

• Dry Sorbent Injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design Methods and Operating Practices



# 8.5.2 Elimination of Te chnically Infeasible SO 2 

# Control Options

At less than 1 ppm SO 2 

# in the DRI boiler exhaust, all add-on controls are technically infeasible
because 1 ppm is at or below the exhaust concentr ations that can be achieved with these controls.

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## Table 8-4 Technical Feasibility of SO 2 

## Control Technologies for the DRI Boilers

SO2 Emission Control Technology Feasibility Analysis

Technology Description Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with SO2 and removes it. No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for SO2 removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For SO2 removal, caustic is added to the water spray system, allowing the spray system to function as an SO2 absorber. No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with SO2 and removes it. A fabric filter is used to collect the spent sorbent. No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. SO2 reacts with sorbent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology No

Clean Fuel/ Good Combustion Practices (Base Case) Combust natural gas Yes



# 8.5.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness
The remaining control technology for control of SO 2 

# from the DRI boilers is the use of clean fuel and
good combustion practices.

Table 8-5 Ranking of Remaining SO 2 

## Control Technologies for the DRI Boilers

SO2 Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the process

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# 8.5.4 Evaluation of Most Effective SO 2 

# Control Technologies

Since the use of clean fuel and good combustion prac tices is an inherent part of the process no

additional cost will be incurred.

Table 8-6 Evaluation of Most Effective SO 2 

## Control Technologies for the DRI Boilers
Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the
process NA Inherent to the process NA NA



# 8.5.5 DRI Boiler SO 2 

# BACT Selection
Use of clean fuels (natural gas) and good combustion practices are selected as BACT for the DRI
boilers. Use of natural gas, a clean fuel, limits potential SO 2 

# emissions to the rated heat input
capacity of the boilers.

Minnesota Steel Industries proposed SO 2 

# mass emission limit is 0.1 lbs of SO 2 

# per hour on a 3 hour
average basis. The proposed limit is based on compliance testing for SO 2 

# by EPA Method 6C,

determination of SO 2 

# by instrumental methods. The mass emission limit is base d on operation with
BACT controls and the facility running at full capacity.

Attachment L, Table L-39 contains a summary of BACT SO 2 

# determinations from the EPA RBLC
database for natural gas-fired boile rs and heaters rated at 100 MMBtu/hr or less. Statistical analyses
of the RBLC data are summarized in the tables and bar charts below. The proposed BACT limit of

0.1 lb SO 2 

# /hr is equivalent to 0.0006 lb SO 2 

# /MMBtu, and is consistent with AP-42 and the lowest

BACT SO 2 

# limits listed below. Controls listed in the RBLC for this source are use of natural gas and
good combustion practices. Theref ore, specifying good combustion controls and use of natural gas

with a limit of 0.1 lb SO 2 

# /hr as BACT is consistent with r ecent RBLC BACT determinations.

RBLC SO 2 

# BACT Limits Summary

BACT-PSD SO2 lb/MMBtu Emission Limits Other (non-BACT) SO 2 

## lb/MMBtu Emission Limits

MIN 0.0006 lb/MMBtu MIN 0.0006 lb/MMBtu MAX 1.28 lb/MMBtu MAX 4 lb/MMBtu MEDIAN 0.0025 lb/MMBtu MEDIAN 0.017 lb/MMBtu
COUNT 44 CASES COUNT 14 CASES

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# Since Minnesota Steel will fire only natural gas in the DRI Boilers, no special permit conditions are
required to control SO 2 

# emissions during startup and shutdown.



# 8.6 DRI Boiler Nitrogen Oxides (NO x 

# ) Emissions

Combustion of gaseous fuels, na tural gas and process tail gas, is the primary source of NO
x 

# emissions

from the DRI boilers. NO
x 

# emissions from the DRI boilers are primarily thermal NO
x. 

# Low NO
x 

# Burners (LNB) rated at 0.08 lb NOx/MMBtu are used as the base case in this analysis because they
are inherent in the process design from HYL. LNB are inexpensive and are routinely offered as
standard equipment. A conservatively high emissi on rate of 0.08 lb NOx/ MMBtu was used for the

base case so that the tars removed by other technologies were not artificially low. The AP-42 NO
x 

# emission factor for small boilers is equivalent to 0.05 lb/MMB tu. A burner rating of 0.08 lb

NO
x 

# /MMBtu equates to a NO
x 

# concentration of 60 ppm dry.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 9-34. Pote ntial control technologi es for DRI boilers NO
x 

# emissions are the following:

• Low Temperature Oxidation

• Selective Catalytic Reduction

• Selective Non-Catalytic Reduction

• Non-selective Ca talytic Reduction

• Ultra Low NO
x 

# Burners / Low-NOx Burners and Flue Gas Recirculation (ULNB / LNB-FGR)

• External Flue Gas Recirculation (EFGR)

• Low NOx Burners (Base Case)

• Low Excess Air (LEA)

• Other Combustion Controls



# 8.6.1 Elimination of Te chnically Infeasible NO x 

# Control Options

Table 8-7 summarizes the feasibility of potential NO
x 

# control technologies for emissions from the
DRI boilers. Details regarding the technologies that are infeasible are discussed in the subsequent

sections.

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## Table 8-7 Technical Feasibility of NO x 

## Control Technologies for the DRI Boilers

NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Low Temperature Oxidation Low Temperature Oxidation is a process where NO x 

## is oxidized to form water soluble nitrate compounds which can easily be removed by absorption (wet scrubbing). Oxidation occurs at relatively low temperatures (100oF – 200oF) so it can be effectively used as an add-on control system where the stream to be treated is not hot enough for catalytic controls. Ozone is typically used as the oxidizing agent. Yes (demonstrated in limited applications)

Selective Catalytic Reduction Selective catalytic reduction (SCR) is a postcombustion NO x 

## control technology in which ammonia (NH 3 

## ) is injected into the flue gas stream in the presence of a catalyst. SCR requires a temperature range of 500 ° F – 800 ° F. Yes

Selective Non-Catalytic Reduction The Selective non-catalytic reduction (SNCR) process injects urea or ammonia-based chemicals into the flue gas stream to convert NO to N 2 

## and water. The optimum operating temperature for SNCR is 1,600 ° F to 2,000 ° F. Yes

Non-Selective Catalytic Reduction Non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NO x 

## and CO react in the presence of NSCR catalyst to form nitrogen (N 2 

## ) and carbon dioxide (CO 2 

## ). It is typically employed in clean gas services such as natural gas fired turbines. No

Ultra Low NO x 

## Burners or Low NO x 

## Burners and Flue Gas Recirculation This option is a combination of Low NOx burners and external flue gas recirculation.

The same effect can be accomplished with Induced flue gas recirculation burners. These burners are designed to draw flue gas into the burner to dilute the fuel. This reduces flame temperature and NO x 

## formation. Yes

External Flue Gas Recirculation External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures. In an external flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air and this mixture is introduced into the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x 

## . Yes

Incorporated via the ULNB / LNB-EFR analysis

Low-NOx Burners Low-NO x 

## burner (LNB) technology utilizes advanced burner design to reduce NO x 

## formation through the restriction of oxygen, flame temperature, and/or residence time. Yes (Base Case)

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## NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Low Excess Air (LEA) Low Excess is a combustion control method which is used to reduce the amount of oxygen in the combustion zone of a furnace or boiler. This limits the amount of oxygen available for NO x 

## formation. Yes

Other Combustion Controls These combustion control methods are typically employed on existing sources. They inexpensive, but have limited control efficiencies. Combustion controls incl ude Overfire Air (OFA), Burners Out of Servic e (BOOS) and Load Reduction and Reduced Combustion Air Temperature. No



## • Non-Selective -Catalytic Reduction (NSCR)



# Review of the EPA RACT/BACT/LEAR Clearinghouse, as well as discu ssions with vendors, indicate
that this technology is not used in boiler applicatio ns. In addition, the same level of emission control

can be achieved with SCR or LoTOx.

• Other Combustion Controls


# Overfire air and placing burners out of service are a ppropriate for large industrial and utility boilers.
A 100 MMBtu/hr boiler is not large enough to accommodate over fire air. Smal l boilers us ually have
only one burner; therefore, they do not have spare burners which can be take n out of service. New
boiler designs can meet low NO
x 

# control requirements without the use of air preheat limitations.



# 8.6.2 Ranking of Remaining NO x 

# Control Technologies by Control Effectiveness
The remaining control technologies applicable to th e DRI boilers are ranked by control effectiveness

in Table 9-35

.

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## Table 8-8 Ranking of Remaining NO x 

## Control Technologies for the Tunnel Furnace

NO x 

## Control Technology Ranking

Rank Technology Estimated % Control Efficiency

1 Selective Catalytic Reduction 70 %*

2 LoTOx 70%*

3 Ultra Low NO x 

## Burners or Low-NO x 

## Burners and Flue Gas Recirculation 56%

4 SNCR 25%

NA Low NOx Burners NA

Base Case

5 Low Excess Air (LEA) 1-15% Implement as good operating practices



## * A 70% control efficiency is equivale nt to 18 ppm NOx on a dry basis



# 8.6.3 Evaluation of Most Effective NO x 

# Control Technologies

The detailed control cost analyses are located in Attachment C

Table 8-9 Evaluation of Most Effective NO x 

## Control Technologies for the DRI Boilers

NOx Control Technology Effectiveness Evaluation

Rank Technology Emission Reduction (tpy) Installed Capital Cost Annualized Cost Control Cost ($/ton removed)

1 LoTOx 

## 22.0 $724,544 $619,859 $28,142

1 Selective Catalytic Reduction 

## 22.0 $1,676,449 $449,601 $20,412

2 Ultra Low NO x 

## Burners or Low-NOx Burners and Flue Gas Recirculation Burners 

## 17.7 $429,399 $59,310 $3,351

3 SNCR 

## 7.9 $861,742 $217,176 $27,608

4 Low NOx Burners NA Base Case NA Base Case NA Base Case NA Base Case

5 Low Excess Air (LEA) NA Implement as good operating practices NA Implement

as good operating practices NA NA

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# SCR, LoTOx, and SNCR are all economically infeasible as their control costs are all significantly
above $10,000 per ton NO
x 

# removed.

Ultra Low NO
x 

# Burners or Low NO
x 

# burners with external flue ga s recirculation have the next
highest level of control, and they are economically feasible. Low NOx burners are effective at
controlling NO
x 

# emissions and do not require the use of reagents and catalysts. CO emissions may
increase slightly with the us e of ultra low NOx burners.

An analysis of the RBLC indicates that for gas fired boilers and heaters rated less than or equal to

100 MMBtu/hr, as listed in Attachment L Table L-40A, do not have add-on devices to control NO
x. 

# Instead, ultra low NO
x 

# burners or low NO
x 

# burners with flue gas recirculation have been selected as

BACT for control of NO
x 

# emissions.



# 8.6.4 DRI Boiler NO x 

# BACT Selection

Minnesota Steel proposes ultra low NO
x 

# burners or low NO
x 

# burners with flue gas recirculation, or
equivalent combustion controls as BACT. Minnesota Steel considers the use of ultra low NOx

burners or low NO
x 

# burners with flue gas recirculation to be consistent with recent BACT

determinations as shown in Attachment L, Table L-40A.

Minnesota Steel proposes a BACT NO
x 

# emission limit of 0.035 lb NO
x 

# /MMBtu on a 24 hour average
basis for the DRI boilers. The proposed NO
x 

# mass emission limit is 3.5 lbs of NO
x 

# per hour on a 24
hour average basis. The proposed lim it is based on compliance testing for NO
x 

# by EPA Method 7E,

determination of NO
x 

# by instrumental methods. The mass emission limit is base d on operation with
BACT controls and the facility running at full capacity.

Attachment L, Table L-40A contains a summary of BACT determinations from the EPA RBLC
database for the natural gas-fired boilers and heater rated at 100 MMB tu/hr or less. The RBLC data

indicates that ultra low NO
x 

# burners or low NO
x 

# burners with flue gas recirculation have been

selected as BACT for control of NO
x 

# emissions from gas fired boilers and heaters. Statistical
analyses of the RBLC data are summarized in the table below. The proposed BACT limit of 0.035 lb

NO
x 

# /MMBtu is below the median RBLC BACT limit. Therefore, specifying ultra low NOx burners
with flue gas recirculation as BACT is consistent with recent RBLC BACT determinations.

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# RBLC NO x 

# BACT Limits Summary

BACT-PSD NO x 

# lb/MMBtu Emission Limits Other (non-BACT) NO x 

# lb/MMBtu Emission Limits

MIN 0.0085 lb/MMBtu MIN 0.0085 lb/MMBtu MAX 5.5 lb/MMBtu MAX 0.23 lb/MMBtu MEDIAN 0.050 lb/MMBtu MEDIAN 0.036 lb/MMBtu
COUNT 97 CASES COUNT 35 CASES



# RBLC NOx BACT Limits Small Gas Fired Heaters & Boilers

0 5 10 15 20 25 30 35

0 .

0

1 0.02 0.03 0.04 0 . 0

5 0 . 0

6 0.07 0.08 0 . 0

9 0 . 1 0 . 2 0. 3 0. 4
> 0.4



# lb NOx/MMBtuCount 

### Proposed
BACT Limit
0.035



# Periods of startup, sh utdown and malfunction

For ULNB to effectively control NO
x 

# emissions, the DRI Boilers must be at sufficient load for
effective flue gas induction into the ULNB and fo r combustion controls to maintain low levels of
excess combustion air. Once the process heater has reached the appropriate operating conditions; the

ULNB will be able to control NO
x 

# emissions as intended. Until the process heater reaches the proper
operating conditions Minnesota Steel cannot comply with the BACT limits for normal operation.
Therefore, Minnesota Steel proposes to follow “Goo d Air Pollution Control Practices for Minimizing
Emissions” and to limit emissions to the rates Attachment M, Table 1 as BACT during startup and
shutdown. Good operating practices will include:

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## • 

# Operation of the DRI Boilers in a manner which minimizes the amount of time the heater is
operated at temperatures and firing rates which are outside the operating range effective NO
x 

# control by ULNB.

• 

# Operation of the DRI Boilers in a manner which minimizes the amount of time the heater is
operated at excess oxygen le vels higher than the operating range effective for NO
x 

# control by

ULNB.

Minnesota Steel will define these periods in its star tup, shutdown and malfunction plan. As noted in
Section 4.8, plans for startup, shutdown and malfunction will follow all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.



# 8.7 DRI Boiler Carbon Mo noxide (CO) Emissions

CO emissions from the DRI boilers are the result of incomplete natural gas combustion. Based on

AP-42 emission factors, the estimated CO concentr ation in the exhaust of the DRI boilers is 0.08
lb/MMBtu. This equates to a CO concentration of 111 ppm, which is consis tent with good operation

of low NO
x 

# burners.



# 8.7.1 Identification of Potent ial CO Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various CO control technologies ar e discussed in Section

4.0 and Table 9-52. Potential control tec hnologies for CO emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Good Burner Design and Operating Practices



# 8.7.2 Elimination of Technically Infeasible CO Co ntrol Options

Table 9-37 summarizes the feasibility of potential control technologies for CO emissions from the

DRI boilers.

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## Table 8-10 Technical Feasibility of CO Control Technologies for the DRI Boilers
CO Emission Control Technologie s Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize CO to CO 2


## . This may be accomplished using an add on oxidizer or a duct burner. Yes

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of CO at lower temperatures than a thermal incinerator. Yes

Good Combustion Controls Good combustion control limits the formation of CO by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of CO formed as a result of incomplete combustion. 

## Yes



# 8.7.3 Ranking of Remaining CO Control Technologies by Control Effectiveness

Table 8-11 Ranking of Remaining CO Technologies for the DRI Boilers

CO Control Technology Ranking

Rank Technology % Efficiency

1 

## Thermal Oxidizer (Recuperative and Regenerative) 90% *

1 

## Catalytic Oxidizer 90% *

2 

## Good Combustion Controls NA

Base Case

2 Good Burner Design and Operating Practices NA

Base Case



## * A 90% control efficiency is equivalent to 10 ppm CO on a dry basis

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# 8.7.4 Evaluation of Most Effe ctive CO Contro l Technologies
The detailed control cost analyses are located in Attachment C.

Table 8-12 Evaluation of Most Effective CO Control Technologies for the DRI Boilers

Control Technology Effectiveness Evaluation

Rank Technology 

## Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton
1 Thermal Oxidizer Recuperative 

## 29.5 $622,596 $803,420 $27,228

1 Thermal Oxidizer Regenerative 

## 29.5 $801,987 $567,104 $19,219

1 Catalytic Oxidizer 

## 29.5 $764,279 $459,942 $15,588

2 

## Good Combustion Controls NA Inherent Controls NA Inherent Controls NA NA

2 Good Burner Design and Operating Practices NA Inherent Controls NA Inherent Controls NA NA



# Thermal and catalytic oxidation c ontrol costs are well over $10,000 per ton, and are economically

infeasible.

Since the use of good combustion controls and good burner design and op erating practices are
inherent parts of the process no a dditional cost will be incurred.



# 8.7.5 DRI Boiler CO BACT Selection

Good Combustion Practices and Good Burner Design and Operating Practices are selected as BACT

for CO control in the DRI boilers. Use of natu ral gas, a clean fuel, in combination with good
combustion practices limits potential CO emissions from the boilers.

Minnesota Steel proposes a BACT CO emission limit of 0.08 lb CO/MMBtu for the DRI boilers.
The proposed CO mass emission limit is 8.2 lbs of CO per hour on a 1 hour average basis. The
proposed limit is based on complian ce testing for CO by EPA Method 10. The mass emission limit is
based on operation with BACT controls and the facility running at full capacity.

Attachment L, Table L-41 contains a summary of BACT determinations from the EPA RBLC
database for natural gas-fired boi lers and heaters rated at 100 MMBt u/hr or less. The RBLC data

indicates Good Combustion Practices and use of natura l gas as BACT for CO control. As noted in
the NOx control analysis, CO emissions from low a nd ultra low NOx burners are slightly higher than

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# standard burners. Data in Table L-41 shows CO emissions fro m low and ultra low NOx burners in
the 0.08 to 0.1 lb CO/MMBtu range. Therefore, specifying good combustion c ontrols as BACT with

a limit of 0.08 lb CO/MMBtu for ultra low NOx burners is cons istent with recent RBLC BACT

determinations. This limit is also consistent with the median or recent determinations. Statistical
analyses of the RBLC data are summarized in the table and bar graph below.

RBLC CO BACT Limits Summary BACT-PSD CO lb/MMBtu Emission Limits Other (non-BACT) CO lb/MMBtu Emission Li it MIN 0.022 lb/MMBtu MIN 0.011 lb/MMBtu MAX 4.3 lb/MMBtu MAX 0.7 lb/MMBtu MEDIAN 0.082 lb/MMBtu MEDIAN 0.08 lb/MMBtu
COUNT 81 CASES COUNT 30 CASES

RBLC CO BACT Limits Small Gas Fired Heaters & Boilers

0 5 10 15 20 25 30

0.02 0.04 0.06 0.08 0.1 0.2 0.4 0.6 0.8 1 > 1

BACT limit lb CO/MMBtuCount Proposed BACT
Limit 0.08



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the boilers into service, and will continue this practice until the process is shut down and off line.
Therefore, Minnesota Steel is not proposing any sp ecial permit conditions for startup and shutdown.



# 8.8 DRI Boiler Volatile Orga nic compound (VOC) Emissions

VOC emissions from the DRI boilers are the result of incomplete natural gas combustion. Based on

AP-42 information, the calculated VOC emissions in the uncontrolled flue gases of the DRI boilers
are 0.0054 lb/MMBTU. This equates to a VOC concentration of 13 ppm.

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# 8.8.1 Identification of Potent ial VOC Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous VOC control technologi es are discussed in

Section 4.0 and Table 9-40. Potential control t echnologies for VOC emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Good Burner Design and Operating Practices



# 8.8.2 Elimination of Technically Infeasible VOC Control Options

Table 9-40 summarizes the feasibility of potential c ontrol technologies for control of VOC emissions
from the DRI boilers. At 13 ppm VOC in the DRI boil er exhaust, all add-on controls are technically

infeasible because this level is at or below the exhaust concentrations that can be achieved with

theses controls.

Table 8-13 Technical Feasibility of VOC Control Technologies for the DRI Boilers
VOC Emission Control Technologies Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize VOC to water and CO 2 

## . This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of VOC at lower temperatures than a thermal incinerator. No

Good Combustion Controls Good combustion control limits the formation of VOCs by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of particulate matter formed as a result of incomplete combustion. 

## Yes

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# Thermal and catalytic oxidation c ontrol devices are considered te chnically infeasible in this
application due to the low concentrations of VOC in the boiler exhaust. At 13 ppm VOC, boiler

exhaust VOC concentrations are at or below the level of control achievable by add on oxidation
controls. In addition, control cost calculations show that both thermal and catalytic oxidizers are
economically infeasible. Se e Attachment C Table C-1.



# 8.8.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness

The only remaining VOC control technologies are good combustion practices and good burner design
and operating practices.

Table 8-14 Ranking of Remaining VOC Control Technologies for the DRI Boilers

VOC Control Technology Ranking

Rank Technology % Efficiency

1 Good Burner Design and Operating Practices NA

Base Case



# 8.8.4 Evaluation of Most Effe ctive VOC Control Technologies

Since the use of good combustion controls and good burner design and op erating practices are
inherent parts of the process no addi tional cost will be incurred.

Table 8-15 Evaluation of Most Effective VO C Control Technologies for the DRI Boilers

Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# 8.8.5 DRI Boiler VOC BACT Selection

Good Combustion Practices and Good Burner Design and Operating Practices are selected as BACT

for VOC control in the DRI boilers. Use of natu ral gas, a clean fuel, in combination with good
combustion practices li mits potential VOC emissions from the boilers.

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# Minnesota Steel proposes a BACT VOC emission limit of 0.006 lb VO C/MMBtu for the DRI boilers.
The proposed VOC mass emission limit is 0.5 lbs of VOC per hour on a 24 hour average basis. The
proposed limit is based on compliance testing for VOC by EPA Method 25A and/or Method 18 for

determination of methane, ethane and individual VOC compounds. Th e mass emission limit is based
on operation with BACT controls and the fa cility running at full capacity.

Attachment L, Table L-42 contains a summary of BACT determinations from the EPA RBLC
database for natural gas-fired boi lers and heaters rated at 100 MMBt u/hr or less. The RBLC data

indicates Good Combustion Practices and use of natu ral gas as BACT for VOC control. The median

BACT limit for VOCs in Table L-42 is 0.006 lb VOC/MMBtu. Therefore, specifying good

combustion controls as BACT with a limit of 0.006 lb VOC/MMBtu is consistent with recent RBLC

BACT determinations.

RBLC VOC BACT Limits Summary BACT-PSD VOC lb/MMBtu Emission Limits Other (non-BACT) VOC lb/MMBtu Emission Limits

MIN 0.002 lb/MMBtu MIN 0.004 lb/MMBtu MAX 1.0 lb/MMBtu MAX 0.08 lb/MMBtu MEDIAN 0.006 lb/MMBtu MEDIAN 0.005 lb/MMBtu
COUNT 35 CASES COUNT 3 CASES



# RBLC VOC BACT limits
Small Gas Fired Heaters & Boilers



# 0 2 4 6 8 10 12 14 16

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1

VOC lb/MMBtuCount 

### Proposed BACT
Limit 0.006

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# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the boilers into service, and will continue this practice until the process is shut down and off line.
Therefore, Minnesota Steel is not proposing any sp ecial permit conditions for startup and shutdown.



# 8.9 DRI Process Heaters

The DRI Process Heater is used heat DRI top gas fo r injection into the DRI reactor as described in
Section 8.1. There will be one process heater for each DRI line. Each DRI Process Heater is rated at

605.7 MMBtu/hr. The DRI Process Heaters will us e natural gas and off gas from the Pneumatic
Transport System (PTS) and the external pellet coolers as fuel. Air pollutants emitted from the DRI

Process heaters include: PM, PM10, SO 2 

# , NO
x 

# , CO, VOC. Emissions are primarily the result of gas
combustion. Trace amounts of fluorides and lead are emitted. These emissions are in particulates
which were not captured in the PTS and external cooler gas scrubbing systems as discussed in

Section 8.1.



# 8.10 DRI Process Heater Pa rticulate Matter (PM/PM 10 

# ) Emissions

8.10.1 Identification of Potential PM/PM 10 

# Control Technologies

The DRI vendor’s value for particulat es emitted in the process heater’s exhaust gas is 0.01 gr/dscf.
Based on the duty and design stack flow of pr ocess heaters, this equates to 0.015 lb

PM/PM 10 

# /MMBtu. Add-on controls will be evaluated using this as the control device inlet
concentration basis. At these low levels of part iculate loading, add-on c ontrols are typically not
economically feasible.

The DRI Process Heater e xhaust gas also contains a small about of condensable particulate matter.
The condensable particulates are primarily products of incomplete combustion.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in

Section 4.0, and Table 8-16. Pote ntial control technologies for DRI Process Heater particulate
emissions are the following:

• Fabric filter

• Wet scrubber

• Electrostatic precipitator

• Wet Electrostatic Precipitator

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# • Centrifugal Separation (e.g. Cyclones)

• Inertial separators (drop out box)

• Good design methods and operating practices



# 8.10.2 Elimination of Tech nically Infeas ible PM/PM 10 

# Control Options

Table 8-16 lists the partic ulate control technologies and their fe asibility for control emissions from

the DRI Process Heaters.

Use of add on control devices is not feasible in this application due to the low concentrations of
particulate matter in the process heater exhaust gas. The concentration of particulates in the DRI
Process Heater exhaust gas (0.01gr/dscf) is at or below the removal capabilities of these control
devices when applied to gas fired combustion so urces whose exhaust is composed primarily of
condensable particulate ma tter. Condensable PM is not readily removed by these control devices.

Fabric filters and wet scrubbers are also infeasib le in this application due to low particulate
concentrations in the DRI process heater exhaust.

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## Table 8-16 Technical Feasibility of PM C ontrol Technologies for DRI Process Heaters

Summary of PM/PM10 Control Technology Feasibility
Technology Description Feasible? Yes or No

Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. No

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. No

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. No

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. No

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. No

Good Design Methods and Operating Practices DRI plant internal top gas wet scrubbing system and natural gas combustion.

Good combustion practices in the DRI Process Heaters Yes

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# 8.10.3 Ranking of Remaining PM/PM 10 

# Control Technologies by Control Effectiveness
As noted above, the DRI process heater exhaust gas specifications are 0.01 gr/dscf of particulate
matter. At this level, the control efficiency of any add-on control device is limited. A control cost
analysis was conducted on fabric filtration and wet scrubbing as an example of how this affects the
economic feasibility of these devices. Table 8-17 summarizes the estimated control efficiencies for

fabric filtration and wet sc rubbing control technologies.

Table 8-17 Remaining PM/PM 10 

## Control Technologies and Control Effectiveness for the DRI Process Heaters

PM / PM 10 

## Control Technology Ranking

Rank Technology % Efficiency

1 Fabric Filter
(Baghouse) 50%

1 Wet Scrubber 50%

2 Good Design Methods and Operating Practices

Good combustion practices in the DRI

Process Heaters Inherent to the DRI
process design



# A PM control efficiency of 50% is based on reducing PM from 0.01 gr/dscf to 0.005 gr/dscf



# 8.10.4 Evaluation of Most Effective Control Technologies

Table 8-18 summarizes the estimated emission reductio ns, capital and annual operating costs, and the
corresponding cost per ton of part iculate matter removed from the DRI Process Heaters if pollution

controls were installed. The cost for controls is economically infeasible at over $45,000 per ton
removed. The detailed control cost analyses are located in Attachment D.

Table 8-18 Evaluation of Most Effective PM/PM 10 

## Control Technologies for the DRI Process Heaters

Control Technology Effectiveness Evaluation



## Control Technology Outlet Concentration Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Wet Scrubber 0.01 gr/dscf* 

## 17.4 $1,551,775 $777,333 $44,695

Baghouse 0.01gr/dscf* 

## 17.4 $6,913,747 $1,393,567 $80,128 *PM as measured by EPA Methods 201 or 201A and 20 2 or EPA approved modified Method 202 procedures

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# 8.10.5 DRI Process Heater PM/PM 10 

# BACT Selection

Use of inherent controls, clean fuels and good co mbustion practices are r ecommended as BACT for
particulate control from the DRI plant exhaust stack . As discussed in Section 8.1, the DRI process
design includes a scrubber on the top gas as an inhe rent part of the process. At over $45,000 per ton
of PM removed, add-on controls following the internal particulate sc rubber are economically

infeasible.

The proposed BACT PM/PM 10 

# limit for the DRI Process Heaters is 0.015 lb PM/PM 10 

# /MMBtu, good
combustion practices and use of natural gas and process tail gas. Use of natural gas, a clean fuel,
limits potential emissions of particulates. Tail g as is derived from natural gas, and is scrubbed prior
to combustion to prevent DRI particulat es from being emitted. The proposed PM/PM 10 

# mass emission

limit is 8.8 lbs of PM/PM 10 

# per hour on a 24 hour average basis. The proposed limit is based on
compliance testing for PM by EPA Method 5, and PM 10 

# measured by EPA Methods 201 (or 201A)
and 202 (or EPA approved modified Method 202 proce dures). The mass emission limit is based on
operation with BACT controls and the facility running at full capacity.

Attachment L, Table L-2 contains a summary of BACT determinations for DRI operations from the
EPA RBLC database. The RBLC contains three BACT PM limits for the DRI process. All

determinations are consistent with the DRI vendor’s specifications (0.01 gr/dscf) for the exhaust gas

from the DRI Process Heaters.

The tail gas fuel for the DRI Process Heaters is treated by the same type of scrubbers used for
material handing sources in the DRI plant. Th erefore, Minnesota Steel Industries is proposing a
particulate BACT limit for the DRI Process Heaters which is the sum of the BACT limit for

combustion sources and the BACT li mit for material handling sources. i.e. the total of particulates
from combustion and material handling. The DRI pl ant specifications for non – combustion sources
is 0.005 gr/dscf, and is consistent with Minnesota Steel industries proposed BACT limits for material
handling sources, Section 11.0. A PM/PM 10 

# concentration of 0.005 gr/dscf is equivalent to an

emission rate 0.0075 lb PM/PM 10 

# /MMBtu in the DRI process heater exhaust. The proposed BACT
for particulates emitted from the DRI Bo ilers and PTS heaters is 0.0075 lb PM/PM 10 

# /MMBtu. The
proposed PM/PM10 BACT for DRI Pr ocess Heaters is 0.015 lb PM/PM 10 

# /MMBtu, the sum of these

two limits.

For periods of startup and shutdown, Minnesota Steel will operate plant’s inhe rent particulate emission
control equipment. These controls are an integral part of the DRI process, they are used to protect process

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# equipment and the DRI plant cannot operate without them. So, they will be put into service when
commencing operation of process equipment, and will k eep operating until the process is shut down. No
excess emissions will occur as a result of control equi pment startup/shutdown. Therefore, Minnesota
Steel is not proposing any special permit conditions for startup and shutdown.



# 8.11 DRI Process Heater Visible Emissions

Visible emissions are the result of incomplete co mbustion of fuels in the DRI Process Heaters.



# 8.11.1 DRI Process Heater Visi ble Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

In the DRI Process Heaters, PM/PM 10 

# emissions are controlled by good combustion practices.

A 3% opacity limit is recommended as BACT for visibl e emissions from the DRI Process Heaters. i.e. the
average opacity of a process heater cannot exceed 3% for more the one 6-minute period during an hour. If

Minnesota Steel identifies visible emissions from a DRI Process Heater of 3%, it will take corrective
action as soon as it is practicable to do so. An opac ity limit of 3% is consistent with recent RBLC
determinations for gas fired heaters as shown in the table below.

Small Natural Gas Boiler RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 10 % Opacity MIN 5 % Opacity MAX 20 % Opacity MAX 40 % Opacity MEDIAN 20 % Opacity MEDIAN 20 % Opacity
COUNT 14 CASES COUNT 13 CASES



# See Attachment L, Table L-46 for a detailed listing of recent RBLC opacity determinations for small
natural gas fired heaters and boilers.



# 8.12 DRI Process Heater Sulfur Dioxide (SO 2 

# ) Emissions

8.12.1 Identificati on of Potential SO 2 

# Control Technologies

The evaluation of add-on controls is based on ve ndor data citing a process heater exhaust SO 2 

# concentration of 1 ppm SO 2 

# on a wet basis. This is also consistent with SO 2 

# emissions for
combustion of natural gas. As noted in the DRI process description above, the process heaters will
be fired on natural gas or tail gas wh ich is derived from natural gas.

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# Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 8-19. Potentia l control technologies fo r DRI Process Heater SO 2 

# emissions are the
following:

• Wet Scrubber

• Wet Electrostatic Precipitator

• Spray Dryer Absorption

• Dry Sorbent Injection

• Clean Fuel / Good Combusti on Practices (Base Case)



# 8.12.2 Elimination of Te chnically Infeasible SO 2 

# Control Options

At 1 ppm SO 2 

# in the DRI Process Heater exhaust gas, all add-on controls are technically infeasible
because 1 ppm is at or below the exhaust concentrat ions that can be achieved with theses controls.

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## Table 8-19 Technical Feasibility of SO 2 

## Control Technologies for DRI Process Heaters

SO 2 

## Emission Control Technol ogy Feasibility Analysis
Technology Description Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with SO 2 

## and removes it. No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for SO 2 

## removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For SO 2 

## removal, caustic is added to the water spray system, allowing the spray system to function as an SO 2 

## absorber. No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with SO 2 

## and removes it. A fabric filter is used to collect the spent sorbent. No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. SO 2 

## reacts with sorb ent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology No

Clean Fuel/ Good Combustion Practices (Base Case) Combust either purified tail gas or natural gas Yes



# 8.12.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness
Since all add on control options for SO 2 

# control are technically infeasible cost are not presented. The
remaining control option is the use of clean fuel and good combustion practices.

Table 8-20 Remaining SO 2 

## Control Technologies and Control Effectiveness for the DRI Process Heaters

SO2 Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the process

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# 8.12.4 Evaluation of Most E ffective DRI Process Heater SO 2 

# Control Technologies

There are no additional costs asso ciated with the use of clean fuels and good combustion practices
since this is an inherent approach for the Minnesota Steel project.

Table 8-21 Evaluation of Most Effective SO 2 

## Control Technologies for the DRI Process Heaters
Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the
process NA Inherent to the process NA NA



# 8.12.5 DRI Process Heater SO 2 

# BACT Selection

Use of clean fuels (natural gas) and good combustion practices are selected as BACT for the DRI
Process Heaters. Use of natural gas and purified tail gas, both clean fuels, limits potential SO 2


# emissions to the rated heat input capacity of the Proces s Heaters.

The proposed SO 2 

# mass emission limit is 1 lb of SO 2 

# per hour on a 3 hour average basis. The
proposed limit is based on compliance testing for SO 2 

# by EPA Method 6C, determination of SO 2 

# by

instrumental methods. The mass emission limit is based on operation with BACT controls and the
facility running at full capacity.

Attachment L, Table L-2 contains a summary of BACT determinations for DRI operations from the

EPA RBLC database. The RBLC contained only one DRI process SO 2 

# BACT limit. The BACT

determination was for combustion of residual fuel oi l, and is not applicable because Minnesota Steel
will use natural gas and top gas for fuel.

Attachment L, Table L-39 contains a summary of BACT SO 2 

# determinations from the EPA RBLC
database for natural gas-fired boile rs and heaters rated at 100 MMBtu/hr or less. Statistical analyses
of the RBLC data are summarized in the tables and bar charts below. The proposed BACT limit of

1 lb SO 2 

# /hr is equivalent to 0.0006 lb SO 2 

# /MMBtu, and is cons istent with AP-42 for natural gas
combustion, vendor’s specificat ions and the lowest BACT SO 2 

# limits listed below. Controls listed in

the RBLC for this source are use of natural gas and good combustion practices. Therefore,
specifying good combustion controls, us e of clean fuels and a mass em ission limit 1 lb SO2/hr is

consistent with recent RBLC BACT determinations.

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# RBLC SO2 BACT Limits Summary BACT-PSD SO2 lb/MMBtu Emission Limits Other (non-BACT) SO2 lb/MMBtu Emission Limits



## MIN 0.0006 lb/MMBtu MIN 0.0006 lb/MMBtu MAX 1.28 lb/MMBtu MAX 4 lb/MMBtu MEDIAN 0.0025 lb/MMBtu MEDIAN 0.017 lb/MMBtu
COUNT 44 CASES COUNT 14 CASES



# Since Minnesota Steel will use natural gas and/or to p gas at all times the DRI plant is operating, no
special permit conditions are required to control SO 2 

# emissions during startup and shutdown.



# 8.13 DRI Process Heater Nitroge n Oxides (NOx) Emissions

8.13.1 Identification of Potent ial NOx Control Technologies

Combustion of gaseous fuels, process tail gas and na tural gas, is the primar y source of emissions

from the DRI Process Heater exhaust. NO
x 

# emissions from the DRI Process Heaters are primarily

thermal NO
x. 

# The tail gas from the PTS and external pellet cooler contains negligible amounts of fuel
bound nitrogen as it is derived from natural gas. Based on vendor design data, NO
x 

# concentrations in
the DRI Process Heater exhaust gas are estima ted to be 66 ppm NOx on a dry basis. Low NO
x 

# Burners (LNB) rated at 0.08 lb NOx/MMBtu are used as the base case in this analysis. LNB are
inexpensive and are routinely offered as standard equipment.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 8-22. Potent ial control technologies for pellet plant NO
x 

# emissions are the following:

• Low Temperature Oxidation

• Selective Catalytic Reduction

• Selective Non-Catalytic Reduction

• Non-selective Ca talytic Reduction

• External Flue Gas Recirculation

• Ultra Low NO
x 

# Burners / Low-NOx Burners and Flue Gas Recirculation (ULNB / LNB-FGR)

• Oxyfuel Burners

• Low Excess Air (LEA)

• Other Combustion Controls

• Inherently Lower Emitti ng DRI Process Designs

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# 8.13.2 Elimination of Technicall y Infeasible NOx Control Options

Table 8-22 summarizes the technical feasibility of each of the potential NO
x 

# control technologies.
Details regarding the technologies that are not technically feasible are discussed in the subsequent

section.

Table 8-22 Technical Feasibility of NO x 

## Control Technologies for the DRI Process Heaters

NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Low Temperature Oxidation (LoTOx) Low Temperature Oxidation is a process where NO x 

## is oxidized to form water soluble nitrate compounds which can easily be removed by absorption (wet scrubbing). Oxidation occurs at relatively low temperatures (100oF – 200oF) so it can be effectively used as an add-on control system where the stream to be treated is not hot enough for catalytic controls. Ozone is typically used as the oxidizing agent. Yes

Selective Catalytic Reduction Selective catalytic reduction (SCR) is a postcombustion NO x 

## control technology in which ammonia (NH 3 

## ) is injected into the flue gas stream in the presence of a catalyst. SCR requires a temperature range of 500 ° F – 800 ° F. Yes

Selective Non-Catalytic Reduction The Selective non-catalytic reduction (SNCR) process injects urea or ammonia-based chemicals into the flue gas stream to convert NO to N 2 

## and water. The optimum operating temperature for SNCR is 1,600 ° F to 2,000 ° F. Yes

Non-Selective Catalytic Reduction Non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NO x 

## and CO react in the presence of NSCR catalyst to form nitrogen (N 2 

## ) and carbon dioxide (CO 2 

## ). It is typically employed in clean gas services such as natural gas fired turbines. No

External Flue Gas Recirculation External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures. In an external flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air and this mixture is introduced into the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x 

## . Yes
Incorporated via the ULNB / LNB-EFR analysis

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## NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Ultra Low NO x 

## Burners or Low-NO x 

## Burners and Flue Gas Recirculation Low-NO x 

## burner (LNB) technology utilizes advanced burner design to reduce NO x 

## formation through the restriction of oxygen, flame temperature, and/or residence time.

Induced flue gas recirculation burners are designed to draw flue gas into the burner to dilute the fuel. This reduces flame temperature and NO x 

## formation. Yes

Low-NOx Burners Low-NO x 

## burner (LNB) technology utilizes advanced burner design to reduce NO x 

## formation through the restriction of oxygen, flame temperature, and/o r residence time. Yes (Base
Case)

Low Excess Air (LEA) Low Excess is a combustion control method which is used to reduce the amount of oxygen in the combustion zone of a furnace or boiler. This limits the amount of oxygen available for NO x 

## formation. Yes

Other Combustion Controls These combustion control methods are typically employed on existing sources. They inexpensive, but have limited control efficiencies. Combustion controls incl ude Overfire Air (OFA), Burners Out of Servic e (BOOS) and Load Reduction and Reduced Combustion Air Temperature. No

Inherently Lower Emitting DRI Process Designs Process designs which have lower NO x 

## emission rates due to process conditions which are favorable to reduced NOx emissions and/or reduced fuel use. Yes



## Non-Selective Catalytic Reduction (NSCR)


# EPA’s New England’s Center for Environmenta l Industry and Technology (CEIT) web site
( http://www.epa.gov/ne/assistance/ ceit_iti/tech_cos/goalline.html ) lists this technology as applicable
only to natural gas fired turbine systems used for electrical generation.

“Limitations: The SCONOxTM catalytic system is applicable to natur al gas-fired combined cycle turbine using water injection. The performance of the system is sensit ive to sulfur in the exhaust and requires periodic regeneration with dilute hydrogen. The system is used to remove CO and NOx. The certification evaluation was performed on data collected from a 43-megawatt turbine.”



# Therefore, this technology is considered infeasib le for application at th e DRI Process Heaters.

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## Other Combustion Controls


# There are other combustion control methods typica lly employed on large existing sources such as
utility boilers. They are inexpensive, but have limited control efficiencies. Other combustion
controls include Overfire Air (OFA), Burners Out of Service (BOOS) and Load Reduction and
Reduced Combustion Air Temperature. These com bustion controls are typi cally applied on utility
boilers which have large fireboxe s. Large fireboxes provide the extra space and residence time

needed for overfire air. Overfire air would be in effective due to the application of low NOx burners.
BOOS and load reduction are not feasible as the DRI Process Heaters must be run a high capacity to
match the production rate of the facility. Air pr eheat is required for energy efficiency.



# 8.13.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness
Four technologies that are techni cally feasible for control of NO
x 

# on the DRI Process Heaters are

ranked in Table 8-23.

Table 8-23 Ranking of Remaining NO x 

## Control Technologies for DRI Process Heaters

NOx Control Technology Ranking

Rank Technology Estimated NOx Control

1 Low Temperature Oxidation 70% *

1 Selective Catalytic Reduction 70% *

3 Ultra Low NO x 

## Burners or Low-NO x 

## Burners and Flue Gas Recirculation 56%

4 Selective Non-Catalytic Reduction 25%

NA Low NOx Burners NA Base Case

NA Inherently Lower Emitting DRI Process Design NA Base Case

5 Low Excess Air (LEA) 1-15%
Implement as good operating practices



## * A 70% control efficiency is equivale nt to 18 ppm NOx on a dry basis

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# 8.13.4 Evaluation of Most Effe ctive NOx Control Technologies

Table 8-24 summarizes the emission reduction, capital and annualized operating cost, and the
corresponding cost per ton of pollutant removed for LoTOx, SCR, ultra low NO
x 

# burners and SNCR.
The detailed control cost analyses are located in Attachment D.

Table 8-24 Evaluation of Most Effective NOx Control Technologies for DRI Process Heaters

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton
LoTOx 

## 70% 134.8 $3,946,254 $1,807,751 $13,415
Selective Catalytic Reduction (SCR) 

## 70% 134.8 $9,445,459 $1,946,130 $14,442

Ultra Low NO x

## Burners or LowNO x 

## Burners and Flue Gas Recirculation 56% 

## 96.3 $883,202 $198,792 $2,065

Selective NonCatalytic Reduction (SNCR) 25% 

## 48.1 $1,854,845 $493,536 $10,255

Low NOx Burners Base Case NA NA NA NA

Inherently Lower

Emitting DRI Process Design Base Case NA NA NA NA

Low Excess Air (LEA) Base Case NA NA NA NA



# LoTOx and SCR NO
x 

# emissions control options are both economically infeas ible at $13,416 and
$14,434 per ton NOx removed.

LoTOx has the advantage of being able to operate at a relatively low temperature. The disadvantages
of LoTOx are that water is needed to operate the LoTOx scrubber and wastewater from the LoTOx

scrubber has to be treated to remove nitrates. A pplication of LoTOx on the pellet plant faces these
same issues however SCR was shown to be less effective than LoTOx at the pellet plant and to have
a higher degree of uncertainty a nd potential issues. LoTOx require s a source of oxygen in order to

make ozone, the NO
x 

# reduction reagent for the LoTOx proces s. Under many circumstances oxygen
can be expensive. In Minnesota Steel’s case, th e facility already intends to produce oxygen for use
in the steel manufacturing process. This reduces the operating costs for LoTOx because the
incremental cost of oxygen productio n will be relatively low compared to its use at a facility that
would not already have oxygen generating capabiliti es on site. No DRI plants listed in the RBLC
have specified LoTOx for NO
x 

# emission control.

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# SCR systems can be designed to achieve the same level of NO
x 

# in the DRI Process Heater exhaust as
LoTOx (25 ppm); therefore, SCR is also a viable NO
x 

# control option. SCR has the advantage of not
requiring water to operate, nor do es it generate wastewater. The disadvantage of SCR is that the
catalyst is expensive, and it must be periodically replaced. The rate of catalyst use is unknown for
the DRI application. Spent catalyst must be disposed of as a solid waste, or if sufficiently

contaminated as a hazardous waste.

Ultra low NO
x 

# burners are an effective cont rol technology which reduces NO
x 

# emissions at an
affordable cost. Low NOx burners do not require the use of reagents and catalysts. CO emissions
may increase slightly with the use of ultra low NOx burners.

There are two commercially availabl e DRI process designs which utilize natural gas as the reductant.
Minnesota Steel has selected the DRI process design base case which has the lowest NO
x 

# emission
rate of the processes evaluated. The HYL design selected has a lower energy demand than the

alternative, and it can accommodate low and ultra low NO
x 

# burners. The other design could not

accommodate low NO
x 

# burners.



# 8.13.5 DRI NOx BACT Selection

Ultra Low NOx Burners (ULNB) are the proposed NO
x 

# emission control technology for BACT at the
DRI Process Heaters. As noted above, Minnesota Steel Industries has selected the DRI process
alternative that has inherently lower NO
x 

# emissions.

Minnesota Steel proposes a BACT NO
x 

# emission limit of 0.04 lb NO
x 

# /MMBtu on a 24 hour average
basis for the DRI Process Heaters. The proposed NO
x 

# mass emission limit is 24 lbs of NO
x 

# per hour
on a 24 hour average basis. The proposed limit is based on compliance testing for NO
x 

# by EPA

Method 7E, determination of NO
x 

# by instrumental methods. Th e mass emission li mit is based on
operation with BACT controls and the facility running at full capacity.

While LoTOx is technically feasible, ULNB is se lected over LoTOx because LoTOx is economically
infeasible and because of LoTOx’s adverse impact on water consumption and wastewater treatment.
The wet scrubbers needed to operate LoTOx would have a 172 gpm make up water requirement. The
wet scrubber on the pellet plant is smaller due to a smaller air flow rate and the make-up water for
the wet scrubber at the pellet plant is only 76 gpm. The water for the we t scrubber on the DRI unit
represents a 3% to 4% increase in water consum ption over the estimated 4,400 gpm –to 6,000 gpm of
water needed to operate the facility per the water balance prepared for the Minnesota Steel

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# Environmental Impact Study (EIS), water appropr iation permit, and NPDES discharge permit. The
increased water consumption is significant given limited water resources in the area. LoTOx
generated wastewater containing nitrates must be treated before being discharged.

ULNB is selected over SCR because SCR is economically infeasible and because SCR does not
provide a significantly lower emission rate vs. a must higher operating cost. SCR is estimated to cost
$9.4 million vs. $883,000 for ULNB. The incremen tal control cost of SCR is $65,974/ton NOx
removed, and SCR only reduces NOx emissi ons a modest 26.5 ton/yr per heater.

Attachment L, Table L-2 contains a summary of BACT determinations for DRI operations from the

EPA RBLC database. The RBLC contained two DRI process NO
x 

# BACT limits. The BACT

determinations were for combustion of residual fu el oil, and are not appl icable because Minnesota
Steel will use natural gas and top gas for fuel. In addition, the facility (Pea Ridge) is shut down and
the DRI plant was never built. So, compliance wi th the proposed BACT limits was never verified.

The suggested BACT NO
x 

# limit of 0.04 lb NO
x 

# /MMBtu and 24 lb/hr NO
x 

# on a 24 hour average basis

for the DRI Process Heaters exhaust is below the median RBLC BACT limit and is consistent with
recent BACT determinations for large gas fired bo ilers and heaters. Attachment L, Table L-40B
contains a summary of BACT determinations from the EPA RBLC database for the natural gas-fired

boilers and heaters rated at 250 MMBtu/hr to 750 MMBtu/hr. Th e RBLC data indicates that ultra

low NO
x 

# burners or low NO
x 

# burners with flue gas recirculation have been selected as BACT for

control of NO
x 

# emissions from large gas fired boilers and heaters. Statistical analyses of the RBLC
data are summarized in the table and graph below. A NOx emission rate of 0.04 lb NOx/MMBtu is
less than the median BACT limit. Higher levels of control would require use of add on controls
which were shown to be economically infeas ible. Therefore, specifying ultra low NO
x 

# burners at

0.04 lb NO
x 

# /MMBtu as BACT is consistent with recent RBLC BACT determinations.

RBLC NO x 

# BACT Limits Summary BACT-PSD NO x 

## lb/MMBtu Emission Limits Other (non-BACT) NO x 

### lb/MMBtu Emission Limits



## MIN 0.0125 lb/MMBtu MIN 0.05 lb/MMBtu MAX 0.2 lb/MMBtu MAX 0.2 lb/MMBtu MEDIAN 0.05 lb/MMBtu MEDIAN 0.07 lb/MMBtu
COUNT 36 CASES COUNT 6 CASES

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# RBLC NOx BACT Limits
Gas Fired Boilers and Heaters 250 - 750 MMBtu/hr

0 2 4 6 8 10 12

0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09 0.1 0.2 0.3 0.4 > 0.4

NOx Lb/MMBtuCount 

### Proposed BACT
Limit 0.04



# Periods of startup, sh utdown and malfunction

For ULNB to effectively control NO
x 

# emissions, the DRI Process Heater must be at sufficient load
for effective flue gas induction into the ULNB and for combustion controls to maintain low levels of
excess combustion air. When the process heater has reached the appropria te operating conditions,

the ULNB will be able to contro l NOx emissions as designed. Until the process heater reaches the
proper operating conditions Minnes ota Steel cannot comply with the BACT limits for normal
operation. Therefore, Minnesota Steel proposes to follow “Good Air Pollution Control Practices for
Minimizing Emissions” and to limit emissions to the rates Atta chment M, Table 1 as BACT during
startup and shutdown. Good opera ting practices will include:

 

# Operation of the DRI Process Heaters in a manne r which minimizes the amount of time each
heater is operated at temperatures and firing rates which are outside the operating range effective

NO
x 

# control by ULNB.

 

# Operation of the DRI Process Heaters in a manne r which minimizes the amount of time each
heater is operated at excess oxygen levels higher than the operating range effective for NO
x 

# control by ULNB.

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# Minnesota Steel will define these periods in its star tup, shutdown and malfunction plan. As noted in
Section 4.8, plans for startup, shutdown and malfunction will follow all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.



# 8.14 DRI Process Heater Carbon Monoxide (CO) Emissions

8.14.1 Identification of Potent ial CO Control Technologies

Combustion of gaseous fuels (process tail gas and na tural gas) is the primary source of emissions
from the DRI Process Heater exhaust. CO emissions are a result of incomplete combustion of PTS
and external pellet cooler tail ga s and/or natural gas. Based on AP -42 emission factors, the estimated

CO concentration in the exhaust of the DRI boile rs is 0.08 lb/MMBtu. This equates to a CO
concentration of 111 ppm.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 8-25. Potent ial control technologies for DRI Process Heater CO emissions are the
following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls



# 8.14.2 Elimination of Technicall y Infeasible CO Control Options

All CO control technologies are co nsidered technically feasible.

Table 8-25 Technical Feasibility of CO Co ntrol Technologies for DRI Process Heaters
CO Emission Control Technologie s Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize CO to CO 2


## . This may be accomplished using an add on oxidizer or a duct burner. Yes

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of CO at lower temperatures than a thermal Yes

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## CO Emission Control Technologie s Considered for BACT Analysis
Technology Description Feasible? Yes or No incinerator.

Good Combustion Controls Good combustion control limits the formation of CO by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes



# 8.14.3 Ranking of Remaining CO Control Technologies by Control Effectiveness

The calculated CO concentration in the DRI Reform ing Heater exhaust gas is 111 ppm CO. This is
very good performance for a low NO
x 

# burner; therefore, add-on controls will have reduced levels of
control efficiency in this application.

Table 8-26 Ranking of Remaining CO Control Technologies for DRI Process Heaters
CO Control Technology

Rank Technology Estimated Control Efficiency

1 Thermal Oxidizer (Recuperative and Regenerative) 90% *

2 Catalytic Oxidizer 90% *

3 Good Combustion Controls NA

* A 90% control efficiency is equivalent to 10 ppm CO on a dry basis



# 8.14.4 Evaluation of Most Effe ctive CO Control Technologies

Table 8-27 summarizes the cost emission reduction, capital and annualized operating cost and the
cost per ton of pollutant removed. Because the pr ocess already inherently c ontrols CO emissions, the
potential for CO emission reductions by add on cont rols is relatively smal l. Based on the economic
analysis, add-on CO controls are economically infeas ible. In addition, add-on controls required
additional energy to operate, and they generate additional pollutants from the combustion of fuels.
The detailed control cost analyses are located in Attachment D.

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## Table 8-27 Evaluation of Most Effective CO Control Technologies for DRI Process Heaters

CO Control Technology Effectiveness Evaluation



## Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Thermal Oxidizer (Recuperative) 70% 

## 178.5 $945,280 $3,892,175 $21,811

Thermal Oxidizer (Regenerative) 70% 

## 178.5 $2,184,749 $2,555,426 $14,320

Catalytic Oxidizer 70% 

## 178.5 $1,701,213 $1,917,871 $10,747

Good Combustion Controls Base Case NA NA NA NA



# Based on the cost analysis, thermal and catalytic oxidation are economically infeasible at over
$10,000 per ton of CO removed.



# 8.14.5 DRI CO BACT Selection

Use of clean fuels (natur al gas and process tail gas), Good Co mbustion Practices and Good Burner
Design and Operating Practices are selected as BACT for CO control in the DRI Process Heaters.

Minnesota Steel proposes a BACT CO emission limit of 0.08 lb CO/MMBtu for the DRI Process
Heaters. The proposed CO mass emission limit is 50 lbs of CO pe r hour on a 1 hour average basis.
The proposed limit is based on compliance testing for CO by EPA Method 25A and/or Method 18 for

determination of methane, etha ne and individual VOC compounds. The mass emission limit is based
on operation with BACT contro ls and the facility runni ng at full capacity.

There were no BACT determinations listed in the RBLC for CO emissions from DRI plants. BACT
report Attachment L, Table L-2 contains a summary of BACT determinations for DRI operations from the

EPA RBLC database.

Attachment L, Table L-41 contains a summary of BACT determinations from the EPA RBLC
database for natural gas-fired boile rs and heaters rated at 100 MMBtu/ hr or less. Although the duty
range for the RBLC search is smaller than the process heater duty, CO control performance is not
significantly affected by size. AP-42 lists the same CO factor for all sizes of gas fired heaters and
boilers. So, the RBLC data are a representative performance for larger heaters as well. The RBLC

data indicates Good Combustion Prac tices and use of natural gas as BA CT for CO control. As noted
in the NOx control analysis, CO emissions from low and ultra low NOx burners are slightly higher

than standard burners. Data in Table L-41 shows CO emissions from low and ultra low NOx burners

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# in the 0.08 to 0.1 lb CO/MMBtu range. Theref ore, specifying good combustion controls as BACT

with a limit of 0.08 lb CO/MMBtu for ultra low NO x burners is cons istent with recent RBLC BACT

determinations. This limit is also consistent with the median or recent determinations. Statistical
analyses of the RBLC data are summarized in the table and bar graph below.

RBLC CO BACT Limits Summary BACT-PSD CO lb/MMBtu Emission Limits Other (non-BACT) CO lb/MMBtu Emission Limits



## MIN 0.022 lb/MMBtu MIN 0.011 lb/MMBtu MAX 4.3 lb/MMBtu MAX 0.7 lb/MMBtu MEDIAN 0.082 lb/MMBtu MEDIAN 0.08 lb/MMBtu
COUNT 81 CASES COUNT 30 CASES

RBLC CO BACT Limits Small Gas Fired Heaters & Boilers

0 5 10 15 20 25 30

0.02 0.04 0.06 0.08 0.1 0.2 0.4 0.6 0.8 1 > 1

BACT limit lb CO/MMBtuCount Proposed BACT
Limit 0.08



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting process equipment into service, and will contin ue this practice until the process is shut down and
off line. Therefore, Minnesota Steel is not pro posing any special permit conditions for startup and

shutdown.

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# 8.15 DRI Process Heater Volati le Organic Compound (VOC) Emissions

8.15.1 Identification of Pote ntial VOC Control Technologies

Combustion of gaseous fuels (process tail gas and na tural gas) is the primary source of emissions
from the DRI Process Heater exhaust. VOC emissions are a result of incomplete combustion. Based

on AP-42 information, the calculat ed VOC emissions in the uncontrolled flue gases of the DRI
Process Heaters are 0.0054 lb/MMBTU. This equates to a VOC concentration of 13 ppm.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 8-28. Potential control technologies for VOC emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls



# 8.15.2 Elimination of Technicall y Infeasible VOC Control Options

As noted above, VOC concentration in the DRI Pr ocess Heater exhaust gas is approximately 13 ppm
VOC. This is very good performance for a low NOx burner and add-on controls cannot effectively
reduce VOC concentrations below 13 ppm.

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## Table 8-28 Technical Feasibility of VOC C ontrol Technologies for DRI Process Heaters
VOC Emission Control Technologies Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize VOC to water and CO 2 

## . This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of VOC at lower temperatures than a thermal incinerator. No

Good Combustion Controls Good combustion control limits the formation of VOC by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes



# 8.15.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness
The only remaining VOC control technology is good co mbustion control which is an inherent part of
the process.

Table 8-29 Ranking of Remaining VOC Control Technologies for DRI Process Heaters
VOC Control Technology

Rank Technology Estimated Control Efficiency

1 Good Combustion Controls NA

.


# 8.15.4 Evaluation of Most Effe ctive VOC Control Technologies

Because good combustion controls is an inherent part of the process there are no additional costs for
this control technology.

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## Table 8-30 Evaluation of VOC Control Technologies for DRI Process Heaters

VOC Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 

## Good Combustion Controls NA NA NA NA



# 8.15.5 DRI VOC BACT Selection

Good Combustion Practices and Good Burner Design and Operating Practices are selected as BACT
for VOC control in the DRI Process Heaters. Use of clean fuels (natural gas and process tail gas) in
combination with good combustion practices limits potential VOC emissions from the boilers.

Minnesota Steel proposes a BACT VOC emission li mit of 0.006 lb VOC/MMBtu for the DRI Process
Heaters. The proposed VOC mass emission limit is 3.3 lbs of VOC per hour on a 24 hour average
basis. The proposed limit is based on compli ance testing for VOC by EPA Method 25A and/or

Method 18 for determination of methane, etha ne and individual VOC compounds. The mass

emission limit is based on operation with BACT controls and the facility running at full capacity.

There were no BACT determinati ons listed in the RBLC for VOC emissions from DRI plants. BACT
report Attachment L, Table L-2 contains a summar y of BACT determinati ons for DRI operations

from the EPA RBLC database.

Attachment L, Table L-42 contains a summary of BACT determinations from the EPA RBLC
database for natural gas-fired boile rs and heaters rated at 100 MMBtu/ hr or less. Although the duty
range for the RBLC search is smaller than the process heater duty, VOC control performance is not
significantly affected by size. AP-42 lists the same VOC factor for all sizes of gas fired heaters and
boilers. So, the RBLC data are a representative performance for larger heaters as well. The RBLC

data indicates Good Combustion Pr actices and use of natural gas as BACT for VOC control. The

median BACT limit for VOCs in Table L-42 is 0.006 lb VOC/MMB tu. Therefore, specifying good

combustion controls as BACT with a limit of 0.006 lb VOC/MMBtu is consistent with recent RBLC

BACT determinations.

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# RBLC VOC BACT Limits Summary BACT-PSD VOC lb/MMBtu Emission Limits Other (non-BACT) VOC lb/MMBtu Emission Limits



## MIN 0.002 lb/MMBtu MIN 0.004 lb/MMBtu MAX 1.0 lb/MMBtu MAX 0.08 lb/MMBtu MEDIAN 0.006 lb/MMBtu MEDIAN 0.005 lb/MMBtu
COUNT 35 CASES COUNT 3 CASES



# RBLC VOC BACT limits
Small Gas Fired Heaters & Boilers



# 0 2 4 6 8 10 12 14 16

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1

VOC lb/MMBtuCount 

### Proposed BACT
Limit 0.006



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the boilers into service, and will continue this practice until the process is shut down and off line.
Therefore, Minnesota Steel is not proposing any sp ecial permit conditions for startup and shutdown.



# 8.16 DRI Process Heater Fl uoride (F) Emissions

8.16.1 Identification of Potential Fluoride Control Technologies

Fluoride compounds may be emitted in trace quantities from the DRI Process He aters as the result of

trace amounts of fluoride in the tac onite ore pellets and the natural ga s used in the DRI plant. Based
on the emission inventory data, the fluoride concentration in the DRI Process Heater exhaust is
calculated to be 5.0 e-7 gr/dscf. This value is ba sed on combustion of natural gas and process tail gas
which has passed through the DRI scrubber systems, and thus includes any inherent F- control that

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# the DRI gas scrubber systems provide. The evaluati on of add-on controls will be based on a DRI

Process Heater exhaust fluoride co ncentration of 5.0 e-7 gr/dscf.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 8-31. Potentia l control technologies for pellet plan t fluoride emissions are the following:

• Wet Scrubber

• Wet Electrostatic Precipitator

• Spray Dryer Absorption

• Dry Sorbent Injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design Methods and Oper ating Practices (Base Case)



# 8.16.2 Elimination of Technically Infeasible Fluorid e Control Options

At < 1 ppb, fluoride in the DRI Pr ocess Heater exhaust gas, all add-on contro ls are technically
infeasible because 5.0 e-7 gr/dscf is at or below th e exhaust concentrations that can be achieved with

theses controls.

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## Table 8-31 Technical Feasibility of Fluoride Control Technologies for DRI Process Heaters

Fluoride Emission Control Technolo gies Considered for BACT Analysis

Technology Description Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with fluoride and removes it. No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for fluoride removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For fluoride removal, caustic is added to the water spray system, allowing the spray system to function as a fluoride absorber. No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with fluoride and removes it. A fabric filter is used to collect the spent sorbent. No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. Fluoride re acts with sorbent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology No

Clean Fuel/ Good Combustion Practices (Base Case) Combust purified top gas and/or natural gas Yes

Good Design Methods and Operating Practices (Base Case) DRI plant internal top gas wet scrubbing system Yes



# 8.16.3 Ranking of Remaining Fluorid e Control Technologies by Control Effectiveness

Table 8-32 Ranking of Remaining Fluoride Control Technologies for DRI Process Heaters

Fluoride Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the process

1 Good Design Methods and Operating Practices (Base Case) NA Inherent to the process

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# 8.16.4 Evaluation of Most Effect ive Fluoride Cont rol Technologies

Table 8-33 Evaluation of Most Effective Fluoride Control Technologies for DRI Process Heaters
Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the
process NA Inherent to the process NA NA



# To show that add on emission controls are economically infeasible when fluorides are emitted in
trace quantities, a100% control efficiency was used as an example to calculate control costs. The
example calculation yields control costs of $470 mi llion dollars per ton of fluoride removed. The
results of the example calculations are summarized in Attachment D Table D-1



# 8.16.5 DRI Fluoride BACT Selection

Use of clean fuels and Good Design Methods and Operating Practices are selected as BACT. This
includes purified tail gas and natural gas. Top gas is low in F- due to the low concentration of
fluorides in the taconite feed to the DRI plant, and the inherent F- control provided by the top gas
scrubber. Natural gas is inherently low in fluor ide compounds. As discussed in 8.1 the DRI process
includes a top gas scrubber as part of the proces s which will provide for some inherent control of

fluoride emissions.

The proposed BACT fluoride mass emission limit for the DRI Process Heaters is 0.0004 lb/hr as
determined by particulate performan ce testing and measur ement of fluorides in the raw materials
feeding the DRI plant. The averaging period for fl uoride emissions is 3 hours (three 1-hour test
runs).

Attachment L, Table L-2 contains a summary of BA CT determinations for DRI operations from the

EPA RBLC database . Fluoride emission controls are not includ ed in any of the listings in Table L-2.

Since Minnesota Steel will use natural gas and/or purified tail gas at all times the DRI plant is
operating, no special permit conditions are requi red to control F- emissions during startup and

shutdown.

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# 8.17 DRI Process Heater Lead (Pb) Emissions

8.17.1 Identification of Potent ial Pb Control Technologies

Lead is present in trace quantities in taconite ore and the DRI pellets. It is emitted in trace quantities
as particulate matter. Em issions are primarily due to the attriti on of particles (dust) from the taconite
and DRI pellets. This is caused by the abrasion of pellets rubbing against one and other and the
process equipment as the pellets move through the DR I plant. In addition, any lead fume formed in
the process will be in a solid state (i.e. particulate) after being cooled to the operating temperatures of
the DRI plant emission control equipment. As disc ussed in Section 8.1, the DRI plants will have
internal wet scrubbing systems for particulate removal to protect the operating equipment from DRI

dust.

The evaluation of add-on controls for lead wi ll be based on a Process Heater exhaust lead
concentration of 3.6 e-7 gr/dscf. This concentratio n is calculated from the Pb mass emission rate in
the Air Emission Inventory (Appendix 3B.), and stack flow rate from form GI-04.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in

Section 4.0, and Table 8-16. Potent ial control technologies for pellet plant lead bearing particulate
emissions are the following:

• Fabric filter

• Wet scrubber

• Electrostatic precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (e.g. Cyclones)

• Inertial separators (drop out box)

• Good design methods and operating practices



# 8.17.2 Elimination of Technicall y Infeasible Pb Control Options

Table 8-16 lists the lead bearing particulate control technologies a nd their feasibility for control

emissions from the DRI Process Heater.

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# At 3.6 e-7 gr/dscf lead in the DRI Process Heater exhaust gas, all add-on controls are technically
infeasible because 3.6 e-7 gr/dscf is at or below th e exhaust concentrations that can be achieved with

theses controls.

Table 8-34 Technical Feasibility of Pb C ontrol Technologies for DRI Process Heaters

Summary of Pb Control Technology Feasibility
Technology Description Feasible? Yes or No

Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Lead bearing particulate matter is collected on the surface of the bags as the gas stream passes through them. The lead bearing particulate is periodically removed from the bags and collected in hoppers located beneath the bags. No

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the lead bearing particulate out of the gas stream. No

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove lead bearing particulate matter from the collection plates. No

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. No

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. No

Good Design Methods and Operating Practices (Base Case) DRI plant internal top gas wet scrubbing system and natural gas combustion. Yes

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# 8.17.3 Ranking of Remaining Pb Control Technologies by Control Effectiveness
The only remaining emission control technology fo r lead is Good Design Methods and Operating

Practices.

Table 8-35 Remaining Pb Control Technologies and Control Effectiveness for the DRI Process Heaters

Pb Control Technology Ranking

Rank Technology % Efficiency

1 Good Design Methods and Operating Practices (Base Case) Inherent to the DRI process design



# 8.17.4 Evaluation of Most Effective Control Technologies

Since the top gas scrubber is an inherent part of the DRI process, no addition al emission control costs

will be incurred.

Table 8-36 Evaluation of Most Effective Pb C ontrol Technologies for the DRI Process Heaters

Control Technology Effectiveness Evaluation



## Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Good Design Methods and

Operating Practices NA Inherent

to the
process NA Inherent to the process NA NA NA Inherent to the
process



# To show that add on emission controls are economically infeasible when fluorides are emitted in
trace quantities, a control cost based on 100% contro l efficiency was calculated as an example. The
example calculation yields control costs of $655 milli on per ton of lead removed. The results of the
example calculations are summarized in Attachment D Table D-1



# 8.17.5 DRI Pb BACT Selection

Use of inherent controls is recommended as BACT for lead bearing particulate control from the DRI
plant exhaust stack. As discussed in 8.1 the DRI process includes a scrubber on the top gas as an
inherent part of the process. Top gas is low in Pb due to the low concentration of Pb in the taconite

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# pellet feed to the DRI plant, and the inherent Pb control provided by the top gas scrubber. Natural
gas is inherently low in Pb compounds.

The proposed lead emission limit is 0.0003 lb/hr as demonstrated by performance testing for
particulate matter and measurement of lead in the DRI feed. The averaging period for lead emissions
is 3 hours (three 1-hour test runs).

Add-on controls following the internal partic ulate scrubber are economically infeasible.

Attachment L, Table L-2 contains a summary of BACT determinations for DRI operations from the

EPA RBLC database. Lead controls are not included in any of the listings in Table L-2.

For periods of startup and shutdown, Minnesota Steel will put the DRI plant particulate emission control
equipment into service prior to commencing operation of process equipment, and keep controls operating
until the process is shut down and off line. No excess emissions will occu r as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 8.18 DRI Top Gas Purification System

Carbon Dioxide (CO 2 

# ) is a by product of the DRI process. It is formed when CO reduces iron oxide
to metallic iron. It’s presence in the DRI top gas lowers the effectiveness of re using the reducing
gas by diluting its active constituents (CO and H 2 

# ). The DRI Top Gas Purification system is
designed to purify the reducing gas by removing the CO 2 

# . This is accomplished by using an amine
based sorption/desorption system. CO 2 

# captured in the CO 2 

# absorber is then vented to the
atmosphere in the amine stripper (desorption).

Another byproduct of the DRI process is hydrogen sulfide (H 2 

# S). Sulfur compounds in the DRI

reactor are converted to H 2 

# S by the reducing gas. The source of su lfur within the DRI process is that
a small amount of Dimethyl-disulfide that is injected into the top gas to serve as a corrosion
inhibitor, which protects the DRI Process Heater tubes. The amine solution used in the Top Gas
Purification system captures H 2 

# S as well as CO 2 

# . H 2 

# S is then vented along with the CO 2 

# in the

exhaust from the CO 2 

# stripper.

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# 8.19 DRI Top Gas Purificat ion Hydrogen Sulfide (H 2 

# S) Emissions

8.19.1 Identificati on of Potential H 2 

# S Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 8-19. Potentia l control technologies for pellet plan t Sulfur Dioxide emissions are the
following:

• Sulfur Recovery (LoCAT)

• Absorption (Zinc Oxide)

• Oxidation (Catalytic, Recuperative and Regenerative)

• Oxidation with Flue Gas Desulfurization



# 8.19.2 Elimination of Te chnically Infeasible H 2 

# S Control Options

With the exception of catalytic oxidation, all H 2 

# S control systems are technically feasible as shown in

Table 8-37.

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## Table 8-37 Technical Feasibility of H 2 

## S Control Technologies for DRI Top Gas Purification

SO 2 

## Emission Control Technol ogy Feasibility Analysis
Technology Description Feasible? Yes or No

Sulfur Recovery Sulfur recovery is the process of converting hydrogen sulfide to elemental sulfur. The LoCAT process uses an aqueous based iron catalyst to produce solid elemental sulfur. Yes

Absorption A sorbent is used to chemically capture the H 2 

## S. Zinc oxide is commonly used as a sorbent for H2S removal. The spent sorbent is disposed of as a solid waste. Yes

Catalytic Oxidation 

## Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of VOC at lower temperatures than a thermal incinerator. No

Recuperative Thermal Oxidation 

## A thermal oxidizer us es high temperature and residence time to oxidize H 2 

## S to water and SO 2 

## . A recuperative thermal oxidizer uses heat exchangers to reduce the energy requirements for operation of the thermal oxidizer. Yes

Regenerative Thermal Oxidation 

## A thermal oxidizer us es high temperature and residence time to oxidize VOC to water and CO 2 

## . A regenerative thermal oxidizer uses packed beds for heat transfer to reduce the energy requirements of the thermal oxidizer. Yes

Oxidation followed by Flue Gas Desulfurization This combination of controls is used to control the SO 2 

## generated by the oxidation of H 2 

## S in the oxidizer

A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with SO 2 

## and removes it Yes



# Catalytic oxidation is not technically feasible because H 2 

# S is a poison for oxidation catalyst.



# 8.19.3 Ranking of Remaining H 2 

# S Control Technologies by Control Effectiveness
The control technology rankings for technically feasible H 2 

# S control are listed be low in Table 8-38.

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## Table 8-38 Remaining H 2 

## SControl Technologies and Control Effectiveness for the DRI Top Gas Purification

SO2 Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Sulfur Recovery 92.3% *

2 Absorption 92.3% *

3 Oxidation followed by Flue Gas Desulfurization 92.3% *

4 Recuperative Thermal Oxidation 92.3% * Collateral SO2 emitted

5 Regenerative Thermal Oxidation 92.3% * Collateral SO 2 

## emitted



## * A 92.3% control efficiency is equivalent to 5 ppm H 2 

## S on a wet basis in the Top Gas Purification exhaust



# 8.19.4 Evaluation of Most Effective H 2 

# S Control Technologies

The effectiveness of H 2 

# S control technologies is summarized in Table 8-39 below. The detailed
control cost analyses are located in Attachment E.

Table 8-39 Evaluation of Most Effective H 2 

## S Control Technologies for the DRI Top Gas Purification
Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton 1 Sulfur Recovery 

## 30.1 $7,373,349 $1,355,047 $45,010 2 Absorption 

## 30.1 $7,920,532 $2,096,023 $69,622

3 Oxidation followed by Flue Gas Desulfurization 

## 30.1 $3,011,277 $1,177,247 $39,104

4 Regenerative Thermal Oxidation 

## 30.1 $1,956,150 $883,916 $29,360

5 Recuperative Thermal Oxidation 

## 30.1 $1,467,113 $1,441,107 $47,868



# With control costs over $20,000 per ton H 2 

# S removed, all H 2 

# S control technologies are economically

infeasible.



# 8.19.5 DRI Top Gas Purification H 2 

# S BACT Selection

Based on excessive costs, no add on cont rols are recommended as BACT for H 2 

# S control from the
Top Gas Purification System. The propo sed BACT emission limit is 8.2 lb H 2 

# S/hr on a 3-hour

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# average basis. Compliance w ill be demonstrated by performance testing using EPA Method 11.
Ongoing compliance will be monito ring the addition rate of dimethyl-disulfide to the process.

No BACT performance standard is recommended because H 2 

# S emissions are inherently low and no

add on controls are used.

Attachment L, Table L-2 contains a summary of BACT determinations for DRI operations from the

EPA RBLC database. The RB LC does not contain any H 2 

# S BACT limits.

Minnesota Steel does not require special permit conditions for control of H 2 

# S emissions during
startup and shutdown.



# 8.20 Pneumatic Transport Sy stem (PTS) Gas Heaters

The DRI plant is equipped with a pneumatic syst em for transferring hot DRI pellets from the DRI
plant over to the melt shop. The transfer gas circulates between the DRI plant outlet bins and the
EAF transfer bins. Gas leaving th e transport purge bin contains pa rticulates, and must be scrubbed
before being compressed for the next transfer cy cle. Wet scrubbing is used to remove theses
particulates. However, wet scrubbing cools off the transfer gas In or der to keep DRI pellet hot during
transfers, the pneumatic transfer gas is reheated after compression.

A natural gas fired process heater will provide the heat energy for reheating the transfer gas. The
transfer gas heaters are each rated at 12 MMBtu/hr. Air pollutants emitted from the PTS Gas Heaters

include: PM, PM10, SO 2 

# , NO
x 

# , CO, VOC. All emissions result from combustion of natural gas and

process gas.



# 8.21 PTS Gas Heater Pa rticulate MatterPM/PM 10 

# Emission

Particulate emissions from natural gas combustion are typically low. Particulate matter is generated
during incomplete combustion. All particulates are assumed to be PM 10 

# . Uncontrolled PTS Gas

Heater emissions were de termined using AP-42 emission factor s (0.0075lb/MMBtu) which equates to
a particulate concentration of 0.005 gr/dscf.



# 8.21.1 Identification of Potential PM/PM 10 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in

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# Section 4.0 and Table 9-28. Potential control technologies for particulate emissions are the
following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)

• Good Design Methods and Operating Practices



# 8.21.2 Elimination of Tech nically Infeas ible PM/PM 10 

# Control Options

Table 9-28 summarizes the technical feasibility of each particulate control technology on the PTS

Gas Heaters. Additional details for the technologies that are not feasible are discussed in the
subsequent sections.

Table 8-40 Technical Feasibility of PM/PM 10 

## Control Technologies for the PTS Gas Heaters

Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. No

Wet Scrubber Wet scrubbers, remove particles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. No

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

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## Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. No

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. No

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. No

Good Design Methods and Operating Practices Well designed and operated burners reduce the amount of particulate matter formed as a result of incomplete combustion. Yes



# At particulate concentrations of 0.005 gr/dscf, use of add-on controls for gas fired combustion
sources is technically infeasible because this partic ulate concentration level is at the limits of PM
emissions control technology. In addition, particulates from natu ral gas combustion are primarily
condensable particulates. Condensable PM is not readily remo ved by these control devices. The
particulate concentration of 0.005 gr/dsc f was calculated using the AP-42, 5 th 

# edition emission factor
for natural gas combustion and the EPA Method 19 “F” factor for flue gas volumes generated by
natural gas combustion. The F factor flow rate was adjusted to 3% oxygen in the flue gas; this is
typical of boiler and process heater operations.

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## Table 8-41 Ranking of Remaining PM/PM 10 

## Control Technologies for PTS Gas Heaters

PM / PM 10 

## Control Technology Ranking

Rank Technology % Efficiency

1 Good Burner Design and
Operating Practices NA

Base Case



# 8.21.3 Evaluation of Most Effe ctive PM Contro l Technologies
Since good burner design and operating practices are i nherent to the process, no additional cost will
be incurred. The detailed control cost analyses are located in Attachment F.

Table 8-42 Evaluation of Most Effective PM/PM 10 

## Control Technologies for the PTS Gas Heaters

Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# 8.21.4 PTS Gas Heater PM/PM 10 

# BACT Selection

Good Burner Design and Operating Pr actices are se lected as BACT for cont rol of particulates from

the PTS Gas Heater.

The proposed BACT PM/PM 10 

# limit for the PTS Heaters is 0.0075 lb PM/PM 10 

# /MMBtu, good
combustion practices and use of natural gas. Use of natural gas, a clean fuel, limits potential
emissions of particulat es. The proposed PM/PM 10 

# mass emission limit is 0.09 lbs of PM/PM 10 

# per hour on a 24 hour average basis. The proposed lim it is based on compliance testing for PM by EPA

Method 5, and PM 10 

# measured by EPA Methods 201 (or 201 A) and 202 (or EPA approved modified
Method 202 procedures). The mass emission limit is based on operati on with BACT controls and the
facility running at full capacity.

Attachment L, Tables L-38A and 38B c ontain a summaries of BACT PM and PM 10 

# determinations
from the EPA RBLC database for natural gas-fired boi lers and heaters rated at 100 MMBtu/hr or less.
Statistical analyses of the RBLC data are summarized in the tables and bar charts below. The
proposed BACT particulate limit of 0.0075 lb PM/PM 10 

# /MMBtu is consistent with AP-42 and less

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# than the median BACT PM/PM 10 

# limits listed below. Controls listed in the RBLC for this source are
use of natural gas and good combustion practices. Therefore, specifying good combustion controls

with a limit of 0.0075 lb/MMBtu as BACT is cons istent with recent RBLC BACT determinations.

RBLC PM 10 

# BACT Limits Summary BACT-PSD PM 10 

# lb/MMBtu Emission Limits Other (non-BACT) PM 10 

# lb/MMBtu Emission Limits

MIN 0.0019 lb/MMBtu MIN 0.007 lb/MMBtu MAX 0.6 lb/MMBtu MAX 0.4 lb/MMBtu MEDIAN 0.0085 lb/MMBtu MEDIAN 0.008 lb/MMBtu
COUNT 59 CASES COUNT 11 CASES



# RBLC PM10 BACT Limits
Small Gas Fired Heaters & Boilers

0 5 10 15 20 25

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1
BACT PM10 Limits lb/MMBtuCount 

### Propsed BACT
Limit 0.0075



# RBLC PM BACT Limits Summary BACT-PSD PM lb/MMBtu Emission Limits Other (non-BACT) PM lb/MMBtu Emission Limits



## MIN 0.005 lb/MMBtu MIN 0.007 lb/MMBtu MAX 5 lb/MMBtu MAX 0.014 lb/MMBtu MEDIAN 0.010 lb/MMBtu MEDIAN 0.00715 lb/MMBtu
COUNT 29 CASES COUNT 10 CASES

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# RBLC PM BACT Limits
Small Gas Fired Heaters & Boilers

0 2 4 6 8 10 12 14

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1 

# PM lb/MMBtuCount 

### Propsed BACT
Limit 0.0075



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the PTS Heaters into service, and will continue this practice until the process is shut down and off
line. In addition, particulate matter emissions fro m natural gas combustion are typically low; so, no
special conditions are needed. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 8.22 PTS Heater Visible Emissions

Visible emissions are the result of incomplete combustion of fuels in the PTS Heaters.



# 8.22.1 PTS Heater Visible Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

In the DRI PTS Heaters, PM/PM 10 

# emissions are controlled by good combustion practices.

A 3% opacity limit is recommended as BACT for visi ble emissions from the DRI PTS Heaters. i.e. the
average opacity of a heater cannot exceed 3% fo r more the one 6-minute period during an hour. If

Minnesota Steel identifies visible emissions from a DRI PTS Heater of 3%, it will take corrective action
as soon as it is practicable to do so. An opacity limit of 3% is consistent with recent RBLC
determinations for gas fired heaters as shown in the table below.

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## Small Natural Gas Boiler RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 10 % Opacity MIN 5 % Opacity MAX 20 % Opacity MAX 40 % Opacity MEDIAN 20 % Opacity MEDIAN 20 % Opacity
COUNT 14 CASES COUNT 13 CASES



# See Attachment L, Table L-46 for a detailed listing of recent RBLC opacity determinations for small
natural gas fired heaters and boilers.



# 8.23 PTS Heater Sulfur Dioxide (SO 2 

# ) emissions

SO 2 

# emissions from natural gas combustion are typicall y low. Based on use of natural gas as the fuel
for the vacuum degasser boiler, the expected SO 2 

# concentration in the boiler flue gas are expected to
be less than 1 ppm SO 2


# .



# 8.23.1 Identificati on of Potential SO 2 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various SO 2 

# control technologies are discussed in

Section 4.0 and Table 9-31. Pote ntial control technologies for SO 2 

# emissions are the following:

• Wet Scrubber

• Spray Dryer Absorption

• Wet Electrostatic Precipitator

• Dry Sorbent Injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design Methods and Operating Practices



# 8.23.2 Elimination of Te chnically Infeasible SO 2 

# Control Options

At less than 1 ppm SO 2 

# in the PTS Gas Heater exhaust, all add- on controls are technically infeasible
because 1 ppm is at or below the exhaust concentr ations that can be achieved with these controls.

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## Table 8-43 Technical Feasibility of SO 2 

## Control Technologies for the PTS Gas Heaters

Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with SO2 and removes it. No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for SO2 removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For SO2 removal, caustic is added to the water spray system, allowing the spray system to function as an SO2 absorber. No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with SO2 and removes it. A fabric filter is used to collect the spent sorbent. No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. SO2 reacts with sorbent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology No

Clean Fuel/ Good Combustion Practices (Base Case) Combust natural gas Yes



# 8.23.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness
The remaining control technology for control of SO 2 

# from the PTS Gas Heaters is the use of clean
fuel and good combustion practices.

Table 8-44 Ranking of Remaining SO 2 

## Control Technologies for the PTS Gas Heaters

SO 2 

## Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the process

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# 8.23.4 Evaluation of Most Effective SO 2 

# Control Technologies

Since the use of clean fuel and good combustion prac tices are an inherent part of the process, no

additional cost will be incurred.

Table 8-45 Evaluation of Most Effective SO 2 

# Control Technologies fo r the PTS Ga s Heaters

Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the
process NA Inherent to the process NA NA



# 8.23.5 PTS Gas Heater SO 2 

# BACT Selection

Use of clean fuels (natural gas) and good combustion practices are selected as BACT for the DRI
PTS heaters. Use of natural gas, a clean fuel, limits potential SO 2 

# emissions to the rated heat input
capacity of the boilers.

The proposed SO 2 

# mass emission limit is 0.024 lbs of SO 2 

# per hour on a 3 hour average basis. The
proposed limit is based on compliance testing for SO 2 

# by EPA Method 6C, determination of SO 2 

# by

instrumental methods. The mass emission limit is based on operation with BACT controls and the
facility running at full capacity.

Attachment L, Table L-39 contains a summary of BACT SO 2 

# determinations from the EPA RBLC
database for natural gas-fired boile rs and heaters rated at 100 MMBtu/hr or less. Statistical analyses
of the RBLC data are summarized in the tables and bar charts below. The proposed BACT limit of

0.024 lb SO 2 

# /hr is equivalent to 0.0006 lb SO 2 

# /MMBtu, and is cons istent with AP-42 and the lowest

BACT SO 2 

# limits listed below. Controls listed in the RBLC for this source are use of natural gas and
good combustion practices. Theref ore, specifying good combustion controls and use of natural gas

with a limit of 0.024 lb SO 2 

# /hr as BACT is consistent with recent RBLC BACT determinations.

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# RBLC SO2 BACT Limits Summary BACT-PSD SO2 lb/MMBtu Emission Limits Other (non-BACT) SO2 lb/MMBtu Emission Limits



## MIN 0.0006 lb/MMBtu MIN 0.0006 lb/MMBtu MAX 1.28 lb/MMBtu MAX 4 lb/MMBtu MEDIAN 0.0025 lb/MMBtu MEDIAN 0.017 lb/MMBtu
COUNT 44 CASES COUNT 14 CASES



# Since Minnesota Steel will use natural gas at all ti mes the DRI Boilers are operating, no special permit
conditions are required to control SO 2 

# emissions during startup and shutdown.



# 8.24 PTS Gas Heater Nitrog en Oxides (NOx) Emissions

Combustion of natural gas is the primary sour ce of emissions from the PTS Gas Heaters. NO
x 

# emissions from the PTS Gas Heaters are primarily thermal NO
x. 

# Low NO
x 

# Burners (LNB) rated at
0.08 lb NOx/MMBtu are used as the base case in this analysis because they are inherent in the
process design from HYL. LNB are inexpensive and are routinely offered as standard equipment.

An emission rate of 0.08 lb NOx/MMBtu is a cons ervatively high emission rate assumption for LNBs

relative to the AP-42 NO
x 

# emission factor for small boilers, whic h is equivalent to 0.05 lb/MMBtu.
A burner rating of 0.08 lb NO
x 

# /MMBtu equates to a NO
x 

# concentration of 60 ppm dry.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0
and Table 9-34. Potential control technologies for PTS Gas Heater NO
x 

# emissions are the following:

• Low Temperature Oxidation

• Selective Catalytic Reduction

• Selective Non-Catalytic Reduction

• Non-selective Ca talytic Reduction

• Ultra Low NO
x 

# Burners / Low-NOx Burners and Flue Gas Recirculation (ULNB / LNB-FGR)

• External Flue Gas Recirculation

• Low NOx Burners

• Low Excess Air (LEA)

• Other Combustion Controls

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# 8.24.1 Elimination of Technicall y Infeasible NOx Control Options

Table 9-34 summarizes the feasibility of potential NO
x 

# control technologies for emissions from the
PTS Gas Heaters. Details regard ing the technologies that are infeasible are discussed in the
subsequent sections.

Table 8-46 Technical Feasibility of NO x 

## Control Technologies for the PTS Heater

NO
x 

## Emission Control Technology Feasibility Analysis

Technology Description Feasible?
Yes or No

Low Temperature Oxidation Low Temperature Oxidation is a process where NO x 

## is oxidized to form water soluble nitrate compounds which can easily be removed by absorption (wet scrubbing). Oxidation occurs at relatively low temperatures (100oF – 200oF) so it can be effectively used as an add-on control system where the stream to be treated is not hot enough for catalytic controls. Ozone is typically used as the oxidizing agent. Yes

Selective Catalytic Reduction Selective catalytic reduction (SCR) is a postcombustion NO x 

## control technology in which ammonia (NH 3 

## ) is injected into the flue gas stream in the presence of a catalyst. SCR requires a temperature range of 500 ° F – 800 ° F. Yes

Selective Non-Catalytic Reduction The Selective non-catalytic reduction (SNCR) process injects urea or ammonia-based chemicals into the flue gas stream to convert NO to N 2 

## and water. The optimum operating temperature for SNCR is 1,600 ° F to 2,000 ° F. Yes

Non-Selective Catalytic Reduction Non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NO x 

## and CO react in the presence of NSCR catalyst to form nitrogen (N 2 

## ) and carbon dioxide (CO 2 

## ). It is typically employed in clean gas services such as natural gas fired turbines. No

Ultra Low NO x 

## Burners or Low-NO x 

## Burners and Flue Gas Recirculation This option is a combination of Low NOx burners and external flue gas recirculation.

The same effect can be accomplished with Induced flue gas recirculation burners. These burners are designed to draw flue gas into the burner to dilute the fuel. This reduces flame temperature and NO x 

## formation. Yes

External Flue Gas Recirculation External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures. In an external flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with Yes

Incorporate

d via the ULNB / LNB-EFR

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## NO
x 

## Emission Control Technology Feasibility Analysis

Technology Description Feasible?
Yes or No
the combustion air and this mixture is introduced into the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x 

## . analysis

Low-NOx Burners Low-NO x 

## burner (LNB) technology utilizes advanced burner design to reduce NO x 

## formation through the restriction of oxygen, flame temperature, and/or residence time. Yes (Base
Case)

Low Excess Air (LEA) Low Excess is a combustion control method which is used to reduce the amount of oxygen in the combustion zone of a furnace or boiler. This limits the amount of oxygen available for NO x 

## formation. Yes

Other Combustion Controls These combustion control methods are typically employed on existing sources. They inexpensive, but have limited control efficiencies. Combustion controls incl ude Overfire Air (OFA), Burners Out of Servic e (BOOS) and Load Reduction and Reduced Combustion Air Temperature. No



##  Non-Selective -Catalytic Reduction (NSCR)



# Review of the EPA RACT/BACT/LEAR Clearinghouse, as well as discu ssions with vendors, indicate
that this technology is not used in boiler applicatio ns. In addition, the same level of emission control

can be achieved with SCR or LoTOx.

 Other Combustion Controls



# Overfire air and burners out of se rvice are appropriate for large indus trial and utility boilers. A small

heater like the PTS Gas Heaters is not large enough to accommodate over fire air. Small heaters
usually have a limited number of burners (1 – 4) ; so, they do not have spare burners which can be
taken out of service. New neater designs can m eet low NOx control require ments without use of air
preheat limitations.



# 8.24.2 Ranking of Remaining NOx Control Technologies by Control Effectiveness
The remaining control technologies applicable to the PTS Gas Heaters are ranked by control

effectiveness in Table 9-35

.

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## Table 8-47 Ranking of Remaining NO x 

## Control Technologies for the PTS Gas Heaters

NO x 

## Control Technology Ranking

Rank Technology Estimated % Control
Efficiency

1 Selective Catalytic Reduction 70 % *

2 LoTOx 70% *

3 Ultra Low NO x 

## Burners or Low-NO x 

## Burners and Flue Gas Recirculation 56%

External Flue Gas Recirculation NA

4 SNCR 25%

NA Low NOx Burners NA Base Case

5 Low Excess Air (LEA) 1-15%
Implement as good operating practices



## * A 70% control efficiency is equivale nt to 18 ppm NOx on a dry basis



# 8.24.3 Evaluation of Most Effe ctive NOx Control Technologies

The detailed control cost analyses are located in Attachment F.

Table 8-48 Evaluation of Most Effective NO x 

## Control Technologies for the PTS Gas Heaters

NOx Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 

## LoTOx 2.4 $73,206 $137,201 $57,562

1 

## Selective Catalytic Reduction (SCR) 2.4 $179,922 $160,163 $67,195

2 Low-NOx Burners and Flue Gas Recirculation Burners 

## 1.9 $118,124 $17,477 $9,125

3 SNCR 

## 0.9 $346,842 $85,477 $100,412

4 Low NOx Burners NA Base Case NA Base Case NA Base Case NA Base Case

5 Low Excess Air (LEA) NA Implement as good operating practices NA Implement

as good operating practices NA NA

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# SCR, LoTOx, and SNCR are all ec onomically infeasible as their control costs are all above $10,000
per ton NOx removed.

Ultra Low NOx Burners, or Low NOx burners with exte rnal flue gas recirculat ion is the next highest

level of control.

An analysis of the RBLC indicates that small gas fi red heaters, similar to th e PTS Gas Heaters, listed

in Attachment L Table L-40A do not have add-on devices to control NO
x. 

# Only two of ninety seven

BACT entries had add-on controls for NOx. Instead, low NO
x 

# burners or low NOx burners with flue
gas recirculation have been predominatel y selected as BACT for control of NO
x 

# emissions.



# 8.24.4 PTS Gas Heater NOx BACT Selection

Minnesota Steel proposes ultra low NO
x 

# burners or low NO
x 

# burners with flue gas recirculation, or
equivalent combustion controls as BACT. Minnesota Steel considers the use of ultra low NOx

burners or low NO
x 

# burners with flue gas recirculation to be consistent with recent BACT

determinations as shown in Attachment L, Table L-40A.

Minnesota Steel proposes a BACT NO
x 

# emission limit of 0.035 lb NO
x 

# /MMBtu. The proposed NO
x 

# mass emission limit is 0.4 lbs of NO
x 

# per hour on a 24 hour average basis. The proposed limit is
based on compliance testing for NO
x 

# by EPA Method 7E, determination of NO
x 

# by instrumental
methods. The mass emission limit is based on oper ation with BACT controls and the facility running
at full capacity.

Attachment L, Table L-40A contains a summary of BACT determinations from the EPA RBLC
database for the natural gas-fired boilers and heater rated at 100 MMB tu/hr or less. The RBLC data

indicates that ultra low NO
x 

# burners or low NO
x 

# burners with flue gas recirculation have been

selected as BACT for control of NO
x 

# emissions from gas fired boilers and heaters. Statistical
analyses of the RBLC data are summarized in th e table and bar graph below. The proposed BACT

limit of 0.035 lb NO
x 

# /MMBtu is below the median RBLC BACT limit. Therefore, specifying ultra
low NOx burners with flue gas recirculation as BACT is consistent with recent RBLC BACT

determinations.

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# RBLC NO x 

# BACT Limits Summary

BACT-PSD NO x 

# lb/MMBtu Emission Limits Other (non-BACT) NO x 

# lb/MMBtu Emission Limits

MIN 0.0085 lb/MMBtu MIN 0.0085 lb/MMBtu MAX 5.5 lb/MMBtu MAX 0.23 lb/MMBtu MEDIAN 0.050 lb/MMBtu MEDIAN 0.036 lb/MMBtu
COUNT 97 CASES COUNT 35 CASES



# RBLC NOx BACT Limits Small Gas Fired Heaters & Boilers

0 5 10 15 20 25 30 35

0 .

0

1 0.02 0 . 0

3 0.04 0 .05 0.0 6 0.07 0 . 0

8 0.09 0 . 1 0.2 0 .3 0.4
> 0 .

4



# lb NOx/MMBtuCount 

### Proposed
BACT Limit
0.0035



# Periods of startup, shutdown and malfunction

For ULNB to effectively control NO
x 

# emissions, the PTS Heater must be at sufficient load for
effective flue gas induction into the ULNB and fo r combustion controls to maintain low levels of

excess combustion air. One the PTS heater has reached the appropriate operating conditions; the
ULNB will be able to control NOx emissions as intended. Until the process heater reaches the proper
operating conditions Minnesota Steel cannot comply with the BACT limits for normal operation.
Therefore, Minnesota Steel proposes to follow “Goo d Air Pollution Control Practices for Minimizing
Emissions” and to limit emissions to the rates Attachment M, Table 1 as BACT during startup and
shutdown. Good operating pr actices will include:

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## • 

# Operation of the PTS heaters in a manner which minimizes the amount of time the heater is
operated at temperatures and firing rates which are outside the operating range effective NO
x 

# control by ULNB.

• 

# Operation of the PTS heaters in a manner which minimizes the amount of time the heater is
operated at excess oxygen le vels higher than the operating range effective for NO
x 

# control by

ULNB.

Minnesota Steel will define good operating practices fo r minimizing emissions in its startup, shutdown
and malfunction plan. As noted in Section 4.8, pl ans for startup, shutdown and malfunction will follow
all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.



# 8.25 PTS Gas Heater Carbon Monoxide (CO) Emissions

CO emissions from the PTS Gas Heater are the result of incomplete natural gas combustion. Based

on AP-42 emission factors, the esti mated CO concentration in the exhaust of the PTS heaters is
0.08 lb/MMBtu. This equates to a CO concentration of 111 ppm, which is consistent with good
operation of low NO
x 

# burners.



# 8.25.1 Identification of Potent ial CO Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous CO control technologi es are discussed in

Section 4.0 and Table 9-52. Potential control t echnologies for CO emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Good Burner Design and Operating Practices



# 8.25.2 Elimination of Technically Infeasible CO Co ntrol Options

Table 8-49 summarizes the feasibility of potential control technologies for CO emissions from the

PTS Gas Heater.

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## Table 8-49 Technical Feasibility of CO Control Technologies for the PTS Gas Heater
CO Emission Control Technologie s Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize CO to CO 2


## . This may be accomplished using an add on oxidizer or a duct burner. Yes

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of CO at lower temperatures than a thermal incinerator. Yes

Good Combustion Controls Good combustion control limits the formation of CO by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of CO formed as a result of incomplete combustion. 

## Yes



# 8.25.3 Ranking of Remaining CO Control Technologies by Control Effectiveness

Table 8-50 Ranking of Remaining CO Technologies for the PTS Gas Heater

CO Control Technology Ranking

Rank Technology % Efficiency

1 

## Thermal Oxidizer (Recuperative and Regenerative) 90%*

1 

## Catalytic Oxidizer 90%

2 

## Good Combustion Controls NA

Base Case

2 Good Burner Design and Operating Practices NA

Base Case



## A 90% control efficiency is equivalent to 10 ppm CO on a dry basis

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# 8.25.4 Evaluation of Most Effe ctive CO Contro l Technologies

The detailed control cost analyses are located in Attachment F.

Table 8-51 Evaluation of Most Effective CO Control Technologies for the PTS Gas Heater

Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Thermal Oxidizer (Recuperative) 3.2 $348,272 $183,888 $58,257

1 Thermal Oxidizer (Regenerative) 3.2 $199,027 $142,871 $45,263

1 Catalytic Oxidizer 3.2 $361,783 $150,410 $47,651

2 

## Good Combustion Controls NA

Inherent Controls NA

Inherent

Controls NA NA

2 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# Thermal and catalytic oxidation are both econo mically infeasible.

Since the use of good combustion controls and good burner design and op erating practices are
inherent parts of the process no a dditional cost will be incurred.



# 8.25.5 PTS Gas Heater CO BACT Selection

Good Combustion Practices and Good Burner Design and Operating Practices are selected as BACT

for CO control in the PTS Heaters. Use of natu ral gas, a clean fuel, in combination with good
combustion practices limits potential CO emissions from the boilers.

Minnesota Steel proposes a BACT CO emission limit of 0.08 lb CO /MMBtu for the PTS Heaters.
The proposed CO mass emission limit is 0.95 lbs of CO per hour on a 1 hour average basis. The
proposed limit is based on compli ance testing for CO by EPA Met hod 10. The mass emission limit is
based on operation with BACT controls and the facility running at full capacity.

Attachment L, Table L-41 contains a summary of BACT determinations from the EPA RBLC
database for natural gas-fired boi lers and heaters rated at 100 MMBt u/hr or less. The RBLC data

indicates Good Combustion Practices and use of natura l gas as BACT for CO control. As noted in

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# the NOx control analysis, CO emissions from low a nd ultra low NOx burners are slightly higher than

standard burners. Data in Table L-41 shows CO emissions fro m low and ultra low NOx burners in
the 0.08 to 0.1 lb CO/MMBtu range. Therefore, specifying good combustion c ontrols as BACT with

a limit of 0.08 lb CO/MMBtu for ultra low NOx burners is cons istent with recent RBLC BACT

determinations. This limit is also consistent with the median or recent determinations. Statistical
analyses of the RBLC data are summarized in the table and bar graph below.

RBLC CO BACT Limits Summary

BACT-PSD CO lb/MMBtu Emission Limits Other (non-BACT) CO lb/MMBtu Emission Limits

MIN 0.022 lb/MMBtu MIN 0.011 lb/MMBtu MAX 4.3 lb/MMBtu MAX 0.7 lb/MMBtu MEDIAN 0.082 lb/MMBtu MEDIAN 0.08 lb/MMBtu
COUNT 81 CASES COUNT 30 CASES

RBLC CO BACT Limits Small Gas Fired Heaters & Boilers

0 5 10 15 20 25 30

0.02 0.04 0.06 0.08 0.1 0.2 0.4 0.6 0.8 1 > 1

BACT limit lb CO/MMBtuCount Proposed BACT
Limit 0.08



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the PTS heaters into service, and will continue this practice until the process is shut down and off
line. Therefore, Minnesota Steel is not proposing any special permit conditions for startup and shutdown.



# 8.26 PTS Gas Heater Volatile Or ganic compound (VOC) Emissions

VOC emissions from the PTS Gas Heater are the result of incomplete natural gas combustion. Based

on AP-42 information, the calculated VOC concentrat ion in the uncontrolled flue gases of the PTS

Gas Heater is .0054 lb/MMBTU . This equates to a VOC concentration of 13 ppm.

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# 8.26.1 Identification of Pote ntial VOC Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous VOC control technologi es are discussed in

Section 4.0 and Table 9-40. Potential control t echnologies for VOC emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Good Burner Design and Operating Practices



# 8.26.2 Elimination of Technically Infeasible VOC Control Options

Table 9-40 summarizes the feasibility of potential c ontrol technologies for control of VOC emissions
from the PTS Gas Heater. At 13 ppm VOC in the PTS Gas Heater exhaust, all add-on controls are
technically infeasible because this level is at or below the exha ust concentrations that can be

achieved with theses controls.

Table 8-52 Technical Feasibility of VOC C ontrol Technologies for the PTS Gas Heater
VOC Emission Control Technologies Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize VOC to water and CO 2 

## . This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of VOC at lower temperatures than a thermal incinerator. No

Good Combustion Controls Good combustion control limits the formation of VOCs by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of particulate matter formed as a result of incomplete combustion. 

## Yes

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# Thermal and catalytic oxida tion with add on control devices is c onsidered technically infeasible in
this application due to the low concentrations of VOC in the PTS heater exhaust. At 13 ppm VOC,

PTS heater exhaust VOC concentrations are at or below the level of control achievable by add on

oxidation controls. In addition, control cost ca lculations show that both thermal and catalytic
oxidizers are economically infeasible . See Attachment F Table F-1.



# 8.26.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness

The only remaining VOC control technologies are good combustion practices and good burner design
and operating practices.

Table 8-53 Ranking of Remaining VOC Control Technologies for the PTS Gas Heater

VOC Control Technology Ranking

Rank Technology % Efficiency

1 Good Burner Design and Operating Practices NA

Base Case



# 8.26.4 Evaluation of Most E ffective VOC Control Technologies

Since the use of good combustion controls and good burner design and op erating practices are
inherent parts of the process no addi tional cost will be incurred. The detailed control cost analyses

are located in Attachment F.

Table 8-54 Evaluation of Most Effective VOC Control Technologies for the PTS Gas Heater

Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# 8.26.5 PTS Gas Heater VOC BACT Selection

Good Combustion Practices and Good Burner Design and Operating Practices are selected as BACT

for VOC control in the PTS heater s. Use of natural gas, a clea n fuel, in combination with good
combustion practices li mits potential VOC emissions from the boilers.

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# Minnesota Steel proposes a BACT VOC emissi on limit of 0.006 lb VOC/MMBtu for the PTS
Heaters. The proposed VOC mass emission limit is 0.1 lbs of VOC per hour on a 24 hour average
basis. The proposed limit is based on compli ance testing for VOC by EPA Method 25A and/or

Method 18 for determination of methane, etha ne and individual VOC compounds. The mass

emission limit is based on operation with BACT controls and the facility running at full capacity.

Attachment L, Table L-42 contains a summary of BACT determinations from the EPA RBLC
database for natural gas-fired boi lers and heaters rated at 100 MMBt u/hr or less. The RBLC data

indicates Good Combustion Practices and use of natu ral gas as BACT for VOC control. The median

BACT limit for VOCs in Table L-42 is 0.006 lb VOC/MMBtu. Therefore, specifying good

combustion controls as BACT with a limit of 0.006 lb VOC/MMBtu is consistent with recent RBLC

BACT determinations.

RBLC VOC BACT Limits Summary

BACT-PSD VOC lb/MMBtu Emission Limits Other (non-BACT) VOC lb/MMBtu Emission Limits

MIN 0.002 lb/MMBtu MIN 0.004 lb/MMBtu MAX 1.0 lb/MMBtu MAX 0.08 lb/MMBtu MEDIAN 0.006 lb/MMBtu MEDIAN 0.005 lb/MMBtu
COUNT 35 CASES COUNT 3 CASES



# RBLC VOC BACT limits
Small Gas Fired Heaters & Boilers



# 0 2 4 6 8 10 12 14 16

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1

VOC lb/MMBtuCount 

### Proposed BACT
Limit 0.006

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# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the PTS heaters into service, and will continue this practice until the process is shut down and off
line. Therefore, Minnesota Steel is not proposing any special permit conditions for startup and shutdown.



# 8.27 DRI Cooling Towers

8.27.1 Process Description
The DRI cooling water system consists of sumps, circulation pumps, cooling towers and a clarifier
system. This system supplies cooling water to the direct contact coolers and cooling for process
water used in the top gas scrubber and reformed gas cooler.

Since all of the cooling towers at Minnesota Steel are similar in nature, this BACT report contains a
single section for cooling tower BACT analysis. See BACT report Section 13.0 for this analysis. In
summary, BACT for cooling towers is installation of mist eliminators and limiting the Total
Dissolved Solids content of the cooling water.



# 8.27.2 Cooling Water Blowdown Vents Description/Emissions

Much of the gas cooling in the DRI plant occurs in direct contact coolers. The Process Cooling
Water (PCW) loop includes cooling which takes place in the orifice and venturi scrubbers for the top
gas and depressurization systems. Water from the PCW circuit is routed to a clarifier system for
solids removal. The Quench Cooling Water (QCW) provides cooling water for the top gas quench
tower, compressor after cooler a nd process humidifier. QCW is circ ulated through a c ooling tower.
The primary purpose of the blowdown vents is to prevent process gases from entering the clarifiers
and cooling towers in the event that liquid level is lost in one of the contactors. Because the cooling
water is in direct with the process gases under pressure, CO and CO 2 

# are absorbed by the cooling
water. The blowdown vents provide place for the c ooling water to release di ssolved gases just prior
to entry in the clarifier and cooling tower systems.

Because the DRI process works under pressure, both feed and product pellets must move through
lock hoppers to bring the pellets up to and down fro m the DRI process operati ng pressure. The flow
rate and pressure fluctu ations of the lock hoppers, cause the CO and CO 2 

# concentrations in the
cooling water to fluctuate too. This, in turn, causes fluctuations in the flow rate and concentrations of

CO and CO 2 

# in the cooling water blowdown vents. The introduction of taconite pellets in batches
can also affect the composition of the top gas as each new batch of pe llets begin the reduction

process

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# 8.27.3 Identification of Potential Cooling Tower Blowdown Vent Control Technologies
Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various pollution control technologies are discussed in

Section 4.0 and Table 9-22. Potential control t echnologies for CO emissions are the following:

• Add on controls (e.g. flares, th ermal and catalytic oxidizers)

• Good Design Methods and Operating Practices



# 8.27.4 Elimination of Technically In feasible Cooling Tower Blowdown Vents Control Options

Table 9-22 summarizes the technica l feasibility of potential pollu tion control technologies for the
cooling tower blowdown vents. Deta ils regarding the technologies that are not feasible are discussed
in the subsequent sections.

Table 8-55 Technical Feasibility of Emission Co ntrol Technologies for the Ladle and Tundish Preheaters
Emission Control Technologies Considered for BACT Analysis
Technology Description Feasible? Yes or No Add on Controls Flares, thermal oxidation and catalytic oxidation. No

Good Design Methods and Operating Practices 

## Enclosed space for evolution of CO/CO 2 

## off gas with vent to safe location. Yes



# As noted above, the flow rates of cooling towe r blowdown vent gases are intermittent, and CO
concentrations are highly variable. The DRI vendor has indicated that these variations in flow and
concentration make it technically infeasible to ma intain steady continuous combustion in a flare or

oxidizer. In addition, flow and concentration variations would make it impossible to properly
regulate supplemental gas flow rates to an oxidizer.



# 8.27.5 Ranking of Remaining Coo ling Tower Blowdown Vents Control Technologies by Control Effectiveness

The remaining control technologies applicable to the Cooling Tower Blowdown Vents are ranked by

control effectiveness in Table 9-10.

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## Table 8-56 Ranking of Remaining Preh eater Emission Control Technologies
Emission Control Technologies

Rank Technology Estimated % Control Efficiency

1 Good Design Methods and Operating Practices NA



# Good Design Methods and Operating Practices for minimizing CO emissions are the only technically
feasible emission control technology.



# 8.27.6 Evaluation of Most Effective Cooling Tower Blowdown Vents Control Technologies

Table 8-57 summarizes the evaluation of cooli ng water blowdown vent emission controls.

Table 8-57 Evaluation of Most Effective Cooling Tower Blowdown Vent Emission Control Technologies

Emission Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Design Methods and Operating Practices NA Inherent Control NA Inherent Control NA NA



# The cooling water blowdown vent systems provide for the controlled degassing of cooling water
streams and allow the off gases to be vented to a safe location. While the blowdown systems do not
control CO emissions, they do provide for safe release of these gases and they protect the clarifier
and cooling tower systems. This reduces the potential for excess emissions from process upsets
which would otherwise damage the cooling water systems.



# 8.27.7 Cooling Tower Blowdo wn Vents BACT Selection

The proposed BACT for CO emissions the cooling wa ter system is installation and proper operation
of the cooling water blowdown system. Add on cont rols for CO are technically infeasible in this
application.

The proposed CO mass emission limit is 6.3 lbs of CO per hour from on a 3 hour average basis from
each quench cooling system, and 2.7 lbs of CO per hour from on a 3 hour average basis from each

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# process water cooling system. If te sting is feasible, thre e hour compliance test (or longer if needed)
using EPA Method 10 is proposed due to the highly vari able flow rates from these sources. The mass

emission limit is based on operation with BACT controls and the fa cility running at fu ll capacity.

Attachment L, Tables L 25 -29 contains a summary of BACT determinations for DRI. There were no
BACT determinations for CO emissions from cooling water blowdown stacks.

For periods of startup and shutdown, Minnesota St eel Industries will follow good operating practices for
putting process equipment into service, and shutting it down. This includes practices such as establishing
proper water levels in the cooling water contactors to minimize the venting of gases due to poor water

seals.



# 8.28 DRI Material Handling

8.28.1 DRI Material Ha ndling Process Description
In the DRI section of the plant, material hand ling equipment includes taco nite ore and DRI pellet
conveyor drops, storage bin vents and taconite and DRI pellet scre ening. DRI material handling
systems also include the Pneumatic Transfer System (PTS) which is used for the transfer of hot DRI
pellets from the DRI plan t to the melt shop. The PTS is described in Section 8.1.1. The DRI
vendor’s design includes a wet scrubbing system for the pneumatic transfer gas and the PTS system
vent is designed to meet the pr oposed material handling BACT limit. A mass emission limit for the
PTS depressurization vent is included in Attachment N.

In order to simplify the BACT report, emissions controls for ma terial handing equipment throughout
the facility are reviewed in Section 11.0 for raw materials and Section 12.0 for additives. Material
handing equipment reviewed in Section 11.0 includ es particulate emissions from conveyor drops,
crushing and grinding operations a nd screening of raw materials and intermediate products. Section
11.0 also contains a list of sources covered by the material handling BACT analysis.



# 8.28.2 BACT Summary for DRI Plant Material Handling
BACT for material handling in the DRI area of the fa cility is the use of a wet scrubber in conjunction
with a ventilated enclosure of the emission source(s). As noted in Section 11.0, the use of wet
scrubbers in the DRI area is requ ired for safety reasons. The pr oposed BACT limit for particulate
emissions is 0.005 gr/dscf for we b scrubbers and 0.0025 gr/dscf fo r baghouses as measured by EPA
Method 5. Attachment N specifies the type of control for each emission point. Where feasible,
baghouses are specified.

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# For periods of startup and shutdown, Minnesota St eel will put material handling particulate emission
control equipment into service prior to commencing operation of process equipment, and keep controls
operating until the process is shut dow n and off line. Therefore, Minn esota Steel is not proposing any
special permit conditions for startup and shutdown.

For control of emissions from additive handling, Mi nnesota Steel will put the additive handing emission
control equipment into service prior to commencing tr ansfer operations, and keep controls operating until
the transfer is complete. No excess emissions will occur as a result of control equipment
startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions for startup

and shutdown.



# 8.29 Fugitive Dust Emissions

8.29.1 DRI Fugitive Dust Process Description
Sources of fugitive particulate emission from the DRI plant include unpaved roads, storage piles,
loading and unloading operations, and mate rial drops from mobile equipment.

In order to simplify the BACT report, emissions controls for fugitive dust sources throughout the
facility are reviewed in Section 15.0 of the BACT report. Fugitive dust sources reviewed in
Section 15.0 include mining operations, tailings ba sins, unpaved roads, storage piles, loading and
unloading operations, and material drops from mobile e quipment. Section 15.0 also includes a list of
sources covered by the material handling BACT analysis.



# 8.29.2 Summary of Fugitive Emissions BACT

Minnesota Steel will follow industry best practices for controlling fugitive dust emissions.

Minnesota Steel has prepared a fugitive dust control plan (Attachment O) which describes the

measures Minnesota Steel will take to control thes e emissions. Dust control measures listed in the
plan are consistent with dust control techniques used by other mining facilities in the area.

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# 9.0 Steel Mill

9.1 Steel Mill Overview

The Minnesota Steel Industries' Steel Mill will include the following steel making processes:

• 2 electric arc furnaces (EAF)

• 2 ladle metallurgy furnaces (LMF)

• Ladle and tundish preheaters

• 2 vacuum degassing systems

• 1 natural gas fired boiler for vacuum degassing

• 2 continuous slab casters

• 1 tunnel furnace

• 4 cooling towers

• Materials handling

• Fugitive emissions.



# 9.2 Electric Arc Furnace (EAF) and Ladle Metallurgy Furnaces

9.2.1 Process Description
The Minnesota Steel Melt Shop will include the fo llowing steel making proc esses: 2 electric arc
furnaces (EAF), 2 ladle metallurgy furnaces (LMF), ladl e preheaters, ladle dr yers, and 2 tundishes.

The steel mill will use an approximate 1-hour batch cycle process to melt a 376 metric ton hot DRI
pellet charge to the EAFs. The EAF will also be used to recycle slag metallics and baghouse dust
produced at Minnesota Steel. Pe bble lime and limestone are added to remove impurities from the
steel and to form a slag. Carbon is added to cr eate the desired reducing environment. While a
fraction of ore-based sulfur still exists in the DRI feed material, injection carbon is the primary

source of sulfur, which leads to sulfur dioxide emissions.

Each EAF will be equipped with two carbon electrode s, which enter through the roof of the EAF.
These electrodes are used to melt the DRI pellet charge. Oxy-fuel burners are installed in the side
wall and roof of the furnace. They are used to provide energy for the steel making process. The oxyfuel burners operate at the beginning of the melting cycle to accelerate melting, and are periodically
operated to heat “cold spots” in the furnace. Oxygen lances inject oxygen into the steel “heat” to

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# provide energy, adjust carbon content of the molten steel, to stir the steel to equalize temperature and
composition, and to foam the slag. The lances ar e also used to inject ca rbon and lime. The EAF is
covered by a roof, which is ventilated to a dire ct shell evacuation system and to a baghouse.

When the iron and additives melt in the EAF they se parate into a molten steel layer at the bottom and
a molten slag layer on top. Minnesota Steel will us e a foaming slag process. In this process, carbon
and oxygen are trapped in the slag creating expandable foam. The foaming slag helps to bury the arc
which improves the furnace power input, lowers hear th refractory wear by shielding arc radiation,
and improves heat transfer. This process will pr oduce additional chemical energy along with CO due
to the oxidation of the injected carbon. The slag layer also ab sorbs deoxidation products (e.g., SiO 2


# and Al 2 

# O 3 

# ), removes impurities, provides de-phosphorizing, protects th e molten steel from oxidation,
hydrogen and nitrogen absorption and reduces heat loss . In addition, foamy slag insulates the molten
steel for improved thermal efficiency.

Emissions from the EAF include particulates, SO 2 

# , NO
x 

# CO, and VOCs. Fluorides, sulfuric acid mist
and lead are emitted in trace quantities. Particulates come from metal fumes and slag carry over.
Carbon used in the EAF is the primary source of SO 2 

# . NO
x 

# is generated by the oxy-fuel burners
when they are used to heat the EAF. NO
x 

# is also formed by the high operating temperatures of the

EAF. Molten steel is 2,700°F - 3100°F. At these temperatures NO
x 

# formation will occur from
oxidation of atmospheric nitrogen when it comes in contact with the thermal energy from the hot
steel, electric arc and hot gases used to refine the steel. VOCs and CO are generated by the oxidation
of carbon in the EAF and by incomplete combustion in the oxy-fuel burners.

The majority of emissions from the EAFs are drawn through the “4 th 

# Hole” direct evacuation system.

Particulate emissions from EAFs are most comm only controlled by baghouses. The extreme
temperature (~2,000 o 

# F) conditions of the gas stream imme diately leaving the EAF require watercooled ductwork, including a narrow gap at the duct elbow. The gap allows the furnace roof to be
opened without removing duct work, but it also al lows for the introduction of combustion air when
the roof is in place and the EAF is in operation. During EAF operation the e xhaust stream contains a
high concentration of carbon monoxide (CO). CO is oxidized to CO 2 

# when it mixes with combustion
air introduced at the gap in the 4 th 

# -Hole duct. The water-cooled duct includes a sharp elbow after
clearing the EAF roof leading to the drop out box. The sharp elbow minimizes the buildup of slag
deposits in the duct and allows air-entrained slag to reach the drop out box for collection. The drop
out box also plays a role in CO control by pr oviding a residence time for more complete CO
combustion. EAF off gases leaving the water c ooled duct are in the neighborhood of 1,200o F.

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# Additional cooling is needed befo re emission controls ca n be employed. Cool air from the other
particulate collection hoods in the melt shop is mixed with the EAF exhaust to bring the off gas
stream down to a suitable temper ature (< 400o F) for pa rticulate emission controls. Using air from

the other collection hoods minimizes the amount of water used for cooling the EAF off gas and
consolidates all of the particulate bearing air streams for efficient particulate removal. The combined
exhaust stream is then vented through a baghouse to remove particulates from the EAF and fugitive
particulates released by other operations within the melt shop.

When ready, the liquid steel is tapped to two preheated Ladle Metallurgy Furnaces (LMF). The
liquid steel is then refined in a step generally referred to as the ladle metallurgy process. The LMF is
a small version of an EAF where the chemical composition and the temperature of a steel heat are
adjusted to final specifications prior to casting. LMF processes include the injection and addition of
alloys and fluxes, stirring with inert gas such as argon, desulfurization and slag removal. The LMF
uses twin AC-powered electrodes to increase the heat temperature.

Emissions from the LMF include SO 2 

# , NO
x 

# , CO, and particulates. Most of these compounds are
released as a result of the refining process. NO
x 

# may also be formed by oxidation of atmospheric
nitrogen by the hot molten stee l. Emissions from the LMFs are captured by the melt shop canopy
hood and are routed to the melt shop baghouse for particulate removal.

For some grades of steel, vacuum degassing is used to further refine the molten steel. Vacuum
degassing is used primarily to re duce the carbon content of the steel. It also used to remove
dissolved gases present in the steel. To degas steel, a ladle of molten steel is placed in a vacuum
chamber where the unwanted compounds volatilize under reduced pressure. Vapors from degassing

will be routed to a control device to control ca rbon monoxide emissions. Stea m eductors are used to
generate the vacuum. A natural ga s fired boiler will be used to ge nerate steam for operation of the

eductors.

After the molten steel is refined to the desired composition and temperature specifications, the liquid
steel is transferred to the continuous casting system . The liquid steel is li fted in the ladles and

allowed to flow into two tundishes. The tundishes are shallow refrac tory-lined basins located on top

of the continuous caster. The molten steel then flows through drain holes in the tundish and into a
slowly oscillating, water-cooled copper mold. The tundishes allow the operator to regulate precisely

the flow of metal into the conti nuous caster mold. The molten steel solidifies as it passes through the
mold and emerges as a continuous slab of seven to te n inch thickness. After complete solidification,

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# the continuous slab is cut into appr opriate lengths for sale or for rolling into sheet steel. The casters
are sources of particulate matter. Particulates are emitted as metal fumes and casting powder dust.
Particulates from the caster are captured by th e melt shop canopy hood and routed to the melt shop
baghouse for removal.

The tundishes and ladles are pre-heated with natural gas fired low NO
x 

# burners to protect the
refractory and to ensure that no water is present. These burners have an open flame and heat is
applied directly to the ladles and tundish es. The preheat burners are a source of NO
x 

# emissions.
Emissions of other criteria pol lutants are minimal due to the use of natural gas as fuel.

One caster (i.e., one line) will be served by a tunne l furnace, which provides the holding time needed
to achieve an equalized temper ature distribution at about 2,100 o 

# F throughout the slab prior to
entering the rolling mill. Slabs which are destined for the rolling mill enter and travel through a 700-
foot to 800-foot tunnel furnace. Natural gas-fired low NO
x 

# burners are positi oned along the entire
length heat the tunnel furnaces.

The temperature equalized slabs exit the tunnel fu rnace and enter the rolling mill. From the mill
entry section the slab will be roll ed through a series of mill stands that use hydraulic pressure to
sequentially reduce the finished sheet thickness to the required specification. The sheet steel will be

final trimmed and coiled for rail or truck sh ipment. The tunnel furnace is a source of NO
x 

# emissions.
Emissions of other criteria pol lutants are minimal due to the use of natural gas as fuel.

The steel mill EAFs will use hot DRI as it is disc harged from the DRI plant, which will reduce the
energy consumption by the EAFs, which in turn may minimize the use of the oxy-fuel auxiliary
burners. Reduced use of the oxy-fuel burners should lo wer the overall NO
x 

# emission rate per ton of
steel produced.

The 100% DRI charge also reduces the number of times the EAF roof is opened compared to a
typical EAF. Opening the EAF roof is a source of fugitive particulates inside the melt shop. Typical
EAF operation includes several roof openings pe r EAF heat to add more scrap as each charge is
melted down. DRI pellet addition will occur via a chut e though the furnace roof, and the EAF roof
will not need to be opened for DRI additions. An EAF cycle at Minnesota Steel will typically not
have to open the EAF roof after it is closed to start the cycle, whic h suggests signi ficantly less
fugitive emissions into the melt s hop interior. Periodically, accumula ted in house scrap will have to
be added to the EAFs via an op en EAF roof. In addition, each cold start of the EAF following

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# weekly or annual maintenance will require a 150 ton charge of clean market scrap steel to create a

new molten “heel” in the EAF. DRI pellets are not conductive enough to achieve a cold start of the
EAFs. During normal operations, the heel is retained to start the ne xt batch; so, a 100% DRI charge

is feasible.

Air pollutants generated during steel produc tion can be summarized as follows:

Source Pollutants Emitted

EAF PM, PM10, SO 2 

## , NO x 

## , CO, VOC, SAM, Fand Pb
LMF PM, PM10, SO 2 

## , NO x 

## , CO, VOC Ladle and Tundish preheaters PM, PM10, SO 2 

## , NO x 

## , CO and VOC
Tundish and Continuous Caster PM, PM10
Tunnel Furnace PM, PM10, SO 2 

## , NO x 

## , CO and VOC



# Please note that the proposed BACT limits for startup and shutdown of the EAF are for startup/shutdown
events associated with cold startup after EAF maintenance and shutdowns in preparations for

maintenance. Activities associated with normal batc h cycles are not considered startup or shutdown

conditions for BACT.



# 9.3 EAF Particulate Matter (PM and PM 10 

# ) Emissions

About 90% of the PM emissions are solidified me tal fumes generated during the melting and refining
of the liquid steel in the EAF and LMF. Iron oxide is the predominate constituent of the particulate
matter emitted during melting. The remaining 10% are generated during charging and tapping. The

tundishes and continuous casters are also a source of particulate emissions. Th ese particulates are in
a solid state when emitted and are classified as filterable particulates.

The melt shop also cont ains a small amount of condensable pa rticulate matter. The condensable
particulates are primarily inor ganic compounds like sulfates an d volatile organic compounds.
Sulfates are due to the release of sulfur during the melting and refining of steel. The volatile organic
compounds are products of incomplete combustion fr om burning natural gas in the oxyfuel burners
and the ladle and tundish preheaters

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# 9.3.1 Identification of Potential PM/PM 10 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in

Section 4.0 and Table 9-1. Potential control techno logies for particulate emissions are the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)

• Good Design Methods and Operating Practices



# 9.3.2 Elimination of Tech nically Infeas ible PM/PM 10 

# Control Options

Table 9-1 summarizes the technical feasibility of each particulat e control technology on the melt
shop. Additional details for the technologies that are not feasible are discussed in the subsequent

sections.

Table 9-1 Technical Feasibility of PM/PM 10 

## Control Technologies for the Melt Shop

Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. Yes

Wet Scrubber Wet scrubbers, remove particles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. Yes

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## Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. No

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes

Good Design Methods and Operating Practices The EAF is vented to a Direct-shell Evacuation Control system (DEC). When the DEC is closed, the entire process remains covered, and 100% of the PM is collected. Due to the process variability that comes with the batch EAF, a design including a DEC offers high capture efficiency for PM. The DRI is designed to accept a continuous feed of hot DRI pellets. So opening of the EAF cover is minimized during operation. Yes



# Electrostatic Precipitator
ESP’s have proven to be unsuitable for applicatio ns involving exhaust streams with particulates
containing a high concentration of iron compounds. The electromagnetic properties of small charged
particles of iron compounds cause th e particles to adhere very strongl y to the collection plates. The
particles are then extremely difficult to dislodge which results in a decrease of control efficiencies
for the ESP. Since iron oxide is the predominant particulate constituent of the exhaust streams of

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# EAFs, dry or wet ESP’s are considered technically infeasible for controlling particulate emission
from the melt shop.



# 9.3.3 Rank Remaining PM/PM 10 

# Control Technologies by Control Effectiveness
The remaining particulate control technologies appl icable to the melt shop are ranked by control

effectiveness in Table 9-2.

Table 9-2 Ranking of Remaining PM/PM 10 

## Control Technologies for Melt Shop

PM / PM 10 

## Control Technology Ranking

Rank Technology % Efficiency

1 Baghouse 98% - 99+%

2 Wet Scrubber 95% - 99+%

4 Centrifugal Separation
(e.g. Cyclones) 50% - 80%

5 Inertial Separators
(Drop Out Box) < 50%

6 Good Design Methods and Operating Practices NA Inherent to EAF
operation



# 9.3.4 Evaluation of Most Effective PM/PM 10 

# Control Technologies

Fabric Filter


# Fabric filters are technically feasible for coll ecting fine particulate matter containing high
concentration of iron compounds and can achieve the highest control efficiencies from EAFs and
other types of furnaces that have high particulat e emissions. Control efficiency ranges from 98 to 99+
percent removal.

Attachment L, Tables L-3, L-4 and L- 5 contain summaries of recent PM/PM 10 

# BACT determinations
for EAF operations from the EPA RBLC database. As shown in Tables L- 3, L-4 and L-5 fabric
filters are widely used to control particulate matter and are routinely selected as BACT. The
supporting technical documents as sociated with these permits suggest that baghouses and wet
scrubbers have the highest levels of control and are equivalent. Baghouses are the preferred method
of control as the variable nature of EAF ope ration could adversely af fect a wet scrubber.

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# Based on the fact that fabric filters are the top co ntrol option and are routinely determined as BACT
for melt shops, Minnesota Steel Industries considers fabric filters to be BACT. As specified in the

EPA’s New Source Review Work shop Manual, (October 1990), “ an applicant proposing the top
control alternative need not provide cost and other detailed information in regard to other control
options.” Consequently, mechanical collectors and wet scrubbers will not be considered any further.



# 9.3.5 EAF PM/PM 10 

# BACT Selection

A fabric filter in combination with a Direct-shell Evacuation Control system (DEC) represents the
highest level of control for particulate emissions from the EAF. An eval uation of recent BACT

determinations in the RBLC resulted in emission li mits of 0.0018 grains pe r dscf using EPA Method
5 (filterable particulates), and 0. 0030 gr/dscf using test Methods 5 (fil terable particulates) and 202 or
EPA approved modified Method 202 proce dures (condensable particulates).

The proposed mass emission limits are 16 lb/hr PM 10 

# and 9 lb/hr PM on a 24 hour average basis for
each melt shop. The mass emission limits are based on operation with BACT controls and the facility
running at full capacity.

Attachment L, Tables L-3, L-4, L-17, L-18 and L- 19 contain a summary of PM, PM10 and filterable

PM BACT determinations for EAF and melt s hop operations from the EPA RBLC database.
Statistical analyses of the RBLC data are summariz ed in the tables below. Note that the minimum
value in most cases is 0.0018 gr/dscf, and the maxi mum value is 0.0052 gr/dscf. This is in part due
to the incorporation of condensable PM into the an alysis. Historically, 0. 0052 gr/dscf as filterable

PM was the New Source Performa nce Standard limit for EAFs. As control technology improved,
0.018 gr/dscf became the limit for filterable PM and 0.0052 gr/dscf became the limit for total PM
(filterable + condensable). This development can be seen in the RBLC list ing for melt shop BACT

limits for PM and Filterable PM for the Nucor fac ility with RBLC ID IN-0108 (Tables I- 17 and 19).
It is also documented in the CF & I permit (RBL C ID CO 0054) where the permit specifies Methods
5 and 202 (or EPA approved modified Method 202) procedures for determining compliance with
filterable and total particulat e matter. The proposed BACT PM- limit is ba sed on the Co-Steel
Raritan (RBLC ID NJ-0040) PM BA CT of 0.003 gr/dscf. Stack test showed PM emissions of 0.0029
gr/dscf

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# EAF RBLC PM 10 

# BACT Limits Summary
BACT-PSD PM 10 

# gr/dscf Emission Limits

MIN 0.0018 GR/DSCF MAX 0.0052 GR/DSCF MEDIAN 0.0030 GR/DSCF
COUNT 7 CASES



# EAF RBLC PM BACT Limits Summary BACT-PSD PM gr/dscf Emission Limits

MIN 0.0018 GR/DSCF MAX 0.0052 GR/DSCF MEDIAN 0.0033 GR/DSCF
COUNT 13 CASES

Melt Shop RBLC PM 10 

## BACT Limits Summary 

# BACT-PSD PM10 GR/DSCF Emission Limits

MIN 0.0014 GR/DSCF MAX 0.0052 GR/DSCF MEDIAN 0.0018 GR/DSCF
COUNT 10 CASES

Melt Shop RBLC PM BACT Limits Summary 

# BACT-PSD PM GR/DSCF Emission Limits

MIN 0.0015 GR/DSCF MAX 0.0052 GR/DSCF MEDIAN 0.0018 GR/DSCF
COUNT 5 CASES

Melt Shop RBLC PM F ilterable BACT Limits Summary 

# BACT-PSD PM Filterable gr/dscf Emission Limits

MIN 0.0018 GR/DSCF MAX 0.0018 GR/DSCF MEDIAN 0.0018 GR/DSCF
COUNT 3 CASES

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# RBLC data for LMFs was not included in this an alysis as some of the reported limits were not

consistent with emissions from the entire melt shop whereas EA F and melt shop limits were
consistent with total melt shop emissions.

For periods of startup and shutdown, Minnesota Steel will put EAF particulate emission control
equipment into service prior to commencing operation of process equipment, and keep controls operating
until the process is shut down and off line. No excess emissions will occu r as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 9.4 EAF Visible Emissions

Visible emissions are the result of particulate materials generated as a result of the steel making process.



# 9.4.1 EAF Visible Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

For EAF and melt shop sources, PM/PM 10 

# emissions are controlled by fabric filters (baghouses).

A 3% opacity limit is recommended as BACT for visibl e emissions from EAF and melt shop operations.
i.e. the average opacity of EAF baghouse exhaust cannot exceed 3% for more the one 6-minute period
during an hour. If Minnesota Steel identifies visible emissions from an EAF bagh ouse of 3%, it will take
corrective action as soon as it is practicable to do so. An opacity limit of 3% is consistent with recent

RBLC determinations for EAF and melt shop sources as shown in the table below.

EAF & Melt Shop RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 3 % Opacity MIN 3 % Opacity MAX 6 % Opacity MAX 20 % Opacity MEDIAN 3 % Opacity MEDIAN 6 % Opacity
COUNT 10 CASES COUNT 10 CASES



# See Attachment L, Table L-47 for a detailed listing of recent RBLC opacity determinations for EAF and
melt shop baghouse exhaust streams. Table L-48 has RBLC opacity determinations for LMFs.

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# 9.5 EAF Sulfur Dioxide (SO 2 

# ) Emissions

SO 2 

# emissions are generated from the sulfur content in the charge to the EAF. The charge is direct
reduced iron (DRI), injection carbon, charge carbon , metal alloy and chemical additions made during
the ladle metallurgy processes, all of which have varying sulfur content. The sulfur entering the
exhaust stream may be oxidized to form SO 2 

# in the presence of heat from the EAF or LMF and
oxygen from ambient air.



# 9.5.1 Identification of Potential SO 2 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various SO 2 

# control technologies are discussed in

Section 4.0 and Table 9-3. Pote ntial control technologies for SO 2 

# emissions are the following:

• Wet Scrubber

• Spray dryer Absorption

• Wet Electrostatic Precipitator

• Dry Sorbent Injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design Methods and Operating Practices



# 9.5.2 Elimination of Te chnically Infeasible SO 2 

# Control Options

Table 9-3 summarizes the technical feasibility of potential SO 2 

# control technologies. Details
regarding the technologies that are not feasib le are provided in the subsequent sections.

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## Table 9-3 Technical Feasibility of SO 2 

## Control Technologies for the Melt Shop

SO2 Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with SO 2 

## and removes it. No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with SO 2 

## and removes it. A fabric filter is used to collect the spent sorbent. No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for SO 2 

## removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For SO 2 

## removal, caustic is added to the water spray system, allowing the spray system to function as an SO 2 

## absorber. No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. SO 2 

## reacts with sorb ent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology No

Clean Fuel/ Good Combustion Practices (Base Case) Natural gas will be used as fuel for the EAF Yes

Good Design Methods and Operating Practices Use low sulfur carbon for carbon injection to minimize SO 2 

## emissions.

Use foaming slag 

# process. B asic material, such

as lime in the foaming slag froth scrubs SO 2



## . Yes



## Flue Gas Desulfurization


# Due to the expected low concentrations of SO 2 

# (~5 ppm) in the melt shop exhaust gas stream and the

variable flow conditions 5 

# , the addition of a FGD system is technically infeasible including wet
scrubbers (absorbers), spray dryer absorption, Wet ESP’s and dry sorbent injection. Minnesota Steel

is not aware of a steel mill where FGD has been installed to control SO 2 

# emissions from an EAF. No

recent BACT determinations ha ve identified add-on FGD as a viable control method. See

Attachment L Table L-6 for recent BACT determinations for SO 2 

# emissions from EAFs.

5 

## See Section 9.5 of this report for information on EAF operating conditions.

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# 9.5.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness
The remaining SO 2 

# control technologies applicable to the melt shop are ranked by control

effectiveness in Table 9-4.

Table 9-4 Ranking of Remaining SO 2 

## Control Technologies for Melt Shop

SO 2 

## Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent Control

2 Good Design Methods and Operating Practices NA Inherent Control



# 9.5.4 Evaluation of Most Effective SO 2 

# Control Technologies

Table 9-5 Evaluation of Most Effective SO 2 

## Control Technology for Melt Shop
Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent Control NA Inherent

Control NA NA

2 Good Design Methods and Operating Practices NA Inherent Control NA Inherent

Control NA NA



# Due to the cyclic nature of the flow from the EAF, add-on controls for SO 2 

# removal are not feasible.
Analysis of the RBLC indicates that the steel mills listed in Attachment L Table L-6 do not have addon devices to control SO 2 

# emissions from EAFs. Instead, clean fuels and good design methods and
operating practices are used. Sulfur in the charge carbon and scrap steel is oxidized in the EAF to

form SO 2 

# . So, minimizing the amount of su lfur in these streams minimizes SO 2 

# emissions. Good
design and operating practices often include low sulfur charge carbon and scrap metal to reduce SO 2 

# emissions. Foaming slag is also used to minimize SO 2 

# emissions. Limestone and other basic

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# compounds in the slag can capture some of the SO 2 

# released in the EAF. Minnesota Steel uses only
clean outside scrap metal (“bushling”) as EAF charge material during cold restarts.



# 9.5.5 EAF SO 2 

# BACT Selection

Because clean fuels such as low sulfur carbon and good combustion practices are the only feasible SO 2 

# control option and are routinely selected as BACT , Minnesota Steel proposes the use of combustion
controls to be BACT. Minnesota Steel proposes BACT limits of 0.15 lb SO 2 

# /ton of liquid steel produced
on a 30 operating day rolling average basis and mass emission rate limit of 33 lb/hr SO 2 

# on a 3 hour basis
for each melt shop. The proposed BACT limit is base d on sulfur balance data for EAFs. A comparison
of the proposed limit with RBLC listings for EAFs a nd melt shops shows that the proposed limit of 0.15

lb SO 2 

# per ton of steel is consistent the maximum achi evable emissions reductions as demonstrated by the

fact that it is:

• 

# Equal to the minimum BACT SO 2 

# limit of recent BACT determinations

• 

# Based on emission controls consistent with recent BACT determinations

The statistical analysis of RBLC data was performed on a set of 26 emissions limits for EAFs and melt
shops. A table summarizing the statistical analys is and a frequency distribution of 23 BACT emission
limits from the RBLC is shown below. Ladle Metallurgical Furnace (LMF) determinations from the
RBLC were not included in this analysis because the da ta suggest that the LMF determinations were only

for LMFs and did not include EAF emissions.

MS and EAF RBLC SO 2 

# and SO x 

# BACT Limits Summary

BACT-PSD SO 2 

# and SO x 

# lb/t steel Emission Limits

MIN 0.15 lb/t steel

MAX 2.00 lb/t steel

MEDIAN 0.35 lb/t steel

12th PERCENTILE 0.20 lb/t steel

COUNT 23 CASES

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# Attachment L, Tables L-5, 12 and 20 contain summaries of SO 2 

# BACT determinations for EAF, LMF
and melt shop operations from the EPA RBLC data base. Combined EAF and melt shop data are in

Attachment L, Table 43.

RBLC data for LMFs was not included in this an alysis as some of the reported limits were not

consistent with emissions from the entire melt shop whereas EAF and MS limits were co nsistent with
total melt shop emissions.

A thirty operating day rolling average is propose d for the BACT performa nce limit due to the
variability of emissions on a daily basis. The chart below shows the highest 24 hour average lb/hr

SO 2 

# emission rate vs. the 30 day average SO 2 

# emission rate on a lb/ton st eel basis for a six month
period. The data is from a steel mill recently listed in the RBLC. The 99% confidence interval for
the 30 day average lb SO 2 

# /ton steel produced is similar to the proposed BACT limit.

EAF SO2 Mass Emissions Rate - NUCOR Steel (RBLC ID NY-0094)

0 2 4 6 8 10 12 14 16

7/2/2006 8/21/2006 10/10/2006 11/29/2006

DateDaily Max 24-hr Rolling Avg SO2 Emission Rate (lb/hr)

0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.1630-day Rolling Avg SO2 Emission Rate (lb/ton)

Max 1 hr of 24 hour rolling average (lb/hr) 30 day rolling average (lb/ton) Facilty Down

99% Confidence Interval 2.7 lb/hr 99% Confidence Interval 13.5 lb/hr

99% Confidence Interval 0.07 lb/ton 99% Confidence Interval 0.14 lb/ton



# The facility that this data comes from has a much smaller capacity and therefore the lb/hr data cannot
be directly applied to Minnesota Steel.

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# The proposed limit is based on operating days so th at the average emission rate is not aversely
affected by periods when steel is not being produ ced. An operating day is a calendar day in which
the EAF is operating for at least 18 hours.

Periods of Startup, Shutdown and Malfunction

Startup and shutdown periods only include the initia l startup of the EAF and startup and shutdowns
associated with significant events like the annual maintenance shutdown. Startup and shutdown

emissions associated with routine maintenance will be included in the 30-operating day average. For
periods of startup and shutdown, Minnesota Steel will utilize the same fuel (natural gas) and the same
additives (limestone and charge carbon) it uses during normal operations. The initial charge to the EAF
will include clean steel scrap and/or DRI pellets.

Therefore, SO 2 

# emissions during startup and shutdown will be consistent with normal operations with the
following exceptions:

• 

# Additional time and energy will be needed to melt the initial charge because the steel heel, which is
present under normal operations, must be formed during startup.

• 

# Reduced production rates during startup and shutdown may result in higher lb SO 2 

# /ton steel emission
rates than occur during normal operation.

Until the EAF reaches the proper operating condi tions, Minnesota Steel cannot comply with the
BACT limits for normal operation due to the reas ons noted above. Therefore, Minnesota Steel
proposes “Good Air Pollution Control Practices for Minimizi ng Emissions” and li miting emissions to
the rates Attachment M, Table 1 as BACT during startup and shutdown. Good operating practices

will include:

• 

# Operation of the EAF in a manner which minimize s the amount of time ea ch EAF is operates
with scrap metal feed in order to establish li quid metal levels in the EAF prior to commencing
DRI pellet feed.

Minnesota Steel will define good operating practices fo r minimizing emissions in its startup, shutdown
and malfunction plan. As noted in Section 4.8, pl ans for startup, shutdown and malfunction will follow
all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.

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# 9.6 EAF Nitrogen Ox ides (NOx) Emissions

Thermal NO
x 

# is formed by the high operating temperatur es of the EAF. Mo lten steel is 2,700°F -
3100°F. At these temperatures NO
x 

# formation will occur from oxidation of atmospheric nitrogen
when it comes in contact with the thermal energy from the hot steel, electric arcs and hot gases used

to refine the steel. Thermal NO
x 

# is generated by the oxy-fuel burners when they are used to heat the
EAF. Natural gas use in the EA F burners has minimal fuel bound to nitrogen; eliminating fuel bound

NO
x 

# as a source of NO
x 

# emissions.



# 9.6.1 Identification of Potent ial NOx Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various NO
x 

# control technologies are discussed in

Section 4.0 and Table 9-6. Pote ntial control technologies for NO
x 

# emissions are the following:

• Low Temperature Oxidation

• Selective Catalytic Reduction

• Selective Non-Catalytic Reduction

• Non-selective Ca talytic Reduction

• External Flue Gas Recirculation

• Low-NOx Burners and Induced Flue Gas Recirculation Burners

• Oxy-fuel Burners

• Low Excess Air (LEA)

• Other Combustion Controls

• Good Design Methods and Operating Practices



# 9.6.2 Elimination of Technically Infeasible NOx Control Options

Table 9-6 summarizes the technical feasibility of potential NO
x 

# control technologies. Additional

details are discussed for those technologies that are not feas ible in the subsequent sections.

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## Table 9-6 Technical Feasibility of NOx Control Technologies for the Melt Shop

NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Low Temperature Oxidation Low Temperature Oxidation is a process where NO x 

## is oxidized to form water soluble nitrate compounds which can easily be removed by absorption (wet scrubbing). Oxidation occurs at relatively low temperatures (100oF – 200oF) so it can be effectively used as an add-on control system where the stream to be treated is not hot enough for catalytic controls. Ozone is typically used as the oxidizing agent. No

Selective Catalytic Reduction Selective catalytic reduction (SCR) is a postcombustion NO x 

## control technology in which ammonia (NH 3 

## ) is injected into the flue gas stream in the presence of a catalyst. SCR requires a temperature range of 500 ° F – 800 ° F. No

Selective Non-Catalytic Reduction The Selective non-catalytic reduction (SNCR) process injects urea or ammonia-based chemicals into the flue gas stream to convert NO to N 2 

## and water. The optimum operating temperature for SNCR is 1,600 ° F to 2,000 ° F. No

Non-Selective Catalytic Reduction Non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NO x 

## and CO react in the presence of NSCR catalyst to form nitrogen (N 2 

## ) and carbon dioxide (CO 2 

## ). It is typically employed in clean gas services such as natural gas fired turbines. No

External Flue Gas Recirculation External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures. In an external flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air and this mixture is introduced into the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x 

## . No

Low-NOx Burners and Induced Flue Gas Recirculation Burners Low-NO x 

## burner (LNB) technology utilizes advanced burner design to reduce NO x 

## formation through the restriction of oxygen, flame temperature, and/or residence time.

Induced flue gas recirculation burners are designed to draw flue gas into the burner to dilute the fuel. This reduces flame temperature and NO x 

## formation. No

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## NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Oxy-fuel Burners Oxy-fuel burners burn a blend of natural gas and pure oxygen. Oxy-fuel combustion removes nitrogen from the combustion zone where most NO x 

## is formed, and substantially reduces fuel consumption as well. Yes

Low Excess Air (LEA) Low Excess is a combustion control method which is used to reduce the amount of oxygen in the combustion zone of a furnace or boiler. This limits the amount of oxygen available for NO x 

## formation. No

Other Combustion Controls These combustion control methods are typically employed on existing sources. They inexpensive, but have limited control efficiencies. Combustion controls incl ude Overfire Air (OFA), Burners Out of Servic e (BOOS) and Load Reduction and Reduced Combustion Air Temperature. No

Good Design Methods and Operating Practices EAF roof 4 th 

## hole ventilated by Direct-shell Evacuation Control system (DEC). This system minimizes air infiltration and reduces the amount of nitrogen available for NO x 

## formation inside the EAF

Use of foaming slag insulates and seals the surface of molten steel in the EAF. The reducing the potential for oxidation of nitrogen by the molten steel. Yes



# As noted above, variability in EAF operating condit ions is a principle con cern in application of NO
x 

# controls. This issue is documented in the paper 6 

# Infeasibility of Non-se lective Catalytic Reduction
(SNCR) for Control of NOx Emissions from an Electric Arc Furnace . In the example presented in
Figure 2 (on the page numbered 622) of the articl e, EAF exhaust flow rates vary from 150,000 acfm
to 400,000 acfm in a period of 5 minutes. Figure 5 shows that NO
x 

# concentrations are also highly
variable; concentrations range from 65 ppm to 5 ppm in a period of 5 minutes. This rate of change in

flow rate and NO
x 

# concentrations makes the use of add on controls infeasible because of the
difficulty in controlling reagent injection rates to match process flow rates and NO
x 

# concentrations.

6 

## “Infeasibility of Non-selective Catalytic Reduction (SNC R) for Control of NOx Emissions from an Electric Arc Furnace” is a paper written by Wesselmand, Rahu and Aski ns; it was presented at the 2005 AISTech convention.

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# Another issue which affected the viability of NO
x 

# controls is the low concentration of NOx in the
EAF exhaust. The initial exhaust stream from the EAF is very hot (2,400°F) and the temperature is
variable. It also has high levels of partic ulate matter, which would adversely affect NO
x 

# catalysts.
So, the particulates must be cleaned from the EAF exhaust gas before it would be feasible to employ
catalytic NO
x 

# controls, which requires that the temperature of the exhaust gas stream be less than
400°F for baghouse control. From the EAF, air is injected into the exhaust gas for oxidation of CO
and VOCs. Water cooling drops the temperature of the gas to approximately 1,200°F. The EAF
exhaust gas stream is then diluted with ot her gas streams from the canopy hood and the ladle
metallurgical furnace for cooling. The dilution streams are near ambient temperature and have a
combined flow rate of more than 4 times the flow rate of the EAF exhaust gas. Therefore, after the
addition of cooling air, the NO
x 

# concentration is in the baghouse ex haust is too low for effectively

control.

Conventional heat exchangers are not feasible to cool the EAF e xhaust gas stream because of the
high particulate content. The pa rticulates would deposit in the heat exchange equipment, which
could cause plugging, fouling, and inefficient heat recovery. Boiler operation is infeasible because
the gas stream is too hot and the temperature vari ability causes problems with control of the steam
production.

As indicated in Attachment L, Table L-7, the RBLC Database shows the add-on NOx controls (SCR,
NSCR, SNCR and LTO) have not been selected as BACT to control NO
x 

# emissions from melt shops.

Therefore, based on the technical reasons discussed a bove, and the fact that add on controls have not
been installed on EAFs; Minnesota Steel Industries concludes that it is not technically feasible to
apply SCR, NSCR, SNCR or LTO to the melt shop.

Selective Catalytic Reduction (SCR)


# The relatively high particulate c oncentrations present in the melt shop’s exhaust ga s stream would
cause several operating issues with the applicati on of SCR directly downstream of the EAF. The
potential problems include cataly st poisoning, fouling, and maski ng of the SCR system. Catalyst
poisoning results when particulates in the exhaust gas stream react with and contaminate the catalyst.
Fouling occurs when the cell openings of the catalyst are plugged with a solid material. Masking
occurs when the cell openings of the catalyst are plugged with residues that pr event their contact with
the exhaust gas. In addition, the variable flow rates and off gas temperatures from the EAF make
operation of the SCR infeasible.

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# Consequently, it would be necessary to place the SCR system downstream of the particulate control
device (baghouse) because of po tential poisoning, masking, and f ouling problems. Placing a SCR
unit downstream of a particulate control device would be unacceptable because:

1. NO
x 

# concentrations at the baghouse exhaust ar e in the 10 ppm to 15 ppm range. The
concentration is too low for SCR catalyst to remove any significant amount of NO
x 

# .

2. Exhaust gas temperatures are below 250oF. The application of SCR requires uniform gas
temperatures between 600 ° F and 850 ° F for effective catalytic reduction. Reheating such a
large volume of gas is cost prohibitive.

3. Since the EAF will operate in a batch mode, the temperature and the NO
x 

# concentration of
the exhaust gas will vary widely over the melt cycle. Constantly changing flow rates and
temperature would make ope ration of SCR infeasible.

In view of the above limitations, SCR is not te chnically feasible to a pply at the melt shop.

Non-Selective Catalytic Reduction (NSCR)


# In order for NSCR to operate properly, the combustion process must be near stoichiometric. Steel
making in an EAF is not a steady state process with respect to available fuel (CO), nor is it a near
stoichiometric operation. In addition, catalyst poisoning trace metals present in the charge to the
EAF are a potential problem with NSCR systems. Additionally, wh en the gas stream is hot enough
to operate NSCR (before the PM controls); the PM concentrations are too high. After the PM
controls, the gas temperature is too lo w. Finally, the concentration of NO
x 

# at the exhaust of the
baghouse on the EAF is too low to achieve effectiv e control using NSCR. NSCR can not reduce NO
x 

# concentrations below the 15ppm expected to be in the exhaust. For th ese reasons, NSCR is not
technically feasible.

Selective Non-Catalytic Reduction (SNCR)


# SNCR provides effective NO
x 

# control for operations in which the NO
x 

# concentration and temperature
are relatively stable. The melt shop operates in batch mode whic h result in short bursts of NO
x 

# in
high concentrations followed by extended periods of low concentrations. The temperature of the
EAF exhaust gas will vary widely during the melt cycl e so it would be difficult, if not impossible, to
inject ammonia or urea at the proper temperatures. The time that EAF exhaust gas is at the SNCR
temperature window is too short for effective NO
x 

# control. The water cool ed duct on the outlet of the

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# EAF is the only part of the process which is at the proper operating temperature for SNCR. As
shown in Figure 7 of the article in Attachment M, residence time in the water cooled duct at SNCR
reaction temperatures is only 0.25 s econds. This is insufficient time for the SNCR reactions to occur
at rate which is effective in controlling NO
x 

# emissions. In view of these operating conditions, SNCR
is not technically feasible.

Low Temperature Oxidation (LTO)


# Although LTO is suited to the temp eratures downstream of the melt shop baghouse, it is infeasible

because:

1. NO
x 

# concentrations at the baghouse exhaust ar e in the 10 ppm to 15 ppm range. The

concentration is too low for LTO to remove any significant amount of NO
x 

# .

2. Since an EAF operates in a batch mode, the temperature, flow rate and NO
x 

# concentrations of
the exhaust gas will vary widely over the melt cycle. Constantly changing flow rates,
temperatures and NO
x 

# concentrations will make it difficult to maintain proper reagent
addition rates, and to keep the HNO 3 

# absorber operation stable.

External Flue Gas Recirculation


# External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame
temperatures. The flue gas is mixed with the combustion air. The lower oxygen level in the
combustion zone reduces flame temper ature; which in turn reduces NO
x 

# . This technology is not
feasible under normal operating conditions. The EAF exhaust is heavily loaded with particulates
which would plug the burners if recycled for EFGR. In addition, this type of emission control system
would not be feasible to operate du e to the difficulty of maintaining the proper flue gas dilution ratio
as the auxiliary burners only operate for short peri ods and flow rates can fl uctuate rapidly during the
EAF operational cycles.

Low-NO x 

## Burners and Induced Flue Gas Recirculation Burners 

# EAF operation requires extremely hi gh operating temperatures. Molten steel in the EAF is 2,700°F -
3100°F. Under these conditions, high flame temperat ures are required to meet the temperature
requirements of the EAF. Low NO
x 

# burners work by reducing peak flame temperatures; so, they

loose NO
x 

# control effectiveness in high temperature applications. Oxyfuel burner technology is
typically employed in these applic ations. Oxyfuel burners provide NO
x 

# emissions control by

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# substituting pure oxygen for combustion air. This significantly reduces the introduction of
atmospheric nitrogen into the EAF where it can form NO
x 

# .

Low Excess Air (LEA)



# Low Excess Air is a combustion control method which is used to reduce the amount of oxygen in the

combustion zone of a furnace or boiler. This limits the amount of oxygen available for NO
x 

# formation. This is not feasible at the EAF since oxygen is injected into the EAF as part of the steel
manufacturing process.

Other Combustion Controls



# There are other combustion control methods typically employed on ex isting sources such as utility
boilers. They are inexpensive, but have limited control efficiencies. Other combustion controls
include Overfire Air (OFA), Burners Out of Service (BOOS) and Load Reduction and Reduced
Combustion Air Temperature. EAF operation is not a normal external combustion device such as a
boiler and therefore these types of controls are not suitable for use on an EAF, and are considered
technically infeasible. For example, an EAF does not have an enclosed combustion air system where
combustion air is preheated. So it is not fe asible to reduce the combustion air temperature.



# 9.6.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness
The remaining control technologies applicable to the melt shop are ranked by control effectiveness in

Table 9-7:

Table 9-7 Ranking of Remaining NO x 

## Control Technologies for Melt Shop

NOx Control Technology Ranking

Rank Technology Estimated % Control
Efficiency

1 Oxy-fuel burners NA

Inherent Controls

2 Good Design Methods and Operating Practices NA

Inherent Controls

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# 9.6.4 Evaluation of Most Effe ctive NOx Control Technologies

Due to the cyclic nature of the flow from the EAF, add-on controls for NO
x 

# removal are not feasible,
but combustion controls represent a tec hnically feasible means of reducing NO
x 

# emissions. An
analysis of recently established BACT selecti ons based on a review of the RACT/BACT/LAER
Clearinghouse (RBLC) database indicates that the st eel mills listed in Appendix L, Table L-7 do not

have add-on devices to control NO
x 

# emissions from EAFs. Instead, oxy-fuel burners and Direct-shell
Evacuation Controls (DEC) lead to acceptable NO
x 

# emissions. Since these are inherent to the
process, the cost has already been incurred.

Table 9-8 Evaluation of Most Effective NOx Control Technologies for Melt Shop

NOx Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Oxy-fuel burners NA

Inherent Controls NA

Inherent Controls NA NA

2 Good Design Methods and Operating Practices NA

Inherent Controls NA

Inherent Controls NA NA



# 9.6.5 EAF NOx BACT Selection

Because oxy-fuel burners and the Direct-shell Evacu ation Control system (DEC) are the only feasible
NOx control options and are routinely selected as BA CT for EAFs, Minnesota Steel considers the use of

combustion controls to be BACT. Minnesota Steel proposes BACT limits of 0.26 lb NOx/ton of liquid
steel produced on a 30 operating day average basis and a mass emission rate limit of 53 lb/hr NOx for
each melt shop on a 24 hour average basis.

The proposed BACT limit is based on the NO
x 

# BACT limit for Nucor Auburn Steel (RBLC ID NY0094). Nucor has a NO
x 

# BACT of 0.27 lb/t steel, 30-day rolling average. This emission limit is also

consistent with vendor data for EAFs equipped with BACT emission controls. A comparison of the
proposed limit with RBLC listings for EAFs and melt s hops shows that the proposed limit of 0.26 lb NOx
per ton of steel is consistent the maximum achievab le emissions reductions as demonstrated by the fact

that it is:

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## • 

# Less than the median of recent BACT determinations

• 

# Within the top half of the upper quartile (top 12%) of recent PSD permits.

• 

# Based on emission controls consistent with recent BACT determinations

• 

# It is consistent with NO
x 

# emission limits which have been demonstrated in practice by a facility

with a recent BACT determination. This f acility demonstrates compliance by continuous
emissions monitoring; so, the data are more reliable than a single stack test.

By setting BACT within the top half of the upper qua rtile of recent BACT determinations, the proposed
BACT limit will guarantee that the Minnesota Steel facility’s emissions control performance will be
consistent with the best performing units, while providi ng a small allowance for variations in site specific
operating conditions. The statistical analysis of RBL C data was performed on a set of 26 emission limits
for EAFs and melt shops. A table summarizing the statis tical analysis and a frequency distribution of 25
BACT emission limits from the RBLC is shown below. Ladle Metallurgical Furnace (LMF)

determinations from the RBLC were not included in th is analysis because the data suggest that the LMF
determinations were only for LMFs and did not include EAF emissions. Attachment L, Table L-6
contains a summary of NO
x 

# BACT determinations for EAF ope rations from the EPA RBLC database.

EAF and MS RBLC NOx BACT Limits Summary
BACT-PSD NOx lb/t

Emission Limits Other (non-BACT)-case-bycase NOx lb/t Emission Limits

MIN 0.20 NOx lb/t Steel MIN 0.36 NOx lb/t Steel

MAX 1.00 NOx lb/t Steel MAX 0.36 NOx lb/t Steel

MEDIAN 0.36 NOx lb/t Steel MEDIAN 0.36 NOx lb/t Steel
COUNT 25 CASES COUNT 1 CASES

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# RBLC NOx BACT limits
EAF & MS

0 1 2 3 4 5 6 7 8 9

0.2 0.25 0.3 0.35 0.4 0.45 0.5 0.55 > 0.55

Emission limit (lb NOx / T liquid steel produced)Frequency 

## Proposed BACT
Limit 0.26



# Barr Engineering Co. was able to contact representatives of CF&I Steel (RBLC ID CO 0045) and
Republic Technologies (RBLC ID OH-0245 [b]). Neith er facility was able to comply with the NO
x 

# BACT limits listed in the RBLC. CF&I is currently seeking a higher NO
x 

# limit. Republic Technologies
received a higher NO
x 

# limit after it could not meet the lb/hr limit for EAF #7; this limit is equivalent to

0.1 lb NO
x 

# per ton steel produced. Nucor Auburn Steel (RBLC ID NY-0094) has a NO
x 

# BACT of 0.27
lb/t steel, 30-day rolling average which it complies with . The 99% confidence interval for NOx emissions
from actual operations at Nucor for the period 7/1/2007 – 9/26/2007 is equal to the proposed BACT limit

as can be seen on the chart below.

Attachment L, Tables L-6, 13 and 21 contain summaries of NO
x 

# BACT determinations for EAF,
LMF and melt shop operations from the EPA RBLC database. Combined EAF and melt shop data are

in Attachment L, Table 44.

RBLC data for LMFs was not included in this an alysis as some of the reported limits were not

consistent with emissions from the entire melt shop whereas EAF and MS limits were co nsistent with
total melt shop emissions.

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### EAF NOx Mass Emission Rate - NUCOR Steel (RBLC ID NY-0094)

0 5 10 15 20 25

7/2/2006 8/21/2006 10/10/2006 11/29/2006

DateDaily Max 24-hr Rolling Avg NOx Emission Rate (lb/hr)

0 0.05 0.1 0.15 0.2 0.25 0.330-day Rolling Avg NOx Emission Rate (lb/ton)

Daily Max of 24 hour rolling average (lb/hr) 30 day rolling average (lb/ton) Facilit y Down

99% Confidence Interval 7.9 lb/hr 99% Confidence Interval 22.4 lb/hr

99% Confidence Interval 0.16 lb/ton 99% Confidence Interval = 0.26 lb/ton for the period 7/1/07 - 9/26/07



# A thirty operating day rolling average is propose d for the BACT performa nce limit due to the
variability of emissions on a daily basis. The chart on the previous page shows the highest 24 hour
average lb/hr NO
x 

# emission rate vs. the 30 day average NO
x 

# emission rate on a lb /ton steel basis for a
six month period.

The proposed limit is based on operating days so th at the average emission rate is not aversely
affected by periods when steel is not being produ ced. An operating day is a calendar day in which
the EAF is operating for at least 18 hours. The facility that this data is from is much smaller and
therefore the lb/hr emission rates cannot be directly applied to Minnesota Steel.

Startup and shutdown periods only include the initia l startup of the EAF and startup and shutdowns
associated with significant events like the annual maintenance shutdown. Startup and shutdown
emissions associated with routine maintenance will be included in the 30-operating day average.

For periods of startup and shutdown, Minnesota Steel will utilize the same fuel (natural gas) and the same
additives (limestone and charge carbon) it uses during nor mal operations. The initial charge to the EAF
after weekly and annual maintenance outages will incl ude about 50% clean steel scrap followed by the

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# addition of DRI pellets. Therefore, NO
x 

# emissions during startup and shut down will be consistent with
normal operations with the following exceptions:

• 

# Additional time and energy will be needed to melt the initial charge because the steel heel, which is
present under normal operations, must be formed during startup.

• 

# Reduced production rates during startup and shutdown may result in higher lb NO
x 

# /ton steel emission
rates than occur during normal operation.

Until the EAF reaches the proper operating condi tions, Minnesota Steel cannot comply with the
BACT limits for normal operation due to the reas ons noted above. Therefore, Minnesota Steel
proposes “Good Air Pollution Control Practices for Minimizi ng Emissions” and li miting emissions to

the rates Attachment M, Table 1 as BACT durin g startup and shutdown. Good operating practices

will include:

• 

# Operation of the EAF in a manner which minimize s the amount of time ea ch EAF is operates
with scrap metal feed in order to establish li quid metal levels in the EAF prior to commencing
DRI pellet feed.

Minnesota Steel will define good operating practices fo r minimizing emissions in its startup, shutdown
and malfunction plan. As noted in Section 4.8, pl ans for startup, shutdown and malfunction will follow
all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.



# 9.7 EAF Carbon Monoxi de (CO) Emissions

CO will be emitted as a result of incomplete combustion of natural gas in the auxiliary burners and
from incomplete oxidation of charged and injected carbon, the foaming slag operating practice, and
the graphite electrodes reacting with injected air or oxygen.



# 9.7.1 Identification of Potent ial CO Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various CO control technologies ar e discussed in Section

4.0 and Table 9-9. Potential control tec hnologies for CO emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

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# • Catalytic Oxidizer

• Good Combustion Controls

• Post Baghouse Oxidizer

• Good Design Methods and Operating Practices



# 9.7.2 Elimination of Technically Infeasible CO Control Options

Table 9-9 summarizes the technical fe asibility of potential CO control technologies for the melt shop.
Details regarding the technologies that are not feasible are discussed in the subsequent sections.

Table 9-9 Technical Feasibility of CO Control Technologies for the Melt Shop
CO Emission Control Technologie s Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize CO to CO 2


## . This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of CO at lower temperatures than a thermal incinerator. No

Post Baghouse Oxidizer A thermal or catalytic oxidizer installed downstream of the EAF Baghouse. Installed after the baghouse, an oxidizer would not be subject to the problems caused by high particulate loading off the EAF. No

Good Combustion Controls Good combustion control limits the formation of CO by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes (oxy-fuel burners)

Good Design Methods and Operating Practices 

## A 4 th 

## hole EAF roof exhaust vented to Direct-shell Evacuation Control (DEC) system which includes air injection for CO oxidation.

Particulate “drop out” box” provides additional residence time for CO oxidation. Yes

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## Thermal Oxidizer


# Due to the high level of particulates present in the EAF exhaust gas, a thermal oxidizer is not
technically feasible. The heavy particulate loading and variable EAF operating conditions present
the following problems:

1. Variable flow, temperature and CO concentrations will make oxidizer temperature and fuel

flow control difficult.

2. Oxidizer burners will become fouled with particulate matter, and will either not work or
require excessive maintenance.

3. Particulates will foul heat reco very devices and cause excessive pressure drops and fuel use.
Without heat recovery, a thermal oxidizer woul d require and inordinate amount of fuel.

Catalytic Oxidizer


# Due to the high level of particulates present in the EAF exhaust gas, a catalytic oxidizer is not
technically feasible. The heavy particulate loading and variable EAF operating conditions present
the following problems:

1. Variable flow, temperature and CO concentrations will make oxidizer temperature and fuel

flow control difficult.

2. Oxidizer burners will become fouled with particulate matter, and will either not work or
require excessive maintenance.

3. EAF particulates will foul catalyst beds a nd heat recovery device s and cause excessive
pressure drops and fuel use. Potential probl ems include poisoning, deactivation, and/or
blinding of the catalyst. Lead, arsenic, vana dium, and phosphorous ar e generally considered
poisons to catalysts and deactivate the available reaction sites on the catalyst surface.
Particulate emissions can also effectively bloc k the porous catalyst a nd render the catalyst

inactive.

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## Post Baghouse Oxidizer



# Installation of an oxidizer downstream of the EAF baghouse presents the following problems:

1. CO concentrations will be diluted by other ve ntilation air fl ows from the melt shop, rendering

oxidation controls ineffective.

2. Baghouse controls require relatively low operating temperatures (200 oF – 400 oF). The low
temperature of the baghouse exhaust plus the larg e volumes of air in this stream w ould require
2.4 billion cubic feet per year of natural gas to operate the oxidizer (one for each EAF). In
addition, combustion of this much natural ga s would cause 120 tons of NOx emissions per

year.



# 9.7.3 Ranking of Remaining CO Control Technologies by Control Effectiveness
The remaining control technologies applicable to the melt shop are ranked by control effectiveness in

Table 9-10.

Table 9-10 Ranking of Remaining CO Control Technologies for Melt Shop
CO Control Technology

Rank Technology Estimated RHF % Control Efficiency

1 Good Design Methods and Operating Practices 

## 90%

2 Good Combustion Controls NA
Inherent to oxy fuel burners



# 9.7.4 Evaluation of Most Effe ctive CO Contro l Technologies
The use of good design for EAFs typically includes an EAF roof exhaust vented to Direct-shell
Evacuation Control (DEC) system which includes ai r injection, via the combustion air gap, for CO
oxidation. Good designs also include particulate “drop out” boxes, which add additional residence

time for CO oxidation.

Oxy fuel burners are designed to combust a mixture of natural gas and pure oxygen. The reactants
are mixed prior to combustion ensuring complete combustion.

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# Since good design and good combustion controls are inhe rent to the process no additional cost will

be incurred.

Table 9-11 Evaluation of Most Effectiv e CO Control Technologies for Melt Shop

CO Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Design Methods and Operating Practices NA Inherent to EAF design NA Inherent to EAF design NA Inherent to EAF design NA Inherent to EAF design

2 

## Good Combustion Controls NA 

## NA Inherent to

oxy fuel burners NA NA



# 9.7.5 EAF CO BACT Selection

Minnesota Steel considers Direct-s hell Evacuation Control (DEC), wi th air injection followed by a
drop out box to be BACT for CO emissions from th e EAF. Minnesota Steel considers 2.0 lb/ton on a
30 operating day average basis to be BACT for CO emissions. These controls at the proposed

emission limit are consistent with recent BACT de terminations for CO em issions from EAFs as

shown in Attachment L, Table L-8. A mass emission rate of 410 lb/hr CO on a 8 hour average for
each melt shop is also recommended as BACT.

Attachment L, Tables L-7 and 22 contain summaries of CO BACT determinations for EAF and melt
shop operations from the EPA RBLC database. Statistical analyses of the RBLC data for EAFs are
summarized in the tables below (S ee also Attachment L, Table 45). Minnesota Steel is proposing a
CO limit of 2.0 lb CO per t on of steel produced because:

• 

# Most of the recent BACT determinations set BACT at 2.0 lb CO/ton steel produced.

• 

# The median average of recent BACT determ inations is 2.0 lb CO/ton steel produced.

• 

# The proposed BACT is within the top half of th e upper quartile (top 12%) of recent PSD permits.

• 

# The limit is based on emission controls cons istent with recent BACT determinations.

Minnesota Steel proposes a limit of 2.0 lb CO/ton steel produce d because of the large number of
units permitted at 2.0 lb CO/ton s steel produced and because this is in the top 12 percent of
determinations in the RBLC. The proposed BACT li mit is also consistent with actual emissions from
a steel mill recently listed in the RBLC as shown in the chart on the following page.

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# EAF and MS RBLC CO BACT Limits Summary

BACT-PSD CO lb/t steel Emission Limits

MIN 0.60 lb/t steel
MAX 25.22 lb/t steel
MEDIAN 2.76 lb/t steel
12th Percentile 2.00 lb/t steel

COUNT 33 CASES



# The chart below shows the highest 24 hour average lb /hr CO emission rate vs. the 30 day average CO

emission rate on a lb/ton steel basis for a six month period. The data is from a steel mill recently

listed in the RBLC. The 99% confidence interval for the 30 day average lb CO/ton steel produced is
similar to the proposed BACT limit.

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### EAF CO Mass Emission Rate - NUCOR Steel (RBLC ID NY-0094)

0 20 40 60 80 100 120 140 160 180 200

7/2/2006 8/21/2006 10/10/2006 11/29/2006

DateDaily Max of 8-hr Rolling Avg CO Emission Rate (lb/hr)

0 0.5 1 1.5 2 2.530-day Rolling Avg CO Emission Rate (lb/ton)

Daily Max of 8 hour rolling average (lb/hr) 30 day rolling average (lb/ton) Facility Down 99% Confidence Interval 1.93 lb/ton

99% Confidence Interval 0.37 lb/ton

99% Confidence Interval 13 lb/hr 99% Confidence Interval 189 lb/hr



# The facility that this data is from is much sm aller and therefore the lb/h r emission rates cannot be
directly applied to Minnesota Steel.

RBLC data for LMFs (Attachment L, Table 14) was not included in this analysis as some of the
reported limits were not consistent with em issions from the entire melt shop, whereas EAF and MS

limits were consis tent with total melt shop emissions.

A thirty operating day rolling average is propose d for the BACT performa nce limit due to the
variability of emissions on a daily basis. The chart above shows the highest 24 hour average lb/hr
CO emission rate vs. the 30 day average CO emi ssion rate on a lb/ton steel basis for a six month
period.

The proposed limit is based on operating days so th at the average emission rate is not aversely
affected by periods when steel is not being produ ced. An operating day is a calendar day in which
the EAF is operating for at least 18 hours.

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# Periods of Startup, Shutdown and Malfunction

Startup and shutdown periods only include the initia l startup of the EAF and startup and shutdowns
associated with significant events like the annual maintenance shutdown. Startup and shutdown
emissions associated with routine maintenance will be included in the 30-operating day average.

Factors affecting CO emissions during star tup and shutdown include the following:

• For the EAF air gap to effectively control CO emissions, the EAF must reach the appropriate
operating temperatures.

• Additional time and energy will be needed to melt the initial charge because the steel heel, which
is present under normal operations , must be formed during startup.

• 

# Reduced production rates during startup and shutdown may result in higher lb CO/ton steel emission
rates than occur during normal operation.

Until the EAF reaches the proper operating condi tions, Minnesota Steel cannot comply with the
BACT limits for normal operation due to the reas ons noted above. Therefore, Minnesota Steel
proposes “Good Air Pollution Control Practices for Minimizi ng Emissions” and li miting emissions to

the rates Attachment M, Table 1 as BACT durin g startup and shutdown. Good operating practices

will include:

• 

# Operation of the EAF in a manner which minimize s the amount of time ea ch EAF is operates
with scrap metal feed in order to establish li quid metal levels in the EAF prior to commencing
DRI pellet feed.

• 

# Operation of the EAF in a manner which minimize s the amount of time the EAF is operated at
temperatures that are below the oxidation temperat ure of CO during startup and shutdown of an

EAF.

Minnesota Steel will define good operating practices fo r minimizing emissions in its startup, shutdown
and malfunction plan. As noted in Section 4.8, pl ans for startup, shutdown and malfunction will follow
all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.

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# 9.8 EAF Volatile Organic Compound (VOC) Emissions

VOC will be emitted as a result of incomplete combustion in the auxiliary burners and from
incomplete oxidation of charged and injected carbon, the foaming slag operating practice, and the
graphite electrodes reacting with injected air or oxygen.



# 9.8.1 Identification of Potent ial VOC Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous VOC control technologi es are discussed in

Section 4.0 and Table 9-12. Potential control t echnologies for VOC emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Post Baghouse Oxidizer

• Good Design Methods and Operating Practices



# 9.8.2 Elimination of Technically Infeasible VOC Control Options

Table 9-13 summarizes the technical feasibility of potential CO c ontrol technologies for the melt
shop. Details regarding the technologies that ar e not feasible are discussed in the subsequent

sections.

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## Table 9-12 Technical Feasibility of VOC Control Technologies for the Melt Shop
VOC Emission Control Technologies Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize VOC to CO 2 

## and water. This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of VOC at lower temperatures than a thermal incinerator. No

Post Baghouse Oxidizer A thermal or catalytic oxidizer installed downstream of the EAF Baghouse. Installed after the baghouse, an oxidizer would not be subject to the problems caused by high particulate loading off the EAF. No

Good Combustion Controls Good combustion control limits the formation of VOC by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes (oxyfuel burners)

Good Design Methods and Operating Practices 

## A 4 th 

## hole EAF roof exhaust vented to Direct-shell Evacuation Control (DEC) system which includes air injection for VOC oxidation.

Particulate “drop out” box” provides additional residence time for VOC oxidation. Yes

Thermal Oxidizer


# Due to the high level of particulates present in the EAF exhaust gas, a thermal oxidizer is not
technically feasible. The heavy particulate loading and variable EAF operating conditions present
the following problems:

1. Variable flow, temperature and VOC concentrations will make oxidizer temperature and fuel

flow control difficult.

2. Oxidizer burners will become fouled with particulate matter, and will either not work or
require excessive maintenance.

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# 3. Particulates will foul heat reco very devices and cause excessive pressure drops and fuel use.
Without heat recovery, a thermal oxidizer woul d require and inordinate amount of fuel.

Catalytic Oxidizer


# Due to the high level of particulates present in the EAF exhaust gas, a catalytic oxidizer is not
technically feasible. The heavy particulate loading and variable EAF operating conditions present
the following problems:

1. Variable flow, temperature and VOC concentrations will make oxidizer temperature and fuel

flow control difficult.

2. Oxidizer burners will become fouled with particulate matter, and will either not work or
require excessive maintenance.

3. Particulates will foul catalyst beds and heat recovery devices and cause excessive pressure
drops and fuel use. Potential problems include poisoning, deactivation, and/or blinding of the
catalyst. Lead, arsenic, vanadium, and phos phorous are generally considered poisons to
catalysts and deactivate the available reaction sites on the catalyst surface. Particulate
emissions can also effectively block the porous catalyst and render the catalyst inactive.

Post Baghouse Oxidizer



# Installation of an oxidizer downstream of the EAF baghouse presents the following problems:

1. VOC concentrations will be diluted by other ventilation air flows from the melt shop
rendering oxidation controls ineffective.

2. Baghouse controls require relatively low operating temperatures (200 oF – 400 oF). The low
temperature of the baghouse exhaust plus the large volumes of air in this stream would
require 2.4 billion cubic feet per year of natu ral gas to operate the oxidizer (one for each
EAF). In addition, combustion of this much natural gas would cause 120 tons of NOx
emissions per year.



# 9.8.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness
The remaining control technologies applicable to the melt shop are ranked by control

effectiveness in Table 9-13.

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## Table 9-13 Ranking of Remaining VOC Control Technologies for Melt Shop
VOC Control Technology

Rank Technology Estimated RHF % Control Efficiency

1 Good Design Methods and Operating Practices 

## 90%

2 Good Combustion Controls NA Inherent to oxy fuel burners



# 9.8.4 Evaluation of Most Effe ctive VOC Control Technologies

The use of good design for EAFs typically includes an EAF roof exhaust vented to a Direct-shell
Evacuation Control (DEC) system, which includes air injection fo r VOC oxidation. Good designs
also include particulate “drop out” boxes which additional residence time for VOC oxidation.
Oxy fuel burners are designed to combust a mixture of natural gas and pure oxygen. The reactants
are mixed prior to combustion ensuring complete combustion.

Since good design is inherent to the proces s no additional cost will be incurred.

Table 9-14 Evaluation of Most Effectiv e VOC Control Technologies for Melt Shop

VOC Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Design Methods and Operating Practices NA

Inherent Controls NA

Inherent Controls NA NA

2 

## Good Combustion Controls NA

Inherent Controls NA

Inherent Controls NA NA



# 9.8.5 EAF VOC BACT Selection

Minnesota Steel considers the Direct-shell Evacuati on Control system (DEC), with air injection by
combustion air gap followed by a drop out box to be BACT for VOC emissions from the EAF.

Minnesota Steel considers 0.13 lb VO C/ton steel to be BACT for VOC emissions. These controls at
the proposed emission limit are co nsistent with recent BACT dete rminations for VOC emissions

from EAFs as shown in Attachment L, Tables L-8 and 23. A mass em ission rate of 27 lb/hr VOC on
a 24 hour average for each melt shop is also recommended as BACT.

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# Attachment L, Tables L-8 and 23 contain summar ies of VOC BACT determinations for EAF and
melt shop operations from the EPA RBLC database. Statistical analyses of the RBLC data are

summarized in the tables below. Most of the recent BACT determinations set BACT at 0.15 lb
VOC/ton steel produced as indicate d by the median of EAF VOC limi ts. Examination of the RBLC
data shows that many of the BA CT determinations at 0.15 lb VO C/ton steel produced are the most
recent. Minnesota Steel proposes a limit of 0.13 lb VOC/ton steel produced because of the large
number of units permitted at 0.15 lb VOC/tons steel produced.

EAF RBLC VOC BACT Limits Summary 

# BACT-PSD VOC lb/t steel Emission Limits

MIN 0.030 lb/t steel MAX 0.427 lb/t steel MEDIAN 0.150 lb/t steel
COUNT 11 CASES

MS RBLC VOC BACT Limits Summary 

# BACT-PSD VOC lb/t steel Emission Limits

MIN 0.06 lb/t steel MAX 0.35 lb/t steel MEDIAN 0.14 lb/t steel
COUNT 8 CASES



# RBLC data for LMFs was not included in this an alysis as some of the reported limits were not

consistent with emissions from the entire melt shop whereas EAF and MS limits were co nsistent with
total melt shop emissions.

A thirty operating day rolling average is propose d for the BACT performa nce limit due to the
variability of emissions on a daily basis. The chart of CO emissions in Section 9.7.5 (EAF CO
BACT selection) shows the highest 24 hour averag e lb/hr CO emission rate vs. the 30 day average

CO emission rate on a lb/ton st eel basis for a six month period. VOC emissions should follow
similar patterns because VOC emissions are also the result of incomplete oxidation of fuel and
charge carbon in the EAF.

The proposed limit is based on operating days so th at the average emission rate is not aversely
affected by periods when steel is not being produ ced. An operating day is a calendar day in which
the EAF is operating for at least 18 hours.

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# Periods of Startup, Shutdown and Malfunction

Startup and shutdown periods only include the initia l startup of the EAF and startup and shutdowns
associated with significant events like the annual maintenance shutdown. Startup and shutdown
emissions associated with routine maintenance will be included in the 30-operating day average. .

Factors affecting VOC emissi ons during startup and shutdo wn include the following:

• For the EAF air gap to effectively control VOC emissions, the EAF must reach the appropriate
operating temperatures.

• Additional time and energy will be needed to melt the initial charge because the steel heel, which
is present under normal operations, must be formed during startup.

• 

# Reduced production rates during startup and shutdown may result in higher lb VOC/ton steel
emission rates than occur during normal operation.

Until the EAF reaches the proper operating condi tions, Minnesota Steel cannot comply with the
BACT limits for normal operation due to the reas ons noted above. Therefore, Minnesota Steel
proposes “Good Air Pollution Control Practices for Minimizi ng Emissions” and li miting emissions to

the rates Attachment M, Table 1 as BACT durin g startup and shutdown. Good operating practices

will include:

• 

# Operation of the EAF in a manner which minimize s the amount of time ea ch EAF is operates
with scrap metal feed in order to establish li quid metal levels in the EAF prior to commencing
DRI pellet feed.

• 

# Operation of the EAF in a manner which minimize s the amount of time the EAF is operated at
temperatures that are below the oxidation temperat ure of VOC during startup and shutdown of an

EAF.

Minnesota Steel will define good operating practices fo r minimizing emissions in its startup, shutdown
and malfunction plan. As noted in Section 4.8, pl ans for startup, shutdown and malfunction will follow
all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits

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# 9.9 EAF Fluoride (F) Emissions

Fluoride emissions may be generate d from trace amounts of fluorides in the DRI pellets, additives
and natural gas used in the EAF. The most significa nt source of fluorides in the EAF is fluorspar.
Fluorspar is used as an additive for slag form ation. Based on the nature of EAF slag, and the
temperature of the melt shop exhaus t stream, F- compounds are expected to be particulates which are
incorporated in the slag dust from the EAF.



# 9.9.1 Identification of Fluo ride Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the variou s fluoride control technologies are discussed in
Section 4.0 and Table 9-15. Because fluoride emissions from EAFs are in particulate form,
particulate control technologies will be considered for this application. Potential control
technologies for fluoride emissions are the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)

• Good Design Methods and Operating Practices



# 9.9.2 Elimination of Technically In feasible Fluoride Control Options

Table 9-15 summarizes the feasibility of potential controls for fluorides contained in particulate
matter from the EAF. Details rega rding the technologies that were de termined to be infeasible are
discussed in the subsequent sections.

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## Table 9-15 Technical Feasibility of Fluorid e Control Technologies for the Melt Shop

Fluoride Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. Yes

Wet Scrubber Wet scrubbers, remove particles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. No

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes

Good Design Methods and Operating Practices The EAF is vented to a Direct-shell Evacuation Control system (DEC). When the DEC is closed, the entire process remains covered, and 100% of the PM is collected. Due to the process variability that comes with the batch EAF, a design including a DEC offers high capture efficiency for PM. The DRI is designed to accept a continuous feed of hot DRI pellets. So opening of the EAF cover is minimized during operation. Yes

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# Electrostatic Precipitator
Since fluoride compounds in the EAF exhaust are mixe d with all the other part iculate matter in the
EAF exhaust, the general properties of the EAF exhaus t stream will govern control device feasibility.
ESP’s have proven to be unsuitable for applicatio ns involving exhaust streams with particulates
containing a high concentration of iron. The electrom agnetic properties of small charged particles of
iron compounds cause the particles to adhere very st rongly to the collection pl ates. The pa rticles are
then extremely difficult to dislodge which results in a decrease of control efficiencies for the ESP.
Since iron oxide is the predominant particulate constituent of the exhaust streams of EAFs, dry or
wet ESPs are considered technically infeasible for controlling particulate emissions from the melt
shop.



# 9.9.3 Ranking of Remaining Fluorid e Control Technologies by Control Effectiveness
The remaining control technologies applicable to the melt shop are ranked by control effectiveness in

Table 9-16.

Table 9-16 Ranking of Remaining Fluoride Control Technologies for Melt Shop

Fluoride Control Technology Ranking

Rank Technology Estimated Control Efficiency* 1 Baghouse 98% - 99+%

2 Wet Scrubber 95% - 99+%

4 Centrifugal Separation
(e.g. Cyclones) 50% - 80%

5 Inertial Separators
(Drop Out Box) < 50%

6 Good Design Methods and Operating Practices NA Inherent to EAF
operation



# Particulate control efficiencies have been used as a general indicator of the emission control
effectiveness on fluoride bearing particulates. Fluorides are present only in small quantities;
primarily when fluorspar is used in slag forma tion. Based on the Air Em ission Inventory (Appendix
3B.), stack flow rate from form GI -04, and control efficiency in the 90% to 99% range, the calculated
fluoride concentration in the EAF baghouse exhaust is 0.0001 gr/dscf to 0.00001 gr/dscf. Given the

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# low concentrations of fluoride; fluoride control efficiency may vary from the overall particulate
control efficiency



# 9.9.4 Evaluation of Most Effect ive Fluoride Cont rol Technologies

Fabric Filter


# Since fluoride compounds in the EAF exhaust are mixe d with all the other part iculate matter in the
EAF exhaust, the general properties of the EA F exhaust stream will govern control device
effectiveness. Fabric filters are technically feasible for collecting fine particulate matter containing
high concentration of iron compounds and can achi eve the highest control efficiencies from EAFs
and other types of furnaces that have high particul ate emissions. Control efficiency ranges from 98 to
99+ percent removal.

Attachment L, Table L-10 contains a summary of recent F- BACT determinations for EAF operations
from the EPA RBLC database. As shown in Tables L-10, fabric filters are widely used to control
fluoride emissions from EAFs, and are routinely selected as BACT. The supporting technical

documents associated with these permits suggest that baghouses and wet scrubbers have the highest
levels of control and are equivale nt. Baghouses are the preferred me thod of control as the variable
nature of EAF operation could ad versely affect a wet scrubber.

Based on the fact that fabric filters are the top co ntrol option and are routinely determined as BACT
for melt shop s, Minnesota Steel I ndustries considers fabric filters to be BACT. As specified in the

EPA’s New Source Review Work shop Manual, (October 1990), “ an applicant proposing the top
control alternative need not provide cost and other detailed information in regard to other control
options.” Consequently, mechanical collectors and wet scrubbers will not be considered any further.



# 9.9.5 EAF Fluoride BACT Selection

A fabric filter in combination with a Direct-shell Evacuation Control system (DEC) represents the
highest level of control for fluoride particulate emissions from the EAF and is selected as BACT. An

evaluation of recent BACT determ inations in the RBLC did not li st any performance standards for
control of fluorides; only mass em ission limits were listed (BACT re port Attachment L, Table L -9).

Due to the low concentrations of fluorides in th e uncontrolled EAF baghouse exhaust (0.0001 gr/dscf
to 0.00001 gr/dscf), a BACT performance standard li mit for fluoride is not recommended. Since

fluorides are contained in the PM emissions from the EAF, Minnesota Steel proposes use of the EAF
particulate limits to demonstrat e ongoing control of fluoride emissi ons. The proposed mass emission

limit for fluorides from each EAF is 0.6 lb/hr as determined by performance testing for particulate

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# matter and measurement of fluoride in the DRI fed to the EAF and to keep records of the amount of
fluorspar added. The averaging period for fluoride emissions is 3 hours (three 1-hour test runs). The

mass emission limit is based on operation with BACT controls and the facility running at full
capacity.

For periods of startup and shutdown, Minnesota St eel will put EAF F- (particulate) emission control
equipment into service prior to commencing operation of process equipment, and keep controls operating
until the process is shut down and off line. No excess emissions will occu r as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 9.10 EAF Sulfuric Acid Mist (SAM) Emissions

The SAM emissions are generated from the sulfur content in the charge to the EAF. The charge is
direct reduced iron (DRI), injection carbon, charge carbon, and metal alloy and chemical additions
made during the ladle metallurgy processes, all of which have varying sulfur content. The sulfur
entering the exhaust stream may be oxidized to form SAM in the presence of heat from the EAF and
LMF and oxygen from ambient air. The evaluation of add-on controls for SAM will be based on a
melt shop exhaust SAM concentration of 0.1 ppm. This concentration is calculated from the SAM

mass emission rate in the Air Em ission Inventory (Appendix 3B.), and stack flow ra te from form

GI-04.



# 9.10.1 Identification of Pote ntial SAM Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous SAM control technol ogies are discussed in

Section 4.0 and Table 9-17. Potential control t echnologies for SAM emissions are the following:

• Wet Scrubber

• Spray dryer Absorption

• Wet Electrostatic Precipitator

• Dry Sorbent Injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design Methods and Operating Practices

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# 9.10.2 Elimination of Technicall y Infeasible SAM Control Options

Table 9-17 summarizes the feasibility of potential SAM controls on the EAF. Details regarding the
technologies that are infeasible are di scussed in the subsequent sections.

Table 9-17 Technical Feasibility of SAM Control Technologies for the Melt Shop

Sulfuric Acid Mist Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with Sulfuric Acid Mist and removes it. No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with Sulfuric Acid Mist and removes it. A fa bric filter is used to collect the spent sorbent. No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for Sulfuric Acid Mist removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For Sulfuric Acid Mist removal, caustic is added to the water spray system, allowing the spray system to function as an Sulfuric Acid Mist absorber. No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. Sulfuric Acid Mist reacts with sorbent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology No

Clean Fuel/ Good Combustion Practices (Base Case) Natural gas will be used as fuel for the EAF Yes

Good Design Methods and Operating Practices Use low sulfur carbon for carbon injection to minimize Sulfuric Acid Mist emissions.

Use foaming slag 

# process. B asic material, such as lime in the foaming slag froth scrubs Sulfuric Acid Mist. Yes



# 9.10.3 Flue Gas Desulfurization

Flue Gas Desulfurization


# Due to the expected low concentrations of SAM (< 1ppm) in the exhaust gas stream and the variable

flow conditions, the addition of a FG D system is both technically and economically infeasible. This

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# includes wet scrubbers (a bsorbers), spray dryer absorption, We t ESP’s and dry sorbent injection.

Minnesota Steel is not aware of a steel mill where FGD has been installed to control SAM emissions
from an EAF. The RBLC does not have any list ings of BACT determin ations for SAM emission

from EAFs; however, it does list SOx emissions. No recent BACT determinations for SO
x 

# (or SO 2 

# )

have identified add-on FGD as a vi able control method. See Atta chment L Table L-6 for recent

BACT determinations for SO 2 

# emissions from EAFs.



# 9.10.4 Ranking of Remaining SAM Control Technologies by Control Effectiveness
The remaining SAM control technologies applicab le to the melt shop are ranked by control

effectiveness in Table 9-18

Table 9-18 Ranking of Remaining SAM Control Technologies for Melt Shop

Sulfuric Acid Mist Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent Control

2 Good Design Methods and Operating Practices (Base Case) NA Inherent Control



# 9.10.5 Evaluation of Most E ffective SAM Control Technologies

Due to the cyclic nature of the flow from the EAF, add-on controls for SAM re moval are not feasible.
The RBLC does not list any BACT determinations for SAM emission from EAFs . Analysis of the

RBLC also indicates that the steel mills listed in Attachment L, Tables L-5 and L-20 do not have

add-on devices to control SO2 or SO
x 

# emissions from EAFs. Since the same types of add on controls

are used to control both SAM and SO 2 

# , it is reasonable to assume that add on controls are not feasible

for SAM emission. Instead, clean fuels, low sulfur containing carbon and scrap metal are often used

to reduce sulfur oxide emissions. Minnesota Steel will use outside scrap for up to 1% of its total
annual steel production during cold startup after weekly and annua l maintenance. Clean scrap
(bushlings) will be purch ased for this purpose.

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## Table 9-19 Evaluation of Most Effective SAM Control Technologies for Melt Shop
Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent Control NA Inherent Control NA NA

1 Good Design Methods and Operating Practices (Base Case) NA Inherent Control NA Inherent Control NA NA



# 9.10.6 EAF SAM BACT Selection

Based on the fact that a low concentration of SAM (< 1 ppm) will be present in the EAF exhaust
stream, Minnesota Steel considers the use of clean fuel and the use of commercially available charge
carbon to be BACT. Commercially available charge carbon typically has a sulfur content of 0.5% to

1.0%. This sulfur conten t is consistent with SO 2 

# emission limits in recent BACT determinations for
EAFs which list low sulfur charge carbon for SO 2 

# emissions control. Since there are no BACT

determinations in the RBLC for SAM emissions from EAFs, and the fact that the same controls are
used to control both pollutants (SO 2 

# and SAM), Minnesota Steel suggests compliance with the
proposed BACT SO 2 

# limits for ongoing compliance with the BACT limit for SAM emissions. The
proposed mass emission limit for SAM emissions fro m each EAF is 0.007 lb/hr as determined by
performance testing. The averaging period for SAM emissions is 3 hours, unless the amount of
material collected during the 3 hour period is insuffi cient to accurately measure, in which case the
averaging period will be the time it takes to co llect a sufficient amount of material. The mass

emission limit is based on operation with BACT controls and the facility running at full capacity.

No SAM BACT determinations for EAF operatio ns were found in the EPA RBLC database.
Attachment L, Table L-6 contains a summary of BACT determinations for SO 2 

# and SO
x 

# emissions
from EAF operations from the EPA RBLC database.

Periods of Startup, Shutdown and Malfunction

For periods of startup and shutdown, Minnesota Steel will utilize the same fuel (natural gas) and the
same additives and charge carbon used during norma l operations. However, reduced production rates
during startup and shutdown may result in higher lb SAM (SO 2 

# )/ton steel emission rates than occur
during normal operation. Therefore, Minnesota Steel proposes “Good Air Pollution Control

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# Practices for Minimizing Emissions” and limiting emissions to the rates Attachment M, Table 1 as
BACT during startup and shutdown. G ood operating practices will include:

• 

# Operation of the EAF in a manner which minimize s the amount of time ea ch EAF is operates with scrap metal feed in order to establish li quid metal levels in the EAF prior to commencing DRI pellet feed.

Minnesota Steel will define good operating practices fo r minimizing emissions in its startup, shutdown
and malfunction plan. As noted in Section 4.8, pl ans for startup, shutdown and malfunction will follow
all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.



# 9.11 EAF Lead (Pb) Emissions

About 90% of the PM emissions are from melting and refining of the liquid steel in the EAF and
LMF. Iron oxide is the predominate constituent of the particulate matter emitted during melting.
Lead, which is present in trace quantities, is also emitted as particulate matter during these
processing steps. The remaining 10% of lead bearing pa rticulates are generated during charging and
tapping. The tundishes and continuou s casters are also a source of l ead bearing particulate emissions
from metal fumes. Ladle and tundish preheaters are minor sources of Pb from the combustion of
natural gas.



# 9.11.1 Identification of Pote ntial Pb Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in

Section 4.0 and Table 9-1. Potential control techno logies for lead bearing particulate emissions are
the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)

• Good Design Methods and Operating Practices

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# 9.11.2 Elimination of Te chnically Infeasible Pb Control Options

Table 9-1 summarizes the technical feasibility of each particulat e control technology on the melt
shop. Additional details for the technologies that are not feasible are discussed in the subsequent

sections.

Table 9-20 Technical Feasibility of Lead Control Technologies for the Melt Shop

Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Lead bearing particulate matter is collected on the surface of the bags as the gas stream passes through them. The lead bearing particulate is periodically removed from the bags and collected in hoppers located beneath the bags. Yes

Wet Scrubber Wet scrubbers, remove particles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the lead bearing particulate out of the gas stream. Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove lead bearing particulate matter from the collection plates. No

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes

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## Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes

Good Design Methods and Operating Practices The EAF is vented to a Direct-shell Evacuation Control system (DEC). When the DEC is closed, the entire process remains covered, and 100% of the PM is collected. Due to the process variability that comes with the batch EAF, a design including a DEC offers high capture efficiency for PM. The DRI plant is designed to provide a continuous feed of hot DRI pellets. So opening of the EAF cover is minimized during operation. Yes



# Electrostatic Precipitator
ESP’s have proven to be unsuitable for applicatio ns involving exhaust streams with particulates
containing a high concentration of iron compounds. The electromagnetic properties of small charged
particles of iron compounds cause th e particles to adhere very strongl y to the collection plates. The
particles are then extremely difficult to dislodge which results in a decrease of control efficiencies
for the ESP. Since iron oxide is the predominant particulate constituent of the exhaust streams of
EAFs, dry or wet ESPs are considered technically in feasible for controlling particulate emission from
the melt shop.



# 9.11.3 Rank Remaining Pb Control Technologies by Control Effectiveness

The remaining lead bearing particulate control techno logies applicable to the melt shop are ranked by

control effectiveness in Table 9-2.

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## Table 9-21 Ranking of Remaining Lead Control Technologies for Melt Shop

Pb Control Technology Ranking

Rank Technology Particulate Removal Efficiency 1 Baghouse 98% - 99+%

2 Wet Scrubber 95% - 99+%

4 Centrifugal Separation
(e.g. Cyclones) 50% - 80%

5 Inertial Separators
(Drop Out Box) < 50%

6 Good Design Methods and Operating Practices NA Inherent to EAF
operation



# Particulate control efficiencies have been used as a general indicator of the emission control
effectiveness on lead bearing particulates. Lead is present only in trace quantities. Based on the Air
Emission Inventory (Appendix 3B), and stack flow rate from form GI-04, the calculated lead

concentration in the uncontrol led EAF exhaust is 0.000055 gr/dsc f. Given the extremely low
concentrations of lead, lead control efficiency may vary from the overall particulate control
efficiency.



# 9.11.4 Evaluation of Most Effective Pb Control Technologies

Fabric Filter


# Fabric filters are technically feasible for collecti ng fine lead bearing partic ulate matter containing
high concentration of iron compounds and can achi eve the highest control efficiencies from EAFs
and other types of furnaces that have high particul ate emissions. Particulate control efficiency ranges
from 98 to 99+ percent removal.

Attachment L, Tables L-3, L-4 and L- 5 contain summaries of recent PM/PM 10 

# BACT determinations
for EAF operations from the EPA RBLC database. As shown in Tables L- 3, L-4 and L-5 fabric
filters are widely used to control particulate matter and are routinely selected as BACT. The
supporting technical documents as sociated with these permits suggest that baghouses and wet
scrubbers have the highest levels of control and are equivalent. Baghouses are the preferred method

of control as the variable nature of EAF operation could adversely affect the performance of a wet

scrubber.

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# Based on the fact that fabric filters are the top co ntrol option and are routinely determined as BACT
for melt shop s, Minnesota Steel I ndustries considers fabric filters to be BACT. As specified in the

EPA’s New Source Review Work shop Manual, (October 1990), “ an applicant proposing the top
control alternative need not provide cost and other detailed information in regard to other control
options.” Consequently, mechanical collectors and wet scrubbers will not be considered any further.



# 9.11.5 EAF Pb BACT Selection

A fabric filter, in combination with a Direct-she ll Evacuation Control system (DEC), represents the
highest level of control for lead bearing particulate emissions from the EAF and is selected as BACT.

Due to the low concentrations of lead in the unc ontrolled EAF exhaust (0.000055 gr/dscf), performance

standard BACT limits for lead are not recommended. Since lead emissions are related to particulate
emissions, Minnesota Steel proposes use of the EAF particulate limits to demonstrate ongoing control of
lead emissions. The proposed lead emission limit for the EAF is 0.2 lb/hr as demonstrated by
performance testing for particulate matter and measure ment of lead in the DRI fed to the EAF. The
averaging period for particulate emissions is 3 hours (three 1-hour test runs).

Attachment L, Tables L-9 and 24 contain a summary of Pb BACT determinations for EAF operations

from the EPA RBLC database. Attachment L, Table L- 9 also includes two BACT determinations for lead
oxide. Neither determination specifies emission contro ls for lead oxide emissions. Barr Engineering Co.
was able to contact representatives of Republic T echnologies (RBLC ID OH-0245 [b]). Republic was not
able to comply with the Pb BACT limits listed in the RBLC, and received a higher Pb limit.

EAF RBLC Pb BACT Limits Summary
BACT-PSD Pb lb/t steel Emission Limits

MIN 0.00090 lb/t steel MAX 0.00100 lb/t steel MEDIAN 0.00095 lb/t steel
COUNT 2 CASES

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## MS RBLC Pb BACT Limits Summary 

# BACT-PSD Pb lb/t steel Emission Limits

MIN 0.0016 lb/t steel MAX 0.0016 lb/t steel MEDIAN 0.0016 lb/t steel
COUNT 2 CASES



# RBLC data for LMFs was not included in this an alysis as some of the reported limits were not

consistent with emissions from the entire melt shop whereas EAF and MS limits were co nsistent with
total melt shop emissions.

For periods of startup and shutdown, Minnesota St eel will put EAF Pb (particulate) emission control
equipment into service prior to commencing operation of process equipment, and keep controls operating
until the process is shut down and off line. No excess emissions will occu r as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 9.12 Ladle/Tundish Preheaters

9.12.1 Process Descriptions
Ladles are used to move molten steel from the EAFs to the LMFs and from the LMFs to casting.

Tundishes receive the molten steel from ladles and feed it into the continuous casters. As noted in
the melt shop process description in Section 9.1, natural gas preheaters are used to prepare ladles and

tundishes for service. The ladle/t undish preheaters are open flame bur ners which apply heat directly

to the ladles and tundishes. The ladles and tundishes are refractory lined vessels. The refractory
lining must be preheated before molten steel is placed in these vessels to prevent thermal shock from
damaging the refractory. In additi on, these vessels must be free of liquid water for safety reasons.
When water comes in contact with liquid steel it reacts in an explosive manner as it instantly flashes

to form steam.



# 9.12.2 Ladle/Tundish Preheater Emissions

The ladle/tundish preheaters are combustion sources, and are the source of PM, PM10, SO 2 

# , NO
x 

# , CO

and VOC emissions. Because these burners have an open flame, their emissions are vented through
the melt shop canopy to the melt shop baghouse al ong with other melt shop “fugitive” emissions.

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# 9.12.3 Identification of Potential Ladle/Tundish Pre-heater Control Technologies
Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. The Ladle/ Tundish Preheater BACT evaluati on will be done on a global basis
for all pollutants. This approach was selected because of the limited availability of emission controls
for open combustion sources. Desc riptions of the various pollution control technologies are discussed

in Section 4.0 and Table 9-22. Potential control technologies for CO emissions are the following:

• Add on controls (e.g. we t scrubbers or selectiv e catalytic reduction)

• Inherently Lower Polluting Equipment (e.g. low NOx burners)

• Good Combustion Controls

• Clean Fuels

• Good Design Methods and Operating Practices



# 9.12.4 Elimination of Technically Infeas ible Ladle/Tundish Pre-heater Control Options

Table 9-22 summarizes the technica l feasibility of potential pollu tion control technologies for the
Ladle and Tundish preheaters. Deta ils regarding the technologies that are not feasible are discussed
in the subsequent sections.

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## Table 9-22 Technical Feasibility of Emission Co ntrol Technologies for the Ladle and Tundish Preheaters
Emission Control Technologies Considered for BACT Analysis
Technology Description Feasible? Yes or No

Add on Controls Add on controls are pollution control devices are which are installed downstream of an emission source to control emissions. No

Inherently Lower Polluting Equipment Select burners which minimize emissions. E.g. Low NO x 

## Burners Yes

Good Combustion Controls Good combustion control limits the formation of CO, VOC and other products of incomplete combustion by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion
to occur. No

Clean Fuels Use inherently lower polluting fuels. Yes

Good Design Methods and Operating Practices Operate preheater burners in a manner which minimizes emissions. Yes

Add on Controls


# The pre-heater burners are open flame burners where the flame is applied dire ctly to the ladles and

tundishes. Add on controls are infeasible because the burner flames are not enclosed, and there is no
ductwork to collect and transport pol lutants from the burners directly to a control device. As noted

above, these emissions are routed to the me lt shop baghouse with ot her melt shop “fugitive”

emissions.

Good Combustion Controls


# The Ladle/Tundish pre-heater burners are open flame burners where th e flame is applied directly to
the ladles and tundishes. Since the pre-heater burners are not enclosed, combustion controls as
normally applied to heaters and boi lers are not feasible for the sa me reasons as add on controls.



# 9.12.5 Ranking of Remaining Ladle/Tundi sh Pre-heater Control Technologies by Control Effectiveness

The remaining control technologies applicable to the melt shop are ranked by control effectiveness in

Table 9-10.

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## Table 9-23 Ranking of Remaining Preh eater Emission Control Technologies
Emission Control Technologies

Rank Technology Estimated % Control Efficiency

1 Inherently Lower Polluting Equipment Low NO x 

## Burners 30% - 50%

2 Clean Fuels NA Clean fuels inherently have lower emissions

3 Good Design Methods and Operating Practices NA



# Since natural gas combustion is the source of em issions, low NOx burners are the only inherently
lower polluting equipment that can be applied in this application. The typical control efficiency for

low NO
x 

# burners in boiler and heater applications is 30% - 50%.

The pre-heater burners will be fired on natural gas.

Good operating practices in this application are proper operation and main tenance of the low NOx

burners.



# 9.12.6 Evaluation of Most Effectiv e Ladle/Tundish Pre-heater Control Technologies
Low NOx burners are effective at reducing NO
x 

# emissions and should not adversely affect emission
rates for other pollutants in this a pplication. In some cases, low NO
x 

# burners emit slightly more CO

than standard burners.

Natural gas is the clean fuel selected for this application. Use of natural gas will minimize SO 2 

# and

NO
x 

# emissions because natural gas contains very low concentrations of sulfur and nitrogen.

Good operating practices in this application are proper operation and maintenance of the low NO
x 

# burners can be utilized to minimi ze PM, PM10, CO a nd VOC emissions.

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## Table 9-24 Evaluation of Most Effective Ladle/Tundish Pre-heater Emission Control Technologies

Emission Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)


## 1 Inherently Lower Polluting Equipment Unknown (Low NOx Burners) 30% - 50% NA Inherent to

design NA Inherent to

design 2 Clean Fuels NA Inherent Control NA Inherent Control NA NA

3 Good Design Methods and Operating Practices NA Inherent Control NA Inherent Control NA NA



# 9.12.7 Ladle/Tundish Preheaters BACT Selection

Since the ladle/tundish preheaters are open flame burners, emissi on control options are limited.
Because the preheaters are not enclosed, add-on control devices cannot be used (e.g. SCR for NO
x 

# control). Combustion of clean fuels (natural gas) is feasible for control of criteria pollutants. In
addition, good combustion practices can be utilized to minimize PM , PM10, CO and VOC emissions.
Lastly, low NO
x 

# style burners can be used to reduce NO
x 

# emissions.

Minnesota Steel does not propose specific BACT em ission limits on the Ladle/Tundish pre-heaters.
These sources are vented to the melt shop ventila tion system and emissions from the pre-heaters are

accounted for in the emission lim its specified for the EAF.

For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting process equipment into service, and will contin ue this practice until the process is shut down and
off line. Therefore, Minnesota Steel is not proposing any special permit conditions for PM, PM10, NO
x 

# , CO and VOC startup and shutdown. Since Minnesota Steel will use natural gas at all times the
Ladle/Tundish Preheaters are operating, no special permit conditions are required to control SO 2 

# emissions during startup and shutdown.

Attachment L, Tables L-25 -29 cont ains a summary of BACT determ inations for Ladle and Tundish
Pre-heater (LTP) operations from the EPA RBLC database. RBLC Ladle and Tundish preheater

limits are summarized below:

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## LTP RBLC PM10 BACT Limits Summary 

# BACT-PSD PM10 lb/MMBTU Emission Limits

MIN 0.0075 lb/MMBTU MAX 0.0075 lb/MMBTU MEDIAN 0.0075 lb/MMBTU
COUNT 1 CASES

LTP RBLC SO2 and SOx BACT Limits Summary 

# BACT-PSD SO2 and SOx lb/t steel Emission Limits

MIN NA lb/t steel MAX NA lb/t steel MEDIAN NA lb/t steel
COUNT NA CASES

LTP RBLC NOx BACT Limits Summary 

# BACT-PSD NOx lb/MMBTU Emission Limits

MIN 0.089 lb/MMBTU MAX 2.040 lb/MMBTU MEDIAN 1.090 lb/MMBTU
COUNT 10.000 CASES

LTP RBLC CO BACT Limits Summary 

# BACT-PSD CO lb/t steel Emission Limits

MIN 0.0823 lb/MMBTU MAX 0.0824 lb/MMBTU MEDIAN 0.0824 lb/MMBTU
COUNT 2.0000 CASES

LTP RBLC VOC BACT Limits Summary 

# BACT-PSD VOC lb/MMBTU Emission Limits

MIN 0.0054 lb/MMBTU MAX 0.0054 lb/MMBTU MEDIAN 0.0054 lb/MMBTU
COUNT 1 CASES

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# 9.13 Vacuum Degasser

9.13.1 Vacuum Degas ser Process Description
Depending upon final steel specifi cation requirements, some “hea ts” may be processed with a
vacuum degassing step. In this process the LMF and the steel “heat” it c ontains are pl aced under a
vacuum to reduce the carbon content in the steel and to extract other dissolved gases in the “heat”.
Argon gas is commonly used as a stripping agent. Oxygen is used when reducing the carbon content
of the steel. The degassing cycle takes less than an hour. Carbon monoxide is emitted as a
byproduct of the degassing process. The off gas from the degassi ng system will be routed to a
control device. The vacuum is provided by a seri es of steam ejectors. A 108 MMBtu/hr natural gasfired boiler is specified to provide steam to the vacuum degasser system.



# 9.14 Vacuum Degasser CO Emissions Control

9.14.1 Identification of Pote ntial CO Control Technologies

The vacuum degasser process is a source of ca rbon monoxide (CO) emissions . Partial oxidation of

carbon is the source of CO emissions from the de gasser. CO emissions occur as the steel carbon
content is reduced in the degasser. The vacuum de gasser has an estimated CO emission rate of 390

lb/hr as the carbon content of the steel is reduce d from 0.06% to 0.04%. The emission inventory also

lists emissions of PM, PM10, SO2, NOx and VOC. These emissions are not from the degasser; they
are collateral emissions from operation of the CO emission control device; therefore, the BACT
review will not include a control equipment analysis for these pollutants.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 8-25. Potential c ontrol technologies for Vacuum Degasser CO emissions are the
following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Flare

• Good Combustion Controls

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# 9.14.2 Elimination of Technicall y Infeasible CO Control Options

CO control by emission control devices, such as thermal and catalytic oxidation, are considered
technically infeasible because:

• 

# The degassing process is a highly cyclical batch process. CO concentration of the exhaust gas
will vary widely over the degassing cycle. C onstantly changing flow rates and temperature
would make operation of a thermal or catalytic oxidizer infeasible.

• 

# The discharge pressure from steam ejectors typically is very low. A blower or compressor would
be needed to get the off gases up to pressures required for add on controls. A blower or
compressor would be difficult to operate under th e variable flow rates present in the degasser.

• 

# CO control by good combustion prac tices is not feasib le because CO from degassing is not a
combustion by product. The degassing system does not contain burners or a firebox; so no
combustion controls can be employed.

Table 9-25 Technical Feasibility of CO Control Technologies fo r Vacuum Degasser
CO Emission Control Technologie s Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize CO to CO 2


## . This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of CO at lower temperatures than a thermal incinerator. No

Flare Yes

Good Combustion Controls Good combustion control limits the formation of CO by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. No

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# 9.14.3 Ranking of Remaining CO Control Technologies by Control Effectiveness

Flaring is the only technica lly feasible control device for the vacuum degasser

Table 9-26 Ranking of Remaining CO Control Technologies for the Vacuum Degasser Systems
CO Control Technology

Rank Technology Estimated Control Efficiency

1 Flare 98%



# 9.14.4 Evaluation of Most Effe ctive CO Control Technologies
A flare is a relatively simple emission control devi ce. Flares are designed to handle highly variable
flow rates while maintaining a high level of emissions control. No instrumentation systems are
needed to manage the combustion process vs. the comb ustion controls needed to operate an oxidizer.
Flare systems are designed to operate on very low pressures; so no blowers or compressors are
needed to operate a flare in this application. Table 8-27 summarizes the cost of emission reduction,
capital and annualized operating cost and the cost pe r ton of pollutant removed. The detailed control
cost analyses are located in Attachment G.

Table 9-27 Evaluation of Most Effective CO C ontrol Technologies for Vacuum Degasser Boiler

CO Control Technology Effectiveness Evaluation



## Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Flare Base Case NA NA NA NA



# 9.14.5 Vacuum Degasser CO BACT Selection

A flare is selected as the BACT control device fo r CO emissions from vacuum degasser. Other addon controls are technically infeasib le. The estimated CO emission rate after controls is 8 lb/hr based
on a CO control efficiency of 98% at the flare. Minnesota Steel proposed to follow 40 CFR 60
Subpart A (60.18) flare provisions to demonstrate compliance with BACT.

For periods of startup and shutdown, Minnesota Steel will follow good flare operational practices
(e.g. maintaining a pilot light) while putting the degassing equipment into service, and will continue
this practice until the process is s hut down and off line. No excess em issions will occur as a result of

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# control equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit
conditions for startup and shutdown.

No control requirements for vacuum degassers were listed in the EPA RBLC database. An air
quality permit recently issued to SteelCorr LLC specifies use of a flare to control CO emissions from
vacuum degassers. SteelCorr is located in Co lumbus, MS. Operating permit 1680-0064 was issued

on March 21, 2005.



# 9.15 Vacuum Degasser Boiler

A natural gas fired package boiler will provide steam to operate the vacuum ejectors for the vacuum
degasser. The boiler is rated at 108 MMBtu/hr. Air pollutant s emitted from the Vacuum Degasser

Boiler include: PM, PM10, SO 2 

# , NO
x 

# , CO, VOC. All emissions resu lt from combustion of natural

gas.



# 9.16 Vacuum Degasser Boile r Particulate MatterPM/PM 10 

# Emission

Particulate emissions from natural gas combustion are typically low. Particulate matter is generated
during incomplete combustion. All particulates are assumed to be PM 10 

# . Uncontrolled Vacuum
Degasser Boiler emissions were determined using AP-42 emission factors (0.0075lb/MMBtu) which
are equivalent to a particulate concentration of 0.005 gr/dscf.



# 9.16.1 Identification of Potential PM/PM 10 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in

Section 4.0 and Table 9-28. Potential control technologies for particulate emissions are the
following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)

• Good Design Methods and Operating Practices

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# 9.16.2 Elimination of Tech nically Infeas ible PM/PM 10 

# Control Options

Table 9-28 summarizes the technical feasibility of each particulate control technology on the
Vacuum Degasser Boiler. Additional details for the technologies that are not feasible are discussed
in the subsequent sections.

Table 9-28 Technical Feasibility of PM/PM 10 

## Control Technologies for the Vacuum Degasser Boiler

Summary of Control Technology Feasibility

Technology Description Feasible? Yes or No

Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. No

Wet Scrubber Wet scrubbers, remove part icles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. No

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. No

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. No

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. No

Good Design Methods and Operating Practices Well designed and operated burners reduce the amount of particulate matter formed as a result of incomplete combustion. Yes

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# At particulate concentrations of 0.005 gr/dscf, use of add-on controls for gas fired combustion
sources is technically infeasible because this partic ulate concentration level is at the limits of PM
emissions control technology. In addition, particulates from natu ral gas combustion are primarily
condensable particulates. Condensable PM is not readily remo ved by these control devices. The
particulate concentration of 0.005 gr/dsc f was calculated using the AP-42, 5 th 

# edition emission factor
for natural gas combustion and the EPA Method 19 “F” factor for flue gas volumes generated by
natural gas combustion. The F factor flow rate was adjusted to 3% oxygen in the flue gas; this is
typical of boiler and process heater operations.



# 9.16.3 Rank Remaining PM/PM 10 

# Control Technologies by Control Effectiveness
The only remaining control technology for contro l of PM emissions from the Vacuum Degasser
Boiler is good burner design and operating practices.

Table 9-29 Ranking of Remaining PM/PM 10 

## Control Technologies for Vacuum Degasser Boiler

PM / PM 10 

## Control Technology Ranking

Rank Technology % Efficiency

1 Good Burner Design and
Operating Practices NA

Base Case



# 9.16.4 Evaluation of Most Effe ctive PM Contro l Technologies
Since good burner design and operating practices is i nherent to the process no additional cost will be

incurred.

Table 9-30 Evaluation of Most Effective PM/PM 10 

## Control Technologies for the Vacuum Degasser Boiler

Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA

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# 9.16.5 Vacuum Degasser Boiler PM/PM 10 

# BACT Selection

Good Burner Design and Operating Prac tices are se lected as BACT.

The proposed BACT PM/PM 10 

# limit for the Degasser Boiler is 0.0075 lb PM/PM 10 

# /MMBtu, good
combustion practices and use of natural gas. Use of natural gas, a clean fuel, limits potential
emissions of particulat es. The proposed PM/PM 10 

# mass emission limit is 0.7 lbs of PM/PM 10 

# per hour on a 24 hour average basis. The proposed lim it is based on compliance testing for PM by EPA

Method 5, and PM 10 

# measured by EPA Methods 201 (or 201 A) and 202 (or EPA approved modified
Method 202 procedures). The mass emission limit is based on operati on with BACT controls and the
facility running at full capacity.

Attachment L, Tables L-38A and 38B c ontain a summaries of BACT PM and PM 10 

# determinations
from the EPA RBLC database for natural gas-fired boi lers and heaters rated at 100 MMBtu/hr or less.
Statistical analyses of the RBLC data are summarized in the tables and bar charts below. The
proposed BACT particulate limit of 0.0075 lb PM/PM 10 

# /MMBtu is consistent with AP-42 and less

than the median BACT PM/PM 10 

# limits listed below. Controls listed in the RBLC for this source are
use of natural gas and good combustion practices. Therefore, specifying good combustion controls

with a limit of 0.0075 lb/MMBtu as BACT is cons istent with recent RBLC BACT determinations.

RBLC PM 10 

# BACT Limits Summary

BACT-PSD PM 10 

## lb/MMBtu Emission Limits Other (non-BACT) PM 10 

## lb/MMBtu Emission Limits

MIN 0.0019 lb/MMBtu MIN 0.007 lb/MMBtu MAX 0.6 lb/MMBtu MAX 0.4 lb/MMBtu MEDIAN 0.0085 lb/MMBtu MEDIAN 0.008 lb/MMBtu
COUNT 59 CASES COUNT 11 CASES

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# RBLC PM10 BACT Limits
Small Gas Fired Heaters & Boilers

0 5 10 15 20 25

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1
BACT PM10 Limits lb/MMBtuCount 

### Propsed BACT
Limit 0.0075



# RBLC PM BACT Limits Summary

BACT-PSD PM lb/MMBtu Emission Limits Other (non-BACT) PM lb/MMBtu Emission Limits

MIN 0.005 lb/MMBtu MIN 0.007 lb/MMBtu MAX 5 lb/MMBtu MAX 0.014 lb/MMBtu MEDIAN 0.010 lb/MMBtu MEDIAN 0.00715 lb/MMBtu
COUNT 29 CASES COUNT 10 CASES



# RBLC PM BACT Limits
Small Gas Fired Heaters & Boilers

0 2 4 6 8 10 12 14

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1 

# PM lb/MMBtuCount 

### Propsed BACT
Limit 0.0075

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# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the Degasser Boiler service, and will continue this practice until the process is shut down and off
line. In addition, particulate matter emissions fro m natural gas combustion are typically low; so, no
special conditions are needed. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 9.17 Vacuum Degasser Bo iler Visible Emissions

Visible emissions are the result of incomplete combustion of fuels in the Vacuum Degasser Boiler.



# 9.17.1 Vacuum Degasser Package Boile r Visible Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

In the Vacuum Degasser Boiler, PM/PM 10 

# emissions are controlled by good combustion practices.

A 3% opacity limit is recommended as BACT for visible emissions from the Vacuum Degasser Boiler.
i.e. the average opacity of a boiler cannot exceed 3% for more the one 6-minute period during an hour. If

Minnesota Steel identifies visible emissions from the Vacuum Degasser Boiler of 3%, it will take
corrective action as soon as it is practicable to do so. An opacity limit of 3% is consistent with recent
RBLC determinations for gas fired heaters as shown in the table below.

Small Natural Gas Boiler RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 10 % Opacity MIN 5 % Opacity MAX 20 % Opacity MAX 40 % Opacity MEDIAN 20 % Opacity MEDIAN 20 % Opacity
COUNT 14 CASES COUNT 13 CASES



# See Attachment L, Table L-46 for a detailed listing of recent RBLC opacity determinations for small
natural gas fired heaters and boilers.

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# 9.18 Vacuum Degasser Boiler Sulfur Dioxid e (SO2) emission

SO 2 

# emissions from natural gas combustion are typicall y low. Based on use of natural gas as the fuel
for the vacuum degasser boiler, the expected SO 2 

# concentration in the boiler flue gas are expected to
be less than 1 ppm SO 2


# .



# 9.18.1 Identificati on of Potential SO 2 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various SO 2 

# control technologies are discussed in

Section 4.0 and Table 9-31. Pote ntial control technologies for SO 2 

# emissions are the following:

• Wet Scrubber

• Spray Dryer Absorption

• Wet Electrostatic Precipitator

• Dry Sorbent Injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design Methods and Operating Practices



# 9.18.2 Elimination of Te chnically Infeasible SO 2 

# Control Options

At less than 1 ppm SO 2 

# in the Vacuum Degasser Boiler exhaust, all add-on controls are technically
infeasible because 1 ppm is at or below the exhaust concentrations that can be achieved with these

controls.

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## Table 9-31 Technical Feasibility of SO2 Contro l Technologies for the Vacuum Degasser Boiler

SO2 Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with SO2 and removes it. No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for SO2 removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For SO2 removal, caustic is added to the water spray system, allowing the spray system to function as an SO2 absorber. No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with SO2 and removes it. A fabric filter is used to collect the spent sorbent. No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. SO2 reacts with sorbent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology No

Clean Fuel/ Good Combustion Practices (Base Case) Combust natural gas Yes



# 9.18.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness
The remaining control technology for control of SO 2 

# from the Vacuum Degasser Boiler is the use of
clean fuel and good combustion practices.

Table 9-32 Ranking of Remaining SO 2 

## Control Technologies for the Vacuum Degasser Boiler

SO2 Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the process

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# 9.18.4 Evaluation of Most Effective SO 2 

# Control Technologies

Since the use of clean fuel and good combustion prac tices is an inherent part of the process no

additional cost will be incurred.

Table 9-33 Evaluation of Most Effective SO 2 

## Control Technologies for the Vacuum Degasser Boiler
Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the
process NA Inherent to the process NA NA



# 9.18.5 Vacuum Degasser Boiler SO 2 

# BACT Selection

Use of clean fuels (natural gas) and good combustion practices are selected as BACT for the Vacuum
Degasser boilers. Use of natural ga s, a clean fuel, limits potential SO 2 

# emissions to the rated heat
input capacity of the boilers.

The proposed SO 2 

# mass emission limit is 0.1 lbs of SO 2 

# per hour on a 3 hour average basis. The
proposed limit is based on compliance testing for SO 2 

# by EPA Method 6C, determination of SO 2 

# by

instrumental methods. The mass emission limit is based on operation with BACT controls and the
facility running at full capacity.

Attachment L, Table L-39 contains a summary of BACT SO 2 

# determinations from the EPA RBLC
database for natural gas-fired boile rs and heaters rated at 100 MMBtu/hr or less. Statistical analyses
of the RBLC data are summarized in the tables and bar charts below. The proposed BACT limit of

0.1 lb SO 2 

# /hr is equivalent to 0.0006 lb SO 2 

# /MMBtu, and is consistent with AP-42 and the lowest

BACT SO 2 

# limits listed below. Controls listed in the RBLC for this source are use of natural gas and
good combustion practices. Theref ore, specifying good combustion controls and use of natural gas

with a limit of 0.1 lb SO 2 

# /hr as BACT is consistent with r ecent RBLC BACT determinations.

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# RBLC SO 2 

# BACT Limits Summary BACT-PSD SO 2 

## lb/MMBtu Emission Limits Other (non-BACT) SO 2 

## lb/MMBtu Emission Limits

MIN 0.0006 lb/MMBtu MIN 0.0006 lb/MMBtu MAX 1.28 lb/MMBtu MAX 4 lb/MMBtu MEDIAN 0.0025 lb/MMBtu MEDIAN 0.017 lb/MMBtu
COUNT 44 CASES COUNT 14 CASES



# Since Minnesota Steel will use natural gas at all ti mes the DRI Boilers are operating, no special permit
conditions are required to control SO 2 

# emissions during startup and shutdown.



# 9.19 Vacuum Degasser Boiler Nitrogen Oxides (NOx) Emissions

Combustion of natural gas is the primary source of emissions from the vacuum degasser boiler. NO
x 

# emissions from the Vacuum Degasser Boiler are primarily thermal NO
x. 

# Low NO
x 

# Burners (LNB)
rated at 0.08 lb NOx/MMBtu are used as the base case in this analysis because they are inherent in
the process design from Danieli. LNB are inexpensive and are routinely offered as standard
equipment. An emission rate of 0.08 lb NOx/MMBtu is a co nservatively high emission rate
assumption for LNBs relative to the AP-42 NO
x 

# emission factor for small boi lers, which is equivalent
to 0.05 lb/MMBtu. A burner rating of 0.08 lb NO
x 

# /MMBtu equates to a NO
x 

# concentration of 60
ppm dry.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various control technologies are discussed in Section 4.0

and Table 9-34. Potential control tech nologies for Vacuum Degasser Boiler NO
x 

# emissions are the
following:

• Low Temperature Oxidation

• Selective Catalytic Reduction

• Selective Non-Catalytic Reduction

• Non-selective Ca talytic Reduction

• Ultra Low NO
x 

# Burners / Low-NOx Burners and Flue Gas Recirculation (ULNB / LNB-FGR)

• External Flue Gas Recirculation

• Low NOx Burners

• Low Excess Air (LEA)

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# • Other Combustion Controls



# 9.19.1 Elimination of Technicall y Infeasible NOx Control Options

Table 9-34 summarizes the feasibility of potential NO
x 

# control technologies for emissions from the
vacuum degasser boiler. Details regarding the technologies that are infeasible are discussed in the
subsequent sections.

Table 9-34 Technical Feasibility of NO x 

## Control Technologies for the Vacuum Degasser Boiler

NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Low Temperature Oxidation Low Temperature Oxidation is a process where NO x 

## is oxidized to form water soluble nitrate compounds which can easily be removed by absorption (wet scrubbing). Oxidation occurs at relatively low temperatures (100oF – 200oF) so it can be effectively used as an add-on control system where the stream to be treated is not hot enough for catalytic controls. Ozone is typically used as the oxidizing agent. Yes

Selective Catalytic Reduction Selective catalytic reduction (SCR) is a postcombustion NO x 

## control technology in which ammonia (NH 3 

## ) is injected into the flue gas stream in the presence of a catalyst. SCR requires a temperature range of 500 ° F – 800 ° F. Yes

Selective Non-Catalytic Reduction The Selective non-catalytic reduction (SNCR) process injects urea or ammonia-based chemicals into the flue gas stream to convert NO to N 2 

## and water. The optimum operating temperature for SNCR is 1,600 ° F to 2,000 ° F. Yes

Non-Selective Catalytic Reduction Non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NO x 

## and CO react in the presence of NSCR catalyst to form nitrogen (N 2 

## ) and carbon dioxide (CO 2 

## ). It is typically employed in clean gas services such as natural gas fired turbines. No

Ultra Low NO x 

## Burners or Low-NO x 

## Burners and Flue Gas Recirculation This option is a combination of Low NOx burners and external flue gas recirculation.

The same effect can be accomplished with Induced flue gas recirculation burners. These burners are designed to draw flue gas into the burner to dilute the fuel. This reduces flame temperature and NO x 

## formation. Yes

External Flue Gas Recirculation External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures. In an external flue gas Yes

Incorporate

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## NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air and this mixture is introduced into the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x 

## . d via the ULNB / LNB-EFR analysis

Low-NOx Burners Low-NO x 

## burner (LNB) technology utilizes advanced burner design to reduce NO x 

## formation through the restriction of oxygen, flame temperature, and/or residence time. Yes (Base
Case)

Low Excess Air (LEA) Low Excess is a combustion control method which is used to reduce the amount of oxygen in the combustion zone of a furnace or boiler. This limits the amount of oxygen available for NO x 

## formation. Yes

Other Combustion Controls These combustion control methods are typically employed on existing sources. They inexpensive, but have limited control efficiencies. Combustion controls incl ude Overfire Air (OFA), Burners Out of Servic e (BOOS) and Load Reduction and Reduced Combustion Air Temperature. No



## • Non-Selective -Catalytic Reduction (NSCR)



# Review of the EPA RACT/BACT/LEAR Clearinghouse, as well as discussions with vendors, indicate
that this technology is not used in boiler applicatio ns. In addition, the same level of emission control

can be achieved with SCR or LoTOx.

• Other Combustion Controls



# Overfire air and burners out of se rvice are appropriate for large indus trial and utility boilers. A small
package boiler, like the vacuum degasser boiler, is not large enough to accommodate over fire air.
Small boilers usually have only one burner; so, they do not have spare burners which can be taken
out of service. New boiler designs can meet low NOx control requirements without use of air preheat

limitations.



# 9.19.2 Ranking of Remaining NOx Control Technologies by Control Effectiveness
The remaining control technologies applicable to th e Vacuum Degasser Boiler are ranked by control

effectiveness in Table 9-35

.

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## Table 9-35 Ranking of Remaining NO x 

## Control Technologies for the Vacuum Degasser Boiler

NO x 

## Control Technology Ranking

Rank Technology Estimated % Control Efficiency

1 Selective Catalytic Reduction 70 % *

2 LoTOx 70% *

3 Ultra Low NOx Burners or Low-NO x 

## Burners and Flue Gas Recirculation 56%

5 SNCR 25%

5 Low NOx Burners NA Base Case

6 Low Excess Air (LEA) 1-15%
Implement as good operating practices



## * A NOx control efficiency of 70% is equivalent to 18 ppm NOx on a dry basis.



# 9.19.3 Evaluation of Most Effective NO x 

# Control Technologies

Table 9-36 Evaluation of Most Effective NO x 

## Control Technologies for the Vacuum Degasser Boiler

NOx Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)
1 LoTOx 

## 6.2 $673,564 $302,396 $49,032

1 Selective Catalytic Reduction 

## 6.2 $1,683,175 $356,433 $57,793

2 Ultra Low NO x 

## Burners or Low-NO x 

## Burners and Flue Gas Recirculation Burners 

## 5.0 $285,011 $39,905 $8,052

3 SNCR 

## 2.2 $861,742 $212,444 $96,450

4 Low NOx Burners NA Base Case NA Base Case NA Base Case NA Base Case

5 Low Excess Air (LEA) NA Implement as good operating practices NA Implement

as good operating practices NA NA



# SCR, LoTOx, and SNCR are all ec onomically infeasible as their control costs are all above $10,000
per ton NOx removed.

Ultra low or low NOx burners with external flue gas recirculation are the next highest level of

control.

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# An analysis of the RBLC indicates that small gas fired boilers, similar to the Vacuum Degasser

Boiler, listed in Attachment L Table L-40A do not have add-on devices to control NO
x. 

# Only two of
ninety seven BACT entries had add-on controls for NOx. Instead, low NO
x 

# burners or low NOx
burners with flue gas recirculation have been predominately selected as BACT for control of NO
x 

# emissions.



# 9.19.4 Vacuum Degasser Boiler NOx BACT Selection

Minnesota Steel proposes ultra low NO
x 

# burners (ULNB) or low NO
x 

# burners with flue gas
recirculation, or equivale nt combustion controls as BACT. Minnesota Steel considers the use of ultra

low NOx burners or low NO
x 

# burners with flue gas recirculation to be consistent with recent BACT

determinations as shown in Attachment L, Table L-40A.

Minnesota Steel proposes a BACT NO
x 

# emission limit of 0.035 lb NO
x 

# /MMBtu. The proposed NO
x 

# mass emission limit is 3.5 lbs of NO
x 

# per hour on a 24 hour average basis. The proposed limit is
based on compliance testing for NO
x 

# by EPA Method 7E, determination of NO
x 

# by instrumental
methods. The mass emission limit is based on oper ation with BACT controls and the facility running
at full capacity.

Attachment L, Table L-40A contains a summary of BACT determinations from the EPA RBLC
database for the natural gas-fired boilers and heater rated at 100 MMB tu/hr or less. The RBLC data

indicates that ultra low NO
x 

# burners or low NO
x 

# burners with flue gas recirculation have been

selected as BACT for control of NO
x 

# emissions from gas fired boilers and heaters. Statistical
analyses of the RBLC data are summarized in the table below. The proposed BACT limit of 0.035 lb

NO
x 

# /MMBtu is below the median RBLC BACT limit. Therefore, specifying ultra low NOx burners
with flue gas recirculation as BACT is consistent with recent RBLC BACT determinations.

RBLC NO x 

# BACT Limits Summary

BACT-PSD NO x 

## lb/MMBtu Emission Limits Other (non-BACT) NO x 

## lb/MMBtu Emission Limits

MIN 0.0085 lb/MMBtu MIN 0.0085 lb/MMBtu MAX 5.5 lb/MMBtu MAX 0.23 lb/MMBtu MEDIAN 0.050 lb/MMBtu MEDIAN 0.036 lb/MMBtu
COUNT 97 CASES COUNT 35 CASES

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# RBLC NOx BACT Limits Small Gas Fired Heaters & Boilers

0 5 10 15 20 25 30 35

0 .

0

1 0.02 0 . 0

3 0.04 0 .05 0.0 6 0.07 0 . 0

8 0.09 0 . 1 0.2 0 .3 0.4
> 0 .

4



# lb NOx/MMBtuCount 

### Proposed
BACT Limit
0.0035



# Periods of Startup, Shutdown and Malfunction

For periods of startup, shutdown and malfuncti on, Minnesota Steel proposes to follow Good Air

Pollution Control Practices for Minimizing Emissions as BACT as described in Section 4.6.

For ULNB to effectively control NO
x 

# emissions, the DRI Boilers must be at sufficient load for
effective flue gas induction into the ULNB and fo r combustion controls to maintain low levels of
excess combustion air. Once the process heater has reached the appropriate operating conditions; the

ULNB will be able to control NO
x 

# emissions as intended. Until the process heater reaches the proper
operating conditions Minnesota Steel cannot comply with the BACT limits for normal operation.
Therefore, Minnesota Steel proposes to follow “Goo d Air Pollution Control Practices for Minimizing
Emissions” and to limit emissions to the rates Attachment M, Table 1 as BACT during startup and
shutdown. Good operating pr actices will include:

• 

# Operation of the Degasser Boiler in a manner which minimizes the amount of time the heater is
operated at temperatures and firing rates which are outside the operating range effective NO
x 

# control by ULNB.

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## • 

# Operation of the Degasser Boiler in a manner which minimizes the amount of time the heater is
operated at excess oxygen le vels higher than the operating range effective for NO
x 

# control by

ULNB.

Minnesota Steel will define good operating practices fo r minimizing emissions in its startup, shutdown
and malfunction plan. As noted in Section 4.8, pl ans for startup, shutdown and malfunction will follow
all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.



# 9.20 Vacuum Degasser Boiler Car bon Monoxide (CO) Emissions

CO emissions from the Vacuum Degasser Boiler are the result of incomplete natural gas combustion.

Based on AP-42 emission factors, the estimated CO concentration in the exhaust of the Vacuum
Degasser Boiler is 0.08 lb/MMBtu. This equate s to a CO concentration of 111 ppm, which is
consistent with good operation of low NO
x 

# burners.



# 9.20.1 Identification of Potent ial CO Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous CO control technologi es are discussed in

Section 4.0 and Table 9-52. Potential control t echnologies for CO emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Good Burner Design and Operating Practices



# 9.20.2 Elimination of Technically Infeasible CO Co ntrol Options

Table 9-37 summarizes the feasibility of potential control technologies for CO emissions from the
Vacuum Degasser Boiler.

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## Table 9-37 Technical Feasibility of CO Contro l Technologies for the Vacuum Degasser Boiler
CO Emission Control Technologie s Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize CO to CO 2


## . This may be accomplished using an add on oxidizer or a duct burner. Yes

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of CO at lower temperatures than a thermal incinerator. Yes

Good Combustion Controls Good combustion control limits the formation of CO by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of CO formed as a result of incomplete combustion. 

## Yes



# 9.20.3 Ranking of Remaining CO Control Technologies by Control Effectiveness

Table 9-38 Ranking of Remaining CO Technologies for the Vacuum Degasser Boiler

CO Control Technology Ranking

Rank Technology % Efficiency

1 

## Thermal Oxidizer (Recuperative and Regenerative) 90% *

1 

## Catalytic Oxidizer 90% *

2 

## Good Combustion Controls NA

Base Case

2 Good Burner Design and Operating Practices NA

Base Case



## * A 90% control efficiency is equivalent to 10 ppm CO on a dry basis

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# 9.20.4 Evaluation of Most Effe ctive CO Contro l Technologies

Table 9-39 Evaluation of Most Effective CO C ontrol Technologies for the Vacuum Degasser Boiler

Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Thermal Oxidizer (Recuperative) 

## 8.9 $608,902 $322,239 $36,312

1 Thermal Oxidizer (Regenerative) 

## 8.9 $760,713 $283,680 $31,967

1 Catalytic Oxidizer 

## 8.9 $738,592 $249,321 $28,095

2 

## Good Combustion Controls NA

Inherent Controls NA

Inherent

Controls NA NA

2 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# Thermal and catalytic oxidation are both economically infeasible as their control costs are all above
$10,000 per ton NOx removed.

Since the use of good combustion controls and good burner design and op erating practices are
inherent parts of the process no addi tional cost will be incurred. The detailed control cost analyses

are located in Attachment G.



# 9.20.5 Vacuum Degasser Boiler CO BACT Selection

Good Combustion Practices and Good Burner Design and Operating Practices are selected as BACT
for CO control in the Vacuum Degasser Boiler. Use of natural gas, a clean fuel, in combination with
good combustion practice s limits potential CO emissions from the boilers.

Minnesota Steel proposes a BACT CO emission limit of 0.08 lb CO/MMBtu for the DRI boilers.
The proposed CO mass emission limit is 8.2 lbs of CO per hour on a 1 hour average basis. The
proposed limit is based on complian ce testing for CO by EPA Method 10. The mass emission limit is
based on operation with BACT controls and the facility running at full capacity.

Attachment L, Table L-41 contains a summary of BACT determinations from the EPA RBLC
database for natural gas-fired boi lers and heaters rated at 100 MMBt u/hr or less. The RBLC data

indicates Good Combustion Practices and use of natura l gas as BACT for CO control. As noted in

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# the NOx control analysis, CO emissions from low a nd ultra low NOx burners are slightly higher than

standard burners. Data in Table L-41 shows CO emissions fro m low and ultra low NOx burners in
the 0.08 to 0.1 lb CO/MMBtu range. Therefore, specifying good combustion c ontrols as BACT with

a limit of 0.08 lb CO/MMBtu for ultra low NOx burners is cons istent with recent RBLC BACT

determinations. This limit is also consistent with the median or recent determinations. Statistical
analyses of the RBLC data are summarized in the table and bar graph below.

RBLC CO BACT Limits Summary

BACT-PSD CO lb/MMBtu Emission Limits Other (non-BACT) CO lb/MMBtu Emission Limits

MIN 0.022 lb/MMBtu MIN 0.011 lb/MMBtu MAX 4.3 lb/MMBtu MAX 0.7 lb/MMBtu MEDIAN 0.082 lb/MMBtu MEDIAN 0.08 lb/MMBtu
COUNT 81 CASES COUNT 30 CASES

RBLC CO BACT Limits Small Gas Fired Heaters & Boilers

0 5 10 15 20 25 30

0.02 0.04 0.06 0.08 0.1 0.2 0.4 0.6 0.8 1 > 1

BACT limit lb CO/MMBtuCount Proposed BACT
Limit 0.08



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the vacuum degasser boiler into service, and w ill continue this practice until the process is shut

down and off line. Therefore, Minnesota Steel is not proposing any special permit conditions for startup

and shutdown.

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# 9.21 Vacuum Degasser Boiler Volatile Organic compound (VOC) Emissions

VOC emissions from the Vacuum Degasser Boiler are the result of incomplete natural gas

combustion. Based on AP-42 information, the calcul ated VOC concentration in the uncontrolled flue
gases of the Vacuum Degasser Boiler is 0.0054 lb/ MMBTU. This equates to a VOC concentration of
13 ppm.



# 9.21.1 Identification of Pote ntial VOC Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous VOC control technologi es are discussed in

Section 4.0 and Table 9-40. Potential control t echnologies for VOC emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Good Burner Design and Operating Practices



# 9.21.2 Elimination of Technically Infeasible VOC Control Options

Table 9-40 summarizes the feasibility of potential c ontrol technologies for control of VOC emissions
from the vacuum degasser boiler. At 13 ppm VOC in the Vacuum Degasser Boiler exhaust, all addon controls are technically infeasible because this level is at or below the exhaust concentrations that

can be achieved with theses controls.

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## Table 9-40 Technical Feasibility of VOC Contro l Technologies for the Va cuum Degasser Boiler
VOC Emission Control Technologies Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize VOC to water and CO 2 

## . This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of VOC at lower temperatures than a thermal incinerator. No

Good Combustion Controls Good combustion control limits the formation of VOCs by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. Yes

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of particulate matter formed as a result of incomplete combustion. 

## Yes



# Thermal and catalytic oxidation using add on control de vices is considered technically infeasible in
this application due to the low concentrations of VOC in the boiler exhaust. At 13 ppm, boiler

exhaust VOC concentrations are at or below the level of control achievable by add on oxidation
controls. In addition, control cost calculations show that both thermal and catalytic oxidizers are
economically infeasible. Se e Attachment G Table G-1.



# 9.21.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness

The only remaining VOC control technologies are good combustion practices and good burner design
and operating practices.

Table 9-41 Ranking of Remaining VOC Control Technologies for the Vacuum Degasser Boiler

VOC Control Technology Ranking
Rank Technology % Efficiency

1 Good Burner Design and Operating Practices NA

Base Case

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# 9.21.4 Evaluation of Most E ffective VOC Control Technologies

Since the use of good combustion controls and good burner design and op erating practices are
inherent parts of the process no addi tional cost will be incurred. The detailed control cost analyses

are located in Attachment G.

Table 9-42 Evaluation of Most Effective VOC Control Technologies for the Vacuum Degasser Boiler

Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# 9.21.5 Vacuum Degasser Boiler VOC BACT Selection

Good Combustion Practices and Good Burner Design and Operating Practices are selected as BACT
for VOC control in the Vacuum Degasser Boiler. Use of natural gas, a clean fuel, in combination
with good combustion practi ces limits potential VOC emissions from the boilers.

Minnesota Steel proposes a BACT VOC emission limit of 0.006 lb VOC/MMBtu for the Vacuum
Degasser Boiler. The proposed VOC mass emissi on limit is 0.5 lbs of VOC per hour on a 24 hour
average basis. The proposed limit is based on compliance testing for VOC by EPA Method 25A

and/or Method 18 for determination of methane, ethane and individual VOC compounds. The mass

emission limit is based on operation with BACT controls and the facility running at full capacity.

Attachment L, Table L-42 contains a summary of BACT determinations from the EPA RBLC
database for natural gas-fired boi lers and heaters rated at 100 MMBt u/hr or less. The RBLC data

indicates Good Combustion Practices and use of natu ral gas as BACT for VOC control. The median

BACT limit for VOCs in Table L-42 is 0.006 lb VOC/MMBtu. Therefore, specifying good

combustion controls as BACT with a limit of 0.006 lb VOC/MMBtu is consistent with recent RBLC

BACT determinations.

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# RBLC VOC BACT Limits Summary

BACT-PSD VOC lb/MMBtu Emission Limits Other (non-BACT) VOC lb/MMBtu Emission Limits

MIN 0.002 lb/MMBtu MIN 0.004 lb/MMBtu MAX 1.0 lb/MMBtu MAX 0.08 lb/MMBtu MEDIAN 0.006 lb/MMBtu MEDIAN 0.005 lb/MMBtu
COUNT 35 CASES COUNT 3 CASES



# RBLC VOC BACT limits
Small Gas Fired Heaters & Boilers



# 0 2 4 6 8 10 12 14 16

0.002 0.004 0.006 0.008 0.01 0.02 0.04 0.06 0.1 > 0.1

VOC lb/MMBtuCount 

### Proposed BACT
Limit 0.006



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the Vacuum Degasser Boiler into service, and will continue this practice until the process is shut

down and off line. Therefore, Minnesota Steel is not proposing any special permit conditions for startup

and shutdown.



# 9.22 Continuous Slab Casters

9.22.1 Process Descriptions
The Minnesota Steel project will include two (2) con tinuous casters. Casters are used to form liquid
steel into continuous lengths of so lid steel. The liquid steel flows through drain holes in the tundish
and fills a continuous flow, water-cooled copper mold . The liquid steel solidi fies as it passes through
the mold and emerges from its bottom as seven to ten inch thick slab. After complete solidification,
the continuous slab proceeds to the tunnel furnace. Casting emissions are primarily the result of

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# metal fumes and casting powders released during cas ting. Air pollutants emitted during the casting
processes include PM and PM10. Emissions from the caster ar e routed to the melt shop baghouse

system.



# 9.22.2 Continuous slab Casters BACT Selection

Since the continuous caster partic ulate emissions are routed to the melt shop baghouse, the BACT
determination for the caster is the same as the EAF, and the caster emissions have been incorporated
into the proposed EAF BACT emission limit.



# 9.23 Tunnel Furnace

9.23.1 Process Description
The Minnesota Steel project will include a tunnel furnace. The solidified steel slabs produced with
the continuous slab casters are transferred to the tunnel furnace and are then pushed or pulled slowly
through the furnace to equalize the temper ature of the steel prior to rolling.

The Tunnel Furnace is nominally rated between 125 MMBtu/hr and 165 MMBtu/hr. It is fired by
112 natural gas burners. The temperat ure equalized slabs are fed to the start of the rotary drum shear
and descaler. The slab will then be rolled through a series of mill st ands that use hydraulic pressure

to achieve the finished sheet thickness desired. The sheet steel will be final trimmed and coiled for
rail or truck shipment.

Air pollutants emitted from the Tunnel Furnace include: PM, PM10, SO 2 

# , NO
x 

# , CO, VOC. All
emissions result from combustion of natural gas. Based on vendor data, the expected pollutant

concentrations in the Tunnel Furnace are as follows:

Pollutant Tunnel Furnace PM10 0.006 gr/dscf PM 0.006 gr/dscf SO2 < 1 ppm NOx 36 ppm CO 23 ppm VOC 10 ppm

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# 9.24 Tunnel Furnace Particulate Matter (PM/PM 10 

# ) Emissions

9.24.1 Identification of Potent ial PM Control Technologies

Particulate matter emissions from the Tunnel Furn ace are the result of na tural gas combustion.

Based on vendor information, the calculated PM/PM 10 

# concentration in the stack of the Tunnel
Furnace is 0.006 gr/dscf.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various PM/PM 10 

# control technologies are discussed in

Section 4.0 and Table 9-43. Potent ial control technologies for PM/PM 10 

# emissions are the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)

• Good Design Methods and Operating Practices



# 9.24.2 Elimination of Tech nically Infeas ible PM/PM 10 

# Control Options

Table 9-43 summarizes the fe asibility of potential PM control technologies on the Tunnel Furnace.
Details regarding the technologies that are technically infeasible are discussed in the subsequent

sections.

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## Table 9-43 Technical Feasibility of PM/PM 10 

## Control Technologies for the Tunnel Furnace

Summary of Control Technology Feasibility
Technology Description Feasible? Yes or No

Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. No

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. No

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. No

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. No

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. No

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. No

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of particulate matter formed as a result of incomplete combustion. Yes



# At a PM/PM 10 

# concentration of 0.006 gr/dscf in the T unnel Furnace exhaust, the use of add-on
controls is technically infeasible because th is concentration is at the limits of PM/PM 10 

# emissions
control technology. The emissions for the Tunn el Furnace are based on vendor information.

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# 9.24.3 Ranking of Remaining PM/PM 10 

# Control Technologies by Control Effectiveness
The only remaining control technology for control of PM/PM 10 

# emission from the Tunnel Furnace is
good burner design and operating practices.

Table 9-44 Ranking of Remaining PM/PM 10 

## Control Technologies for the Tunnel Furnace

PM / PM 10 

## Control Technology Ranking
Rank Technology % Efficiency

1 Good Burner Design and Operating Practices NA

Base Case



# 9.24.4 Evaluation of Most Effective PM/PM 10 

# Control Technologies

Since good burner design and operating practices is i nherent to the process no additional cost will be

incurred.

Table 9-45 Evaluation of Most Effective PM/PM 10 

## Control Technologies for the Tunnel Furnace

Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# 9.24.5 Tunnel Furnace PM/PM 10 

# BACT Selection

Good Burner Design and Operating Prac tices are se lected as BACT.

The proposed BACT PM/PM 10 

# limit for the Tunnel Furnace is good combustion practices and use of
natural gas. Use of natural gas, a clean fuel, in combination with good combustion practices limits
potential PM/PM 10 

# emissions.

The proposed mass emission limit for the Tunnel Furnace is 1 lb/hr of PM/PM 10 

# . The proposed limit
is based on compliance testing for PM by EPA Method 5, and PM 10 

# measured by EPA Methods 201
(or 201A) and 202 (or EPA approved modified Met hod 202 procedures). The mass emission limit is
based on operation with BACT controls and the facility running at full capacity.

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# Attachment L, Table L-30 contains a summary of BACT determinations for the Tunnel Furnace
operations from the EPA RBLC database. Table L- 30 shows that recent BA CT determinations for

tunnel furnaces boilers have specified use of natural gas as BACT for PM/PM 10 

# controls. Therefore,
specifying good combustion controls and use of natural gas as BACT is consiste nt with recent RBLC
BACT determinations. Only one tunnel furnace BACT determination was identified in the RBLC as

indicated in the table below.

TF RBLC BACT Limits Summary

BACT-PSD lb/MMBTU Emission Limits

PM10 0.0076 lb/MMBTU



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the Tunnel Furnace into service, and will conti nue this practice until the furnace is shut down and
off line. Therefore, Minnesota Steel is not pro posing any special permit conditions for startup and

shutdown.



# 9.25 Tunnel Furnace Visible Emissions

Visible emissions are the result of incomplete combustion of fuels in the Tunnel Furnace



# 9.25.1 Tunnel Furnace Visibl e Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

At the Tunnel Furnace, PM/PM 10 

# emissions are controlled by good combustion practices.

A 3% opacity limit is recommended as BACT for visible emissions from the Tunnel Furnace. i.e. the
average opacity of the Tunnel Furnace cannot exceed 3% for more the one 6-minute period during an

hour. If Minnesota Steel identifies visible emissions from the Tunnel Furnace of 3%, it will take
corrective action as soon as it is practicable to do so. An opacity limit of 3% is consistent with recent
RBLC determinations for gas fired heaters as shown in the table below.

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## Small Natural Gas Boiler RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 10 % Opacity MIN 5 % Opacity MAX 20 % Opacity MAX 40 % Opacity MEDIAN 20 % Opacity MEDIAN 20 % Opacity
COUNT 14 CASES COUNT 13 CASES



# See Attachment L, Table L-46 for a detailed listing of recent RBLC opacity determinations for small
natural gas fired heaters and boilers.



# 9.26 Tunnel Furnace Su lfur Dioxide (SO 2 

# ) Emissions

9.26.1 Identificati on of Potential SO 2 

# Control Technologies

Based on use of natural gas as the fuel for the Tunnel Furnace, the expected SO 2 

# concentration in the
flue gas from this heater is less than 1 ppm SO 2


# .

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various SO 2 

# control technologies are discussed in

Section 4.0 and Table 9-46. Pote ntial control technologies for SO 2 

# emissions are the following:

• Wet Scrubber

• Spray Dryer Absorption

• Wet Electrostatic Precipitator

• Dry Sorbent Injection

• Clean Fuel/ Good Combusti on Practices (Base Case)

• Good Design Methods and Operating Practices



# 9.26.2 Elimination of Te chnically Infeasible SO 2 

# Control Options

At less than 1 ppm SO 2 

# in the Tunnel Furnace, all add-on contro ls are technically infeasible because
1 ppm is at or below the exhaust concentrations that can be achieved with these controls.

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## Table 9-46 Technical Feasibility of SO 2 

## Control Technologies for the Tunnel Furnace

SO2 Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Wet Scrubber A wet scrubber is a vessel which is used to contact the flue gas with a liquid sorbent. Liquid sorbent can be applied by spraying, and / or a packed tower may be used. The sorbent chemically reacts with SO2 and removes it. No

Wet Electrostatic Precipitator In applications where a wet electrostatic precipitator (ESP) is used for particulate removal, it may also be used for SO2 removal. A wet ESP uses a water spray to remove particulate matter from the ESP collection plates. For SO2 removal, caustic is added to the water spray system, allowing the spray system to function as an SO2 absorber. No

Spray Dryer Absorption A dry or semi-dry sorbent material is sprayed into a vessel where it contacts the flue gas. The sorbent chemically reacts with SO2 and removes it. A fabric filter is used to collect the spent sorbent. No

Dry Sorbent Injection Dry sorbent (pulverized lime or limestone) is directly injected into the duct upstream of the fabric filter. SO2 reacts with sorbent and the solid particles are collected with a fabric filter. This process was developed as a lower cost option to conventional SDA technology No

Clean Fuel/ Good Combustion Practices (Base Case) Combust natural gas Yes



# 9.26.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness
The only remaining control technologies for control of SO 2 

# from the Tunnel Furnace are the use of
clean fuel and good combustion practices

Table 9-47 Ranking of Remaining SO 2 

## Control Technologies for the Tunnel Furnace

SO2 Control Technology Ranking

Rank Technology Estimated Control Efficiency

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the process

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# 9.26.4 Evaluation of Most Effective SO 2 

# Control Technologies

Since the use of clean fuel and good combustion prac tices is an inherent part of the process no

additional cost will be incurred.

Table 9-48 Evaluation of Most Effective SO 2 

## Control Technologies for the Tunnel Furnace

Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Clean Fuel/ Good Combustion Practices (Base Case) NA Inherent to the
process NA Inherent to the process NA NA



# 9.26.5 Tunnel Furnace SO 2 

# BACT Selection

Use of clean fuels (natur al gas) and good combustion practices are selected as BACT for the Tunnel

Furnace.

The proposed BACT SO 2 

# limit for Tunnel Furnace is to foll ow good combustion practices and to
combust natural gas. Use of natural gas, a clean fuel limits potential SO 2 

# emissions.

The proposed SO 2 

# mass emission limit for the T unnel Furnace is 0.1 lbs of SO 2 

# per hour on a 3 hour
average basis. The proposed limit is based on compliance testing for SO 2 

# by EPA Method 6C,

determination of SO 2 

# by instrumental methods. The mass emission limit is base d on operation with
BACT controls and the facility running at full capacity.

Attachment L, Table L-30 contains the single SO 2 

# BACT determination for Tunnel Furnace
operations from the EPA RBLC database. Table L-30 shows that the most recent BACT
determination for tunnel furnaces specified use of natural gas as BACT for SO 2 

# controls. Therefore,
specifying use of natural gas as BACT is consistent with rece nt RBLC BACT determinations.
Statistical analyses of the RBLC data are summarized in the table below.

TF RBLC BACT Limits Summary
BACT-PSD lb/MMBTU Emission Limits

SO2 0.0006 lb/MMBTU



# Since Minnesota Steel will use natural gas at all time s when the Tunnel Furnace is operating, no special
permit conditions are required to control SO 2 

# emissions during startup and shutdown.

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# 9.27 Tunnel Furnace Ni trogen Oxides (NO x 

# ) Emissions

9.27.1 Identification of Pote ntial NOx Control Technologies

NO
x 

# emissions from the Tunnel Furnac e are the result of thermal NO
x 

# associated with natural gas

combustion. Based on vendor information, the calculated NO
x 

# concentration in the stack of the
Tunnel Furnace is 36 ppm.

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various NO
x 

# control technologies are discussed in

Section 4.0 and Table 9-49. Pote ntial control technologies for NO
x 

# emissions are the following:

• Selective Catalytic Reduction

• Low Temperature Oxidation

• Selective Non-Catalytic Reduction

• Non-Selective Catalytic Reduction

• External Flue Gas Recirculation

• Low-NO
x 

# Burners and Induced Flue Gas Recirculation Burners

• Oxy-fuel Burners

• Low Excess Air (LEA)

• Other Combustion Controls



# 9.27.2 Elimination of Technicall y Infeasible NOx Control Options

Table 9-49 summarizes the feasibility of potential NO
x 

# control technologies for emissions from the
Tunnel Furnace. Details regarding the technologi es that are infeasible are discussed in the
subsequent sections.

Table 9-49 Technical Feasibility of NO x 

## Control Technologies for the Tunnel Furnace

NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Low Temperature Oxidation Low Temperature Oxidation is a process where NO x 

## is oxidized to form water soluble nitrate compounds which can easily be removed by absorption (wet scrubbing). Oxidation occurs at relatively low temperatures (100oF – 200oF) so it can be effectively used as an add-on control system where the stream to be treated is not hot enough for catalytic controls. Ozone is typically used as the oxidizing agent. No

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## NO
x 

## Emission Control Technology Feasibility Analysis
Technology Description Feasible? Yes or No

Selective Catalytic Reduction Selective catalytic reduction (SCR) is a postcombustion NO x 

## control technology in which ammonia (NH 3 

## ) is injected into the flue gas stream in the presence of a catalyst. SCR requires a temperature range of 500 ° F – 800 ° F. No

Selective Non-Catalytic Reduction The Selective non-catalytic reduction (SNCR) process injects urea or ammonia-based chemicals into the flue gas stream to convert NO to N 2 

## and water. The optimum operating temperature for SNCR is 1,600 ° F to 2,000 ° F. No

Non-Selective Catalytic Reduction Non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NO x 

## and CO react in the presence of NSCR catalyst to form nitrogen (N 2 

## ) and carbon dioxide (CO 2 

## ). It is typically employed in clean gas services such as natural gas fired turbines. No

External Flue Gas Recirculation External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures. In an external flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air and this mixture is introduced into the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x 

## . No

Low-NOx Burners and Induced Flue Gas Recirculation Burners Low-NO x 

## burner (LNB) technology utilizes advanced burner design to reduce NO x 

## formation through the restriction of oxygen, flame temperature, and/or residence time.

Induced flue gas recirculation burners are designed to draw flue gas into the burner to dilute the fuel. This reduces flame temperature and NO x 

## formation. Yes

Low Excess Air (LEA) Low Excess is a combustion control method which is used to reduce the amount of oxygen in the combustion zone of a furnace or boiler. This limits the amount of oxygen available for NO x 

## formation. No

Other Combustion Controls These combustion control methods are typically employed on existing sources. They inexpensive, but have limited control efficiencies. Combustion controls incl ude Overfire Air (OFA), Burners Out of Servic e (BOOS) and Load Reduction and Reduced Combustion Air Temperature. No

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## Selective Catalytic Reduction (SCR)


# SCR systems require relatively stab le flow rates and gas temperatures to work effectively. Tunnel
furnaces operate in a cyclic ma nner with non-steady flow and temp erature conditions. In March
2004, the Arkansas Department of Environmental Quality (AR DEQ) determ ined in its technical
support document for the BIR Steel permit that the overall emission reduc tion that SCR could
achieve in a tunnel furnace application would be insignificant. This conclusion is based on
difficulties presented by properly controlling the SCR ammonia injection rates for a cyclic process.
Either excessive ammonia slip would occur, or insufficient ammonia would be injected for NO
x 

# control. In its review, the AK DEQ referenced an Indiana Department of Environmental
Management (IDEM) permit determin ation for Beta Steel. Beta Steel had installed an SCR system
on a large slab reheating furnace. Beta Steel was unable to operate the SCR system effectively.

Based on the actual level emission control Beta Steel was able to achieve, IDEM concluded that SCR
performance was limited in this a pplication and IDEM revised the emis sion limit for this source from

0.014 lb NO
x 

# /MMBtu to 0.077 lb NO
x 

# /MMBtu. Based on manufact urer’s data, estimated NO
x 

# emissions from the Tunnel Furnace equipped with low NO
x 

# burners is 0.06 lb NO
x 

# /MMBtu, which is

similar the Beta Steel NO
x 

# limit with SCR and supports the conclusion that SCR is not effective in a
tunnel furnace application.

Selective Non-Catalytic Reduction (SNCR)


# SNCR provides effective NO
x 

# control for operations in which the NO
x 

# concentration and temperature
are relatively stable. However, tunnel furnace operations are variable. Therefore, it is anticipated
that SNCR will have similar problems controlling reagent injection as those encountered with SCR.
In addition, the variability in furnace temperatures will make it nearly impossible to inject the
reagent at the location where proper SNCR operating temperatures are present. In its review of
SNCR, the AR DEQ also found that SNCR would not be effective in a tunnel furnace application.

Non-Selective Catalytic Reduction (NSCR)


# Again, variability in tunnel furnace operation will ma ke application of NSCR in feasible. In addition,
the exhaust temperatures from these sources are too hot for NSCR catalyst operation. The NSCR
operating window is 300°F to 700°F. Th e Tunnel Furnace exhaust is 1160°F.

Low Temperature Oxidation (LTO)


# Variability in Tunnel Furnace oper ation will also make applicati on of LTO infeasible due to the
difficulty in controlling reagent a ddition. In the case of LTO, the control system would have to

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# control both ozone injection rates and the operation of the ozone generator. Given that this could not
be accomplished for SCR, whic h has a simpler control system, LTO should not be considered
feasible in this application.

Furthermore, according to the RBLC database (see Attachment L, Table L-12), LTO has not been

selected as BACT to control NO
x 

# emissions from tunnel furnaces . Therefore, Minnesota Steel

Industries concluded that it is not technicall y feasible to apply LTO technologies (Tri-NO
x 

# or LoTOx) to the tunnel furnace.

External Flue Gas Recirculation


# External flue gas circulation works by re-injecting flue gas into the gas burner combustion zone. The
flue gas dilutes combustion air or fuel to reduce flame temperatures thereby reducing NO
x 

# generation. Given the process va riability in the Tunnel Furnace, it is likely the changing conditions
and process control limitations will cause flame instability due to excessive flue gas re-injection.
Therefore flue gas recirculat ion is technically infeasible for the Tunnel Furnace.

Other Combustion Controls


# There are other combustion control methods typica lly employed on large existing sources such as
utility boilers which have relative ly constant operating conditions. They are relatively inexpensive

NO
x 

# controls, but have limited cont rol efficiencies. Other combustion controls include Overfire Air
(OFA), Burners Out of Service (BOOS) a nd Load Reduction and Reduced Combustion Air
Temperature. The Tunnel Furnace is a direct fired heater with operations that cycle with each steel
casting processed. The Tunnel Furnace does not ap proach the size and oper ating conditions present
in utility boilers. Therefore, these types of controls are not suitable and are considered technically

infeasible for the Tunnel Furnace.



# 9.27.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness
The remaining control technologies applicable to the melt shop are ranked by control effectiveness in

Table 9-50

.

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## Table 9-50 Ranking of Remaining NO x 

## Control Technologies for the Tunnel Furnace

NO x 

## Control Technology Ranking

Rank Technology Estimated % Control Efficiency

1 Low-NO x 

## Burners and Induced Flue Gas Recirculation Burners NA

Inherent Control

2 Low Excess Air (LEA) Implement as good operating practices



# 9.27.4 Evaluation of Most Effective NO x 

# Control Technologies

Due to the cyclic nature of the flow, NO
x 

# mass emission rates and stack temperatures from the

Tunnel Furnace, add-on controls for NO
x 

# removal are not feasible. Low NO
x 

# burners, which are an
inherent part of the process design, represen t a technically feasible means of reducing NO
x 

# emissions.

Table 9-51 Evaluation of Most Effective NO x 

## Control Technologies for the Tunnel Furnace

NOx Control Technology Effectiveness Evaluation

Rank Technology Amount Removed (tpy) Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Low-NOx Burners and Induced Flue Gas Recirculation Burners NA Inherent Controls NA Inherent Controls NA NA

2 Low Excess Air (LEA) NA Implement as good operating practices NA Implement

as good operating practices NA NA



# An analysis of the RBLC indicates that the steel mill tunnel furnaces listed in Attachment L

Table L-12 do not have a dd-on devices to control NO
x. 

# Instead, low NO
x 

# burners or oxy-fuel burners

have been selected as BACT for control of NO
x 

# emissions.



# 9.27.5 Tunnel Furna ce NOx BACT Selection

Based on the determination that low NO
x 

# burners are the only feasible NO
x 

# control option, and have

been selected as BACT in recent determinations, Minnesota Steel considers the use of low NO
x 

# burners to be BACT.

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# Minnesota Steel proposes a BACT NO
x 

# emission limit of 0.1 lb NO
x 

# /MMBtu. The proposed NO
x 

# mass emission limit is 5.0 lbs of NO
x 

# per hour on a 24 hour average basis. The proposed limit is
based on compliance testing for NO
x 

# by EPA Method 7E, determination of NO
x 

# by instrumental
methods. The mass emission limit is based on oper ation with BACT controls and the facility running
at full capacity.

Consistent with recent BA CT determinations as shown in Attach ment L, Table L-30, Minnesota Steel
proposes a BACT NO
x 

# limit of 0.1 lb NO
x 

# /MMBtu for the Tunnel Furnace and a total mass emissions
limit of 5 lb/hr NOx. Statistical analyses of the RBLC data are summarized in the table below.

TF RBLC BACT Limits Summary

BACT-PSD NOx Emission Limits

MIN 0.100 lb/t steel MAX 0.190 lb/t steel MEDIAN 0.145 lb/t steel
COUNT 2 CASES



# Periods of startup, shutdown and malfunction

For low NO
x 

# burners to effectively control NO
x 

# emissions, the Tunnel Furnace must be at sufficient
load for effective operation of the low NO
x 

# burners and for combustion controls to maintain low

levels of excess combustion air. Once the Tunne l Furnace has reached the appropriate operating

conditions; the Low NO
x 

# burners will be able to control NO
x 

# emissions as intended. Until the process
heater reaches the proper operating conditions Minn esota Steel cannot comply with the BACT limits
for normal operation. Th erefore, Minnesota Stee l proposes to follow “Good Air Pollution Control
Practices for Minimizing Emissions” and to limit emissions to the rates Attachment M, Table 1 as
BACT during startup and shutdown. G ood operating practices will include:

• 

# Operation of the Tunnel Furnace in a manner whic h minimizes the amount of time the heater is
operated at temperatures and firing rates which are outside the operating range effective NO
x 

# control by low NO
x 

# burners.

• 

# Operation of the Tunnel Furnace in a manner whic h minimizes the amount of time the heater is
operated at excess oxygen le vels higher than the operating range effective for NO
x 

# control by low

NO
x 

# burners.

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# Minnesota Steel will define good operating practices fo r minimizing emissions in its startup, shutdown
and malfunction plan. As noted in Section 4.8, pl ans for startup, shutdown and malfunction will follow
all safety requirements.

See Attachment M, Table 1, for a summary of proposed startup/shutdown emission limits.



# 9.28 Tunnel Furnace Carbon Mo noxide (CO) Emissions

CO emissions from the Tunnel Furnace are the result of incomplete natural gas combustion. Based

on vendor information, the calculated CO concentrati on in the stack of the Tunnel Furnace is 23 ppm.



# 9.28.1 Identification of Potent ial CO Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various CO control technologies ar e discussed in Section

4.0 and Table 9-52. Potential control tec hnologies for CO emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Good Burner Design and Operating Practices



# 9.28.2 Elimination of Technically Infeasible CO Co ntrol Options
Table 9-52 summarizes the feasibility of potential control technologies for CO emissions from the
Tunnel Furnace. At 23 ppm CO in the Tunnel Furnac e, all add-on controls ar e technically infeasible
because 23 ppm is at or below the exhaust concentra tions that can be achieved with theses controls.

As noted in the NO
x 

# review, variability in furnace operating conditions also makes add-on controls

infeasible.

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## Table 9-52 Technical Feasibility of CO Control Technologies for the Tunnel Furnace
CO Emission Control Technologie s Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize CO to CO 2


## . This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of CO at lower temperatures than a thermal incinerator. No

Good Combustion Controls Good combustion control limits the formation of CO by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. No

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of CO formed as a result of incomplete combustion. 

## Yes



# 9.28.3 Ranking of Remaining CO Control Technologies by Control Effectiveness
The only remaining CO control technology is good burner design and operating practices.

Table 9-53 Ranking of Remaining CO Technologies for the Tunnel Furnace

CO Control Technology Ranking

Rank Technology % Efficiency

1 Good Burner Design and Operating Practices NA

Base Case



# 9.28.4 Evaluation of Most Effe ctive CO Contro l Technologies
Since the use of good burner design and operating pr actices are inherent pa rts of the process no

additional cost will be incurred.

It should be noted that low NO
x 

# and ULNB burner designs have high er CO emissions that standard

burners. This is due to the fact that the comb ustion conditions (e.g. re duced flame temperatures)

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# needed to effectively reduce NO
x 

# emissions are not as effective at controlling CO emissions as
standard burner designs.

Table 9-54 Evaluation of Most Effective CO Control Technologies for the Tunnel Furnace

Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# 9.28.5 Tunnel Furnace CO BACT Selection
Good Burner Design and Operating Practices are se lected as BACT for CO control in the Tunnel

Furnace.

Minnesota Steel proposes a BACT CO emission limit for the Tunnel Furnace of 0.08 lb CO/MMBtu
for the DRI boilers. The proposed CO mass emis sion limit is 1.9 lbs of CO per hour on a 1 hour
average basis. The proposed limit is based on compliance testing for CO by EPA Method 10. The

mass emission limit is based on operation with BACT controls and the facility running at full
capacity.

Attachment L, Table L-30 contains the single CO BACT determination for tunnel furnace operations

found in the EPA RBLC database . Table L-30 shows that recent BACT determination for tunnel
furnaces have specifie d good combustion controls and use of na tural gas as BACT for CO. Therefore,
specifying the use of good combustion controls and na tural gas as BACT is c onsistent with recent

RBLC BACT determinations. The RBLC CO BACT data is summarized in the table below.

TF RBLC BACT Limits Summary
BACT-PSD lb/MMBTU Emission Limits

CO 0.1900 lb/MMBTU



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the Tunnel Furnace equipment into service, and w ill continue this practice until the furnace is shut

down and off line. Therefore, Minnesota Steel is not proposing any special permit conditions for startup

and shutdown.

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# 9.29 Tunnel Furnace Volatile Orga nic Compound (VOC ) Emissions

VOC emissions from the Tunnel Furnace are the result of incomplete natural gas combustion. Based

on vendor information, the estimated VOC concentrat ion in the stack of the Tunnel Furnace is 10

ppm.



# 9.29.1 Identification of Pote ntial VOC Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous VOC control technologi es are discussed in

Section 4.0 and Table 9-55. Potential control t echnologies for VOC emissions are the following:

• Thermal Oxidizer (Recuperative and Regenerative)

• Catalytic Oxidizer

• Good Combustion Controls

• Good Burner Design and Operating Practices



# 9.29.2 Elimination of Technically Infeasible VOC Control Options

Table 9-55 summarizes the feasibility of potential c ontrol technologies for control of VOC emissions
from the Tunnel Furnace. At 10 ppm VOC in the T unnel Furnace, all add-on c ontrols are technically
infeasible because 10 ppm is at or below the exhaus t concentrations that can be achieved with theses

controls.

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## Table 9-55 Technical Feasibility of VOC Control Technologies for the Tunnel Furnace
VOC Emission Control Technologies Considered for BACT Analysis
Technology Description Feasible? Yes or No

Thermal Oxidizer (Recuperative and Regenerative) A thermal oxidizer us es high temperature and residence time to oxidize VOC to water and CO 2 

## . This may be accomplished using an add on oxidizer or a duct burner. No

Catalytic Oxidizer Catalytic oxidizers use a bed of catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction rate and allows the conversion of VOC at lower temperatures than a thermal incinerator. No

Good Combustion Controls Good combustion control limits the formation of VOCs by providing sufficient oxygen in the combustion zone of a furnace or boiler for complete combustion to occur. No

Good Burner Design and Operating Practices Well designed and operated burners reduce the amount of particulate matter formed as a result of incomplete combustion. 

## Yes



# 9.29.3 Ranking of Remaining VOC Control Technologies by Control Effectiveness
The only remaining VOC control technology is good burner design and operating practices.

Table 9-56 Ranking of Remaining VOC Control Technologies for the Tunnel Furnace

VOC Control Technology Ranking

Rank Technology % Efficiency

1 Good Burner Design and Operating Practices NA

Base Case



# 9.29.4 Evaluation of Most E ffective VOC Control Technologies

Since the use of good burner design and operating pr actices are inherent pa rts of the process no

additional cost will be incurred.

It should be noted that low NO
x 

# and ULNB burner designs have high er CO emissions that standard

burners. This is due to the fact that the comb ustion conditions (e.g. re duced flame temperatures)
needed to effectively reduce NO
x 

# emissions are not as effective at controlling CO emissions as

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# standard burner designs. Because CO and VO C control requires similar combustion conditions,
control of VOCs may also be re duced with application of low NO
x 

# and ultra low NO
x 

# burners.

Table 9-57 Evaluation of Most Effective VOC Control Technologies for the Tunnel Furnace

Control Technology Effectiveness Evaluation

Rank Technology Amount
Removed (tpy) 

## Installed Capital Cost $ Annualized Cost ($MM) Control Cost ($/ton removed)

1 Good Burner Design and Operating Practices NA

Inherent Controls NA

Inherent

Controls NA NA



# 9.29.5 Tunnel Furna ce VOC BACT Selection
Good Burner Design and Operating Pr actices are sele cted as BACT for VOC control in the Tunnel
Furnace. The use of natural gas, a clean fuel, in combination with good combustion practices limits
potential VOC emissions to the rated heat input capacity of the Tunnel Furnace.

Minnesota Steel proposes a BACT VOC emission limit of 0.006 lb VOC/MMBtu for the Vacuum
Degasser Boiler. The proposed VOC mass emissi on limit is 0.5 lbs of VOC per hour on a 24 hour
average basis. The proposed limit is based on compliance testing for VOC by EPA Method 25A

and/or Method 18 for determination of methane, ethane and individual VOC compounds. The mass

emission limit is based on operation with BACT controls and the facility running at full capacity.

Attachment L, Table L-30 contains the singl e VOC BACT determination for tunnel furnace
operations found in the EPA RBLC database. Table L-30 shows that recent BACT determination for
tunnel furnaces have specified good combustion contro ls and use of natural gas as BACT for VOC.
Therefore, specifying the use of good combustion cont rols and natural gas as BACT is consistent

with recent RBLC BACT determinations. The RBLC VOC BACT data is summarized in the table

below.

TF RBLC BACT Limits Summary

BACT-PSD lb/MMBTU Emission Limits

VOC 0.0050 lb/MMBTU



# For periods of startup and shutdown, Minnesota Steel will follow good combustion practices while
putting the Tunnel Furnace into service, and will conti nue this practice until the furnace is shut down and

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# off line. Therefore, Minnesota Steel is not pro posing any special permit conditions for startup and

shutdown.



# 9.30 EAF Cooling Towers

9.30.1 Process Description
The steel mill cooling water system consists of sump s, circulation pumps, cooling towers and a clarifier
system. This system supplies cooling water to the EAF, ladles, casters and rolling mill.

Since all of the cooling towers at Minnesota Steel are similar in nature, this BACT report contains a
single section for cooling tower BACT analysis. S ee BACT report Section 13 for this analysis. In
summary, BACT for cooling towers is the installation of mist eliminators and limiting the Total

Dissolved Solids content of the cooling waster



# 9.31 Melt Shop Additive Material Handling

9.31.1 Process Description
In order to simplify the BACT report, emissions controls for additive material handing equipment
throughout the facility are reviewed in Section 12.0 of the BACT report. Melt shop operations require the
use of additives in the steel manufacturing and alloying processes. In general, additives are transferred
pneumatically. This includes transfers from delivery truc ks to storage bins and transfers from storage bins
to the process. Therefore, the emission control requ irements for additive material handling are slightly
different from control requirements for material hand ling of raw materials and products. BACT control
requirements for additive material handling are addressed in Section 12.0 of the BACT report.



# 9.31.2 Summary of BACT for Addi tive Handling in the Melt Shop

BACT for additive material handling in the melt shop area of the facility is the use of fabric filter bin
vents to control particulat e emissions from pneumatic transfers of additive materials. The proposed
BACT limit for particulate emissions (PM/PM 10 

# ) is 0.0025 gr/dscf as meas ured by EPA Method 5.

Minnesota Steel will put the melt shop additive handling emission control equipment into service
prior to commencing transfer operations and keep controls operating until the transfer is complete.
No excess emissions will occur as a result of control equipment startup/shutdown. Therefore,
Minnesota Steel is not proposing any special permit conditions for startup and shutdown.

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# 9.32 Fugitive Dust Emissions

9.32.1 Process Description
Sources of fugitive particulate emission from the melt shop include conveyors and material drops for
delivery of additives in lump form.

In order to simplify the BACT report, emission co ntrols for fugitive emission sources throughout the
facility are reviewed in Section 15.0 of the BACT re port. Fugitive dust sour ces reviewed in Section
15.0 includes particulate emissions from mining opera tions, tailings basins, unpaved roads, storage
piles, loading and unloading operations, and materi al drops from mobile equipment. Section 15.0
also includes a list of sources covered by the fugitive dust BACT analysis.



# 9.32.2 Summary of Fugitive Emissions BACT

Minnesota Steel will follow industry best practi ces for controlling fugitive dust emissions.

Minnesota Steel has prepared a fugitive dust control plan (Attachment O) which describes the

measures Minnesota Steel will take to control thes e emissions. Dust control measures listed in the
plan are consistent with dust control techniques used by other mining facilities in the area.

## Minnesota Steel Page - 302 Slag Processing 

# 10.0 Slag Processing

10.1 Slag Processing Overview

Slag from steel making is processed to recover iron for recycling. The balance of the slag is either
sold or disposed as solid waste.



# 10.1.1 Process Description
Slag from the steel making proce ss is poured into a pit and allowed to cool and solidify. The
solidified slag is crushed, screened and segregated into metallic and non-metallic stockpiles. Slag
with sufficient iron content is recycled. Non-metallic slag will be stockpiled for sale, re-use, or
disposal as a solid waste.

Sources of fugitive particulate emissions from slag handling operations at Minnesota Steel will
include slag screening, crushing, conveyor dr ops, unpaved roads, storage piles, loading and
unloading operations, and material drops from mobile equipment.

In order to simplify the BACT re port, emissions controls for fug itive emission sources throughout the
facility are reviewed in Section 15.0 of the BA CT report. Fugitive dust sources reviewed in
Section 15.0 includes mining opera tions, tailings basins, unpaved roads, storage piles, loading and
unloading operations, and material drops from mobile equipment. Section 15.0 also contains a
summary of sources covered by the fugitive dust BACT analysis.



# 10.1.2 Summary of Fugitive Emissions BACT

Minnesota Steel will follow industry best practi ces for controlling fugitive dust emissions.

Minnesota Steel has prepared a fugitive dust control plan (Attachment O) which describes the

measures Minnesota Steel will take to control thes e emissions. Dust control measures listed in the
plan are consistent with dust control techniques used by other mining facilities in the area.

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# 11.0 Material Handling – Transfers of Raw Materials Between Processes

11.1 Raw Material Handling Process Description

Material handling and crushing em ission units are grouped and consid ered together for the BACT
review. These sources represen t continuous movement of materi als between process areas or
between unit operations within a pr ocess area. Particulate matter emissions caused by the abrasion of
pellets and other solids rubbing against one another as they are transported from one process to the

next. These sources are in fixed locations; so, it is feasible to enclose areas where emissions are
generated. The Air Emissions In ventory, Appendix B, lists the material handli ng emission units,
stack numbers, and their associated potential to emit (PTE) particulate matter.

Material handling vents do not include combustion s ources or ore/steel process vents. Therefore,
material handling emission points are not so urces of condensable particulate matter.



# 11.2 Material Handling Particulate Matter (PM/PM 10 

# ) Emissions

11.2.1 Identification of Potential PM/PM 10 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in
Section 4.0 and Table 11-1. Each of the technologie s listed below must be used in conjunction with
an enclosure to capture the particulate matter so it can be routed to the control device. Potential
control technologies for PM emissions are the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)

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# 11.2.2 Elimination of Tech nically Infeas ible PM/PM 10 

# Control Options

Table 11-1 summarizes the feasibility of potential particulate control technologies for material
handling operations. All controls ar e considered technically feasible.

Table 11-1 Technical Feasibility of PM/PM 10 

## Control Technologies for Material Handling

Summary of Control Technology Feasibility
Technology Description Feasible? Yes or No

Fabric Filter Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. Yes Crushing, concentration and cold taconite pellet handling

No Hot taconite pellet

handling and DRI

pellet handling

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. Yes Crushing, concentration and

taconite pellet handling

No DRI pellet handling

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. Yes

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes

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# The air from finished pellet handling contains too much moisture to effectively and reliably apply a
baghouse. Condensation of moisture and condensable particulates w ill form a cake on the bags that

would be difficult to remove. In addition, it is possible to exceed filter bag temperature limits in
finished taconite pellet handling. Pellets leaving the pelletizer are very hot; so, air temperatures will
increase significantly during period of low air flow . This will cause bag failu res if air temperatures
the filter material temperature limits.

Dry iron dust is combustible, and presents a safe ty hazard. Therefore, baghouses and dry ESP’s are
not considered feasible in this application due to safety concerns.



# 11.2.3 Ranking of Remaining PM/PM 10 

# Control Technologies by Control Effectiveness
Particulate control technologies applicable to material handli ng operations are ranked based on

control effectiveness in Table 11-2.

Table 11-2 Ranking of Remaining PM/PM 10 

## Control Technologies for Material Handling

PM / PM 10 

## Control Technology Ranking

Rank Technology % Efficiency/Outlet

Concentration

1 Fabric Filter Fabric Filter (Baghouse) 98% - 99+% or 0.0025 gr/dscf*

2 Wet Scrubber 98% - 99+% or 0.005 gr/dscf*
3 Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

4 Wet Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

5 Centrifugal Separation (e.g. Cyclones) 50% - 80%

6 Inertial Separators (Drop Out Box) < 50%
....... * PM as measured by EPA Method 5



# 11.2.4 Evaluation of Most Effective PM/PM 10 

# Control Technologies

Material handling will be performed by conveyor belt or similar mech anical device. These are fixed
sources and particulate emission points that can be enclosed for collection and control of particulate
emissions. Baghou ses, wet scrubbers and ESP’s are all ca pable of controlling material handling
emissions. In cases where the particulate matter is magnetic, ESP’s are not feasible. Baghouses are
not feasible for taconite pellet handling around the pelletizer furnace due to the high temperature and
moisture content of the air exhausted from material handling equipment. At the DRI plant, wet

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# scrubbing is the preferred option fo r safety reasons. Dry iron dust s can spontaneously combust under
certain conditions; therefore it is not compatible with fabric filters. Wet scrubbing prevents
hazardous conditions associated with DRI dust from occurring.

Two material handling sources were evaluated for control costs of baghouses, scrubbers and ESP’s.
These evaluations showed that all control systems were economically feasible. The detailed control
cost analyses are located in Attachment H and I.

Table 11-3 Evaluation of Most Effective PM/PM 10 

## Control Technologies for Pelletizer—Hearth Layer Bin Material Handling

Control Technology Outlet Concentration Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Baghouse 0.0025 gr/dscf 680 $6,113,901 $1,115,524 $1,640

Wet Scrubber 0.005 gr/dscf 679 $974,410 $388,257 $572

Dry ElectroStatic Precipitator (ESP) 0.005 gr/dscf 679 $2,625,818 $466,071 $687

Wet Wall ElectroStatic Precipitator (WWESP) 0.005 gr/dscf 679 $6,475,115 $1,034,437 $1,524

*PM as measured by EPA Method 5



## Table 11-4 Evaluation of Most Effective PM/PM 10 

## Control Technologies for DRI Material Handling

Control Technology Outlet Concentration Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Dry ElectroStatic Precipitator (ESP) 0.005 gr/dscf* 

## 61.7 $831,104 $211,610 $3,430

Wet Scrubber 0.005 gr/dscf* 

## 61.7 $674,360 $353,525 $5,731

Baghouse 0.0025 gr/dscf* 

## 63.3 $1,019,106 $387,266 $6,117 *PM as measured by EPA Method 5



# Attachment L, Table L-32 is a listing of recent BACT determinations for material handling and
fugitive emissions at steel mills.



# 11.2.5 Material Handling PM/PM 10 

# BACT Selection

Consistent with recent BACT determinations for material handling as listed in Appendix I,

Tables I-31 and 32, and the Taconi te MACT standard for new source s, Minnesota Steel proposes a

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# BACT limit of 0.0025 gr/dscf for material handling sources controlled by baghouses and a BACT
limit of 0.005 gr/dscf for material handling source controlled by wet scrubbers . The proposed limits
are based on particulate emissions measured by EPA Method 5. The proposed limit is consistent
with the minimum particul ate matter limits found in the RBLC fo r this source category. The BACT
limit may be met by baghouses, wet scrubbers, ESPs or WESPs. BACT mass emission limits for
individual material handling sourc es are listed in Attachment N to the BACT report. Statistical
analyses of the RBLC data are summarized in the tables below.

MH & Fug RBLC PM10 BACT Limits Summary BACT-PSD PM10 gr/dscf Emission Limits

MIN 0.0025 GR/DSCF MAX 0.0100 GR/DSCF MEDIAN 0.0100 GR/DSCF
COUNT 11 CASES

MH & Fug RBLC PM BACT Limits Summary BACT-PSD PM gr/dscf Emission Limits

MIN 0.0025 GR/DSCF MAX 0.430 GR/DSCF MEDIAN 0.005 GR/DSCF
COUNT 11 CASES



# For periods of startup and shutdown, Minnesota St eel will put material handling particulate emission
control equipment into service prior to commencing operation of process equipment, and keep controls
operating until the process is shut dow n and off line. No excess emissions will occur as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.



# 11.3 Material Handling Visible Emissions

Visible emissions are the result of particulate mate rials which are generated during material handling
operations.

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# 11.3.1 Material Handling Visibl e Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

For material handling sources, PM/PM 10 

# emissions are controlled by fabric filters (baghouses) or wet

scrubbers.

A 5% opacity limit is recommended as BACT for visible emissions from material handling equipment
controlled by fabric filters. i.e. the average opacity of material handling equipment cannot exceed 5% for
more the one 6-minute period during an hour. If Minnesota Steel identifies visible emissions from
material handling equipment controlled by fabric f ilters of 5%, it will take corrective action as soon as it
is practicable to do so. An opacity limit of 5% is consistent with recent RBLC determinations for
material handling sources in the mining and steel ma king industries as shown in the table below.

MH & Fug RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 3 % Opacity MIN 10 % Opacity MAX 20 % Opacity MAX 20 % Opacity MEDIAN 10 % Opacity MEDIAN 10 % Opacity
COUNT 25 CASES COUNT 4 CASES



# See Attachment L, Table L-49 for a detailed listing of recent RBLC opacity determinations for material
handling equipment.

No opacity limit is recommended for material handling equipment where PM/PM 10 

# emissions are
controlled by wet scrubbers. Wet scrubber exhaust c ontains droplets of entrained scrubber water and the
exhaust gas is saturated with water vapor. The wa ter vapor condenses for form additional water droplets
when the exhaust plume comes in c ontact with the atmosphere. Both of these conditions contribute to
formation of a wet plume which is visible to the eye due solely to water droplets in the plume. Because of
the water in the exhaust stream it is impractical to measure opacity on these sources. Therefore, no

visible emission standard is recommended for mate rial handling sources controlled by wet scrubbers.

Proper operating practices and monitoring of the we t scrubber operating parameters will minimize the
amount of particulate emitted. Particulate emissions from the pelletizer will be well controlled; so, the
hood exhaust and waste gas streams will normally have negligible visible emissions. Monitoring of

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# scrubber operating parameters will enab le Minnesota Steel to identify conditions where visible emissions

could occur, and to take corrective measures.



# 11.4 Material Handling Fluoride (F-) Emissions

11.4.1 Identification of Potent ial F- Control Technologies

Fluoride salts are pre sent in trace quantities in the iron ore. It is emitted as a particulate along with
taconite ore and DRI pellet dust during material tran sfer operations. PM controls will also be used to
control fluoride particulate emission s. Descriptions of the various fluoride (PM) control technologies

are discussed in Section 4. 0 and Table 11-1. Each of the technol ogies listed below must be used in
conjunction with an enclosure to capture the particulate matter so it can be routed to the control
device. Potential control technologies for F- emissions are the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)



# 11.4.2 Elimination of Technically Infeasible F- Control Options

Table 11-5 summarizes the feasibility of potential fluoride control technologi es for material handling
operations. All controls are c onsidered technically feasible.

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## Table 11-5 Technical Feasibility of F- Control Technologies for Material Handling

Summary of Control Technology Feasibility
Technology Description Feasible? Yes or No

Fabric Filter Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. Yes Crushing, concentration and cold taconite pellet handling

No Hot taconite pellet handling and DRI pellet handling

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. Yes Crushing, concentration and

taconite pellet handling

No DRI pellet handling

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. Yes

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes



# 11.4.3 Ranking of Remaining F- C ontrol Technologies by Control Effectiveness
Fluoride emission technologies ap plicable to material handling operations are ranked based on

control effectiveness in Table 11-6.

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## Table 11-6 Ranking of Remaining F- Control Technologies for Material Handling

F- Control Technology Ranking

Rank Technology % Efficiency/Outlet Concentration for PM control

1 Fabric Filter Fabric Filter (Baghouse) 98% - 99+% or 0.0025 gr/dscf*

2 Wet Scrubber 98% - 99+% or 0.0051 gr/dscf*
3 Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

4 Wet Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

5 Centrifugal Separation (e.g. Cyclones) 50% - 80%

6 Inertial Separators (Drop Out Box) < 50%
* PM as measured by EPA Method 5



# 11.4.4 Evaluation of Most Effe ctive F- Contro l Technologies
Material handling will be performed by conveyor belt or similar mech anical device. These are fixed
sources and particulate emission points can be encl osed for collection and control of particulate
emissions. Baghou ses, wet scrubbers and ESP’s are all ca pable of controlling material handling
emissions. In cases where the particulate matter is magnetic, ESP’s are not feasible. Baghouses are
not feasible for taconite pellet handling around the pelletizer furnace due to the high temperature and
moisture content of the air exhausted from material handling equipment. At the DRI plant, wet
scrubbing is the preferred option fo r safety reasons. Dry iron dust s can spontaneously combust under
certain conditions; therefore it is not compatible with fabric filters. Wet scrubbing prevents
hazardous conditions associated with DRI dust from occurring.

Two material handling sources were evaluated for control costs of baghouses, scrubbers and ESP’s.
These evaluations showed that control systems were not economically feasible. A control efficiency
of 99% was used in the example control cost calculations. Control efficiencies used in the emission
inventory and proposed BACT limits in Attachment N may differ slightly for individual sources. The
detailed control cost analyses are located in Attachments H and I.

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## Table 11-7 Evaluation of Most Effective F- Control Technologies for Pelletizer—Hearth Layer Bin Material Handing

Control Technology Control Eff % Emission Reduction T/yr* Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Wet Scrubber 99% 

## 1.7E-02 $974,410 $388,257 $22,998,559

Dry ElectroStatic Precipitator (ESP) 99% 

## 1.7E-02 $2,625,818 $466,071 $27,607,908

Baghouse 99% 

## 1.7E-02 $6,113,901 $1,115,524 $66,078,547
Wet Wall ElectroStatic Precipitator (WWESP) 99% 

## 1.7E-02 $6,475,115 $1,034,437 $61,275,355

*F- emissions are less than 0.1 T/yr



## Table 11-8 Evaluation of Most Effective F- Control Technologies for DRI Material Handling

Control Technology Control Eff % Emission Reduction T/yr* Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Dry ElectroStatic Precipitator (ESP) 99% 

## 1.6E-02 $831,104 $211,610 $13,167,234

Wet Scrubber 99% 

## 1.6E-02 $674,360 $353,525 $21,997,770

Baghouse 99% 

## 1.6E-02 $1,019,106 $387,266 $24,097,245 *F- emissions are less than 0.1 T/yr



# Attachment L, Table L-13 is a listing of recent BACT determinations for material handling and
fugitive emissions at steel mills.



# 11.4.5 Material Handling F- BACT Selection

Consistent with recent BA CT determinations for material handli ng listed in Appendix I, Tables I-31

and 32, and the Taconite MACT standard for ne w sources, Minnesota St eel proposes a F- BACT
limit of 0.0025 gr/dscf for material handling sour ces controlled by baghouses and a BACT limit of
0.005 gr/dscf for material handling source controll ed by wet scrubbers. The proposed limits are
based on particulate emissi ons measured by EPA Me thod 5. The RBLC did not specify BACT limits
for F-. The BACT limit may be met by baghouses, wet scrubbers, ESPs or WESPs. BACT mass

emission limits for indivi dual material handling sources are list ed in Attachment N to the BACT

report.

For periods of startup and shutdown, Minnesota Steel will put material handling fluoride (particulate)
emission control equipment into service prior to co mmencing operation of process equipment, and keep

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# controls operating until the process is shut down and off line. No excess emissions will occur as a result
of control equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit
conditions for startup and shutdown.



# 11.5 Material Handling Lead (Pb) Emissions

11.5.1 Identification of Potential Pb Control Technologies

Lead salts are present in trace quan tities in the iron ore; therefore, lead is emitted as a particulate
along with ore dust during material tr ansfer operations. PM controls w ill also be used to control lead
particulate emissions. Descriptions of the variou s lead (PM) control tec hnologies are discussed in
Section 4.0 and Table 11-1. Each of the technologie s listed below must be used in conjunction with
an enclosure to capture the particulate matter so it can be routed to the control device. Potential
control technologies for Pb emissions are the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)



# 11.5.2 Elimination of Technically Infeasible Pb Control Options

Table 11-5 summarizes the feasibility of potential lead control technologies for material handling
operations. All controls are c onsidered technically feasible.

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## Table 11-9 Technical Feasibility of Lead Control Technologies for Material Handling

Summary of Control Technology Feasibility
Technology Description Feasible? Yes or No

Fabric Filter Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. Yes Crushing, concentration and cold taconite pellet handling

No Hot taconite pellet handling and DRI pellet handling

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. Yes Crushing, concentration and

taconite pellet handling

No DRI pellet handling

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. Yes *

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern in side of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes



# * Exceptions: Use of dry controls for DRI dust due to fire hazards, and use of ESP’s when magnetic materials would bind to the collection plates

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# 11.5.3 Ranking of Remaining Pb Control Technologies by Control Effectiveness
Lead emission technologies applic able to material handling opera tions are ranked based on control

effectiveness in Table 11-10.

Table 11-10 Ranking of Remaining Lead Control Technologies for Material Handling

Pb Control Technology Ranking

Rank Technology % Efficiency/Outlet Concentration for PM control

1 Fabric Filter Fabric Filter (Baghouse) 98% - 99+% or 0.0025 gr/dscf*

2 Wet Scrubber 98% - 99+% or 0.0051 gr/dscf*
3 Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

4 Wet Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

5 Centrifugal Separation (e.g. Cyclones) 50% - 80%

6 Inertial Separators (Drop Out Box) < 50%
...... * PM as measured by EPA Method 5



# 11.5.4 Evaluation of Most Effect ive Pb Control Technologies

Material handling will be performed by conveyor belt or similar mech anical device. These are fixed
sources and particulate emission points can be encl osed for collection and control of lead (PM)
emissions. Baghou ses, wet scrubbers and ESP’s are all ca pable of controlling material handling
emissions. In cases where the particulate matter is magnetic, ESP’s are not feasible. Baghouses are
not feasible for taconite pellet handling around the pelletizer furnace due to the high temperature and
moisture content of the air exhausted from material handling equipment. At the DRI plant, wet
scrubbing is the preferred option for safety reasons. At the DRI plan t, wet scrubbing is the preferred
option for safety reasons. Dry iron dusts can spontaneously combust und er certain conditions;
therefore it is not compatible with fabric filt ers. Wet scrubbing prevents hazardous conditions
associated with DRI dust from occurring.

Two material handling sources were evaluated for control costs of baghouses, scrubbers and ESP’s.
These evaluations showed that control systems were not economically feasible. A control efficiency
of 99% was used in the example in the control cost calculations. Control efficiencies used in the
emission inventory and proposed BA CT limits in Attachment N may differ slightly for individual
sources. The detailed control cost analyses are located in Attachments H and I.

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## Table 11-11 Evaluation of Most Effective Lead Control Technologies for Pelletizer—Hearth Layer Bin Material Handing

Control Technology Control Eff % Emission Reduction T/yr* Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Wet Scrubber 99% 

## 6.8E-04 $974,410 $388,257 $575,041,859

Dry ElectroStatic Precipitator (ESP) 99% 

## 6.8E-04 $2,625,818 $466,071 $690,291,177

Baghouse 99% 

## 6.8E-04 $6,113,901 $1,115,524 $1,652,187,436
Wet Wall ElectroStatic Precipitator (WWESP) 99% 

## 6.8E-04 $6,475,115 $1,034,437 $1,532,091,371

*Pb emissions are less than 0.1 T/yr



## Table 11-12 Evaluation of Most Effective L ead Control Technologies for DRI Material Handling

Control Technology Control Eff % Emission Reduction T/yr* Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Dry ElectroStatic Precipitator (ESP) 99% 

## 6.4E-04 $831,104 $211,610 $329,180,860

Wet Scrubber 99% 

## 6.4E-04 $674,360 $353,525 $549,944,248

Baghouse 99% 

## 6.4E-04 $1,019,106 $387,266 $602,431,118 *Pb emissions are less than 0.1 T/yr



# Attachment L, Table L-13 is a listing of recent BACT determinations for material handling and
fugitive emissions at steel mills.



# 11.5.5 Material Handling Pb BACT Selection

Consistent with recent BA CT determinations for material handli ng as listed in Appendix I, Tables

I-31 and 32, and the Taconite MACT standard for new sources, Minnesota Steel proposes a Pb
BACT limit of 0.0025 gr/dscf for material handlin g sources controlled by baghouses and a BACT
limit of 0.005 gr/dscf for material handling source controlled by wet scrubbers . The proposed limits
are based on particulate emissions measured by EPA Method 5. The RBLC did not specify BACT
performance limits for Pb. RBLC mass emission limits for Pb are listed in Table L-34. The BACT
limit may be met by baghouses, wet scrubbers, ESPs or WESPs. BACT mass emission limits for
individual material handling sour ces are listed in Attachment N to the BACT report.

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# For periods of startup and shutdown, Minnesota Steel will put material handling Pb (particulate) emission
control equipment into service prior to commencing operation of process equipment, and keep controls
operating until the process is shut dow n and off line. No excess emissions will occur as a result of control
equipment startup/shutdown. Therefore, Minnesota Steel is not proposing any special permit conditions
for startup and shutdown.

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# 12.0 Additive Material Handling

12.1 Additive Material Hand ling Process Description

Additive receiving and handling includes the ra ilcar or truck unloading of additives such as
limestone, hydrated lime, and car bon, transfer to the additive st orage silos and the transfer of
additives to day bins. In general, these materials are transferred pneumatically to enclosed storage
vessels. Particulate matter emissions are due dust contained in the additives becoming entrained in
the air used to pneumatically transfer additive ma terials. The individual emission units and stack

numbers of additive material ha ndling sources are listed in the Air Emissions Inventory, Appendix

B3.

Additive material handling vents do not include co mbustion sources or ore/steel process vents.
Therefore, material handling emission points are not sources of condensable particulate matter.



# 12.2 Additive Material Handling Pa rticulate Matter (PM) Emissions

12.2.1 Identification of Potent ial PM Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various PM control technologies ar e discussed in Section

4.0 and Table 12-1. Potential control technologies for PM/PM 10 

# emissions are the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)



# 12.2.2 Elimination of Technically Infeasible PM Control Options

Table 12-1 summarizes the technical feasibility of particulate control technologies for emissions
from additive material handling operations. All controls are considered technically feasible.

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## Table 12-1 Technical Feasibility of PM/PM 10 

## Control Technologies for Additive Material Handling

Summary of Control Technology Feasibility
Technology Description Feasible? Yes or No

Fabric Filter Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. Yes *

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. Yes *

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. Yes *

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes

* Exceptions: Use of dry controls for DRI dust due to fire hazards, and use of ESP’s when magnetic materials would bind to the collection plates

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# 12.2.3 Ranking of Remaining PM Control Technologies by Control Effectiveness
Particulate control technologies applicable to additive receiving and handling operations are ranked

based on control effectiveness in Table 12-2.

Table 12-2 Ranking of Remaining Control Te chnologies for Additive Material Handling

PM / PM 10 

## Control Technology Ranking

Rank Technology % Efficiency/Outlet

Concentration

1 Fabric Filter Fabric Filter (Baghouse) 98% - 99+% or 0.0025 gr/dscf*

2 Wet Scrubber 98% - 99+% or 0.005 gr/dscf*
3 Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

4 Wet Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

5 Centrifugal Separation (e.g. Cyclones) 50% - 80%

6 Inertial Separators (Drop Out Box) < 50%
* PM as measured by EPA Method 5



# 12.2.4 Evaluation of Most Effect ive PM Control Technologies
Additive receiving and handling wi ll be performed pneumatically and the compressed air transfer
medium will be separated from solid material. A fabric filter is one of the most effective control
technology available for the control of PM and PM 10 

# from additive receiving and handling. The
detailed control cost analyses are located in Attachment J.

Table 12-3 Evaluation of Most Effective PM Control Technologies for Additive Material Handling

Control Technology Outlet Concentration Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Wet Scrubber 0.005 gr/dscf* 

## 18.7 $28,454 $32,180 $1,719

Baghouse 0.0025 gr/dscf* 

## 18.7 $63,096 $36,469 $1,945

Dry ElectroStatic Precipitator (ESP) 0.005 gr/dscf* 

## 18.7 $110,499 $42,254 $2,257

* PM as measured by EPA Method 5



# Attachment L, Table L-13 is a li sting of recent BACT determina tions for material handling and
fugitive emissions at steel mills. Table L-13 shows that fabric filters are widely used to control

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# particulate matter from material transfers into silos and storage bins and are routinely selected as
BACT. Fabric filters are the pref erred method of control as the vari able nature of additive transfer
could adversely affect the performa nce of a wet scrubber or electrostat ic precipitator. In addition,

most additive material transfer sources are too small for cost effe ctive installation of a scrubber or

ESP.



# 12.2.5 Additive Material Handling PM BACT Selection

Fabric filters are a top particulate emission contro l option and are routinely selected as BACT for

additive material transfers; therefore, Minnesota Steel considers fabric filters to be BACT.

Consistent with recent BA CT determinations for additive material transfers as listed in Appendix I,

Tables I-31 and 32, Minnesota Stee l proposes a BACT limit of 0.005 gr/dscf, as measured by EPA

Method 5, for additive material transfers. BA CT mass emission limits for individual material
handling sources are listed in Attachment N to the BACT report. Statistica l analyses of the RBLC

data are summarized in the tables below.

MH & Fug RBLC PM10 BACT Limits Summary BACT-PSD PM10 gr/dscf Emission Limits

MIN 0.0025 GR/DSCF MAX 0.0100 GR/DSCF MEDIAN 0.0100 GR/DSCF
COUNT 11 CASES

MH & Fug RBLC PM BACT Limits Summary BACT-PSD PM gr/dscf Emission Limits

MIN 0.0025 GR/DSCF MAX 0.430 GR/DSCF MEDIAN 0.005 GR/DSCF
COUNT 11 CASES



# Minnesota Steel will put the additive handing em ission control equipment into service prior to
commencing transfer operations, and keep controls operating until the transfer is complete. No

excess emissions will occur as a result of control equipment startup/shutdown . Therefore, Minnesota
Steel is not proposing any special permit conditions for startup and shutdown.

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# 12.3 Additive Material Hand ling Visible Emissions

Visible emissions are the result of particulate mate rials which are generated during additive material
handling operations.



# 12.3.1 Additive Material Handling Visible Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

For additive material handling sources, PM/PM 10 

# emissions are controlled by fabric filters (baghouses) or

wet scrubbers.

A 5% opacity limit is recommended as BACT for visible emissions from additive material handling
equipment controlled by fabric filters. i.e. the av erage opacity of additive material handling equipment
cannot exceed 5% for more the one 6-minute period during an hour. If Minnesota Steel identifies visible
emissions from material handling equipment controlled by fabric filters of 5%, it will take corrective
action as soon as it is practicable to do so. An opac ity limit of 5% is consistent with recent RBLC
determinations for material handling sources in th e mining and steel making industries as shown in the

table below.

MH & Fug RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 3 % Opacity MIN 10 % Opacity MAX 20 % Opacity MAX 20 % Opacity MEDIAN 10 % Opacity MEDIAN 10 % Opacity
COUNT 25 CASES COUNT 4 CASES



# See Attachment L, Table L-49 for a detailed listing of recent RBLC opacity determinations for material
handling equipment.

No opacity limit is recommended for additive material handling equipment where PM/PM 10 

# emissions are
controlled by wet scrubbers. Wet scrubber exhaust c ontains droplets of entrained scrubber water and the
exhaust gas is saturated with water vapor. The wa ter vapor condenses for form additional water droplets
when the exhaust plume comes in c ontact with the atmosphere. Both of these conditions contribute to
formation of a wet plume which is visible to the eye due solely to water droplets in the plume. Because of
the water in the exhaust stream it is impractical to measure opacity on these sources. Therefore, no

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# visible emission standard is recommended for add itive material handling sources controlled by wet

scrubbers.

Proper operating practices and monitoring of the we t scrubber operating parameters will minimize the
amount of particulate emitted. Particulate emissions from the pelletizer will be well controlled; so, the
hood exhaust and waste gas streams will normally have negligible visible emissions. Monitoring of
scrubber operating parameters will enab le Minnesota Steel to identify conditions where visible emissions

could occur, and to take corrective measures.



# 12.4 Additive Material Handli ng Fluoride (F-) Emissions

12.4.1 Identification of Potent ial F- Control Technologies

Fluoride salts are present in fluorspar (calcium fluorite CaF 2 

# ); it is not present in any of the other

additives used at Minnesota Steel. It is emit ted as a particulate along with dust emitted during
fluorspar material transfer operations . PM controls will also be used to control fluoride particulate
emissions. Descriptions of the various fluori de (PM) control technol ogies are discussed in
Section 4.0 and Table 12-4. Each of the technologie s listed below must be used in conjunction with
an enclosure to capture the particulate matter so it can be routed to the control device. Potential
control technologies for F- emissions are the following:

• Fabric Filter (Baghouse)

• Wet Scrubber

• Electrostatic Precipitator

• Wet Electrostatic Precipitator

• Centrifugal Separation (Cyclones)

• Inertial Separators (Drop Out Box)



# 12.4.2 Elimination of Technically Infeasible F- Control Options

Table 12-4 summarizes the technica l feasibility of fluoride control technologies for emissions from
additive material handling operations. All co ntrols are considered technically feasible.

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## Table 12-4 Technical Feasibility of F- Control Technologies for Additive Material Handling

Summary of Control Technology Feasibility
Technology Description Feasible? Yes or No

Fabric Filter Fabric Filter
(Baghouse) A fabric filter, or baghouse, consists of a number of fabric bags placed inside an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. Yes

Wet Scrubber Wet scrubbers, remove pa rticles from waste gas by capturing the particles in liquid droplets (usually water) and separating the droplets from the gas stream. The droplets transport the particulate out of the gas stream. Yes

Electrostatic Precipitator An electrostatic precipitator applies electrical forces to separate particles from the flue gas stream. Particles are given an electrical charge. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal

. Yes

Wet Electrostatic Precipitator A Wet ESP operates on the same collection principles as a dry ESP, and uses a water spray to remove particulate matter from the collection plates. Yes

Centrifugal Separation
(e.g. Cyclones) Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of the top the cyclone. Yes

Inertial Separators

(Drop Out Box) A drop-out box uses inertial separation to remove the larger particles from the smaller one. This is usually initiated by a change in flow direction. Inertial separation may be augmented by gravitational settling. Yes



# 12.4.3 Ranking of Remaining F- C ontrol Technologies by Control Effectiveness
Particulate control technologies applicable to additive receiving and handling operations are ranked

based on control effectiveness in Table 12-5.

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## Table 12-5 Ranking of Remaining Control Te chnologies for Additive Material Handling

F- Control Technology Ranking

Rank Technology % Efficiency/Outlet Concentration for PM control

1 Fabric Filter Fabric Filter (Baghouse) 98% - 99+% or 0.0025 gr/dscf*

2 Wet Scrubber 98% - 99+% or 0.005 gr/dscf*
3 Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

4 Wet Electrostatic Precipitator 98% - 99+% or 0.005 gr/dscf*

5 Centrifugal Separation (e.g. Cyclones) 50% - 80%

6 Inertial Separators (Drop Out Box) < 50%
* PM as measured by EPA Method 5



# 12.4.4 Evaluation of Most Effe ctive F- Contro l Technologies
Additive receiving and handling wi ll be performed pneumatically and the compressed air transfer
medium will be separated from solid material. A fabric filter is one of the most effective control
technologies available for the control of F- (PM) from additive receiving and handling. A control
efficiency of 99% was used in the example control cost calculations. Control efficiencies used in the
emission inventory and proposed BA CT limits in Attachment N may differ slightly for individual
sources. The detailed control cost analyses are located in Attachment J.

Table 12-6 Evaluation of Most Effective F- Cont rol Technologies for Additive Material Handling

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton

Wet Scrubber 99% 

## 2.20 $28,454 $32,180 $14,657

Baghouse 99% 

## 2.20 $63,096 $36,469 $16,611 Dry ElectroStatic Precipitator (ESP) 99% 

## 2.20 $110,499 $42,254 $19,246



# Please note that the fluorspar bin emissions rates used for these calculations are one to two orders of
magnitude higher that any other addi tive storage bin. So, the fluoride control costs for the balance of
the storage bins will be ten to one hundred ti mes higher that the fluorspar bin control cost.

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# Attachment L, Table L-13 is a listing of recent BACT determinations for material handling and
fugitive emissions at steel mills. Table L-13 shows that fabric filters are widely used to control
particulate matter from material transfers into silos and storage bins and are routinely selected as
BACT. Fabric filters are the pref erred method of control as the vari able nature of additive transfer
could adversely affect the performa nce of a wet scrubber or electrostat ic precipitator. In addition,

most additive material transfer sources are too small for cost effe ctive installation of a scrubber or

ESP.



# 12.4.5 Additive Material Handling F- BACT Selection

Based on the fact that fabric filt ers are a top control option and are routinely selected as BACT for

additive material transfers, Minnesota Steel considers fabric filters to be BACT. Consistent with
recent BACT determinations for additive material transfers as listed in Appendix I, Tables I-31 and
32, Minnesota Steel proposes a F- BACT limit of 0. 0025 gr/dscf of particulates , as measured by EPA

Method 5, for additive material transfers. The RBLC did not specify BACT limits for F-. The
BACT limit may be met by baghouses , wet scrubbers, ESPs or WESPs. BACT mass emission limits
for individual material handling sources are list ed in Attachment N to the BACT report.

Minnesota Steel will put the additive handing F- (particulate) emission control equipment into
service prior to commencing transfer operations an d keep controls operatin g until the transfer is
complete. No excess emissions will occur as a result of control equipment startup/shutdown.
Therefore, Minnesota Steel is not proposing any sp ecial permit conditions fo r startup and shutdown.

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# 13.0 Cooling Towers

13.1 Cooling Tower Process Description

The DRI plant, melt shop and rolling mill use water as a cooling medi um to control process
temperatures. The DRI plant and steel mill cooling water systems consists of sumps, circulation
pumps, cooling towers and a clar ifier system. This system suppl ies cooling water to the direct
contact coolers and process water uses including th e top gas scrubber and reformed gas cooler. Cool
water is circulated through these systems to remove the heat from these processes. The hot water
return from heat exchangers and cooling water jackets is cooled in cooling towers.

Cooling towers reduce the temperat ure of water in the cooling water system by evaporative cooling.
A cooling tower consists of a fan, water distribution system, drift el iminator, contact tower and water
sump. Hot cooling water enters the top of the c ooling tower through a water distribution system and
flows down through a contact tower and into a recove ry sump. Some of the water evaporates as it
flows through the contact tower, a nd its temperature is reduced. The sides and/or bottom sections of
the contact tower are louvered to let air into the cooling tower. The top of the cooling tower has a
fan to draw air through the cooling tower. The contac t tower is filled with c ontact grates or packing,
which are designed to maximize air water contact inside the cooling tower for more efficient cooling
tower operation.

Fine water droplets are generated inside the contact section due to water splashing against the contact
plates and/or packing. Air movement through th e cooling tower draws these droplets towards the
fan. These water droplets are vented to the at mosphere as cooling tower “drift” through the cooling
tower fan. As water in these droplets evaporates, mineral salts in the water are left behind as
airborne partic ulate matter.

There are two means to reduce particulate emissions from cooling towers:

1. Install a drift eliminator at the top of the contact section. The drift eliminator is a porous media, which is used to capture these fine droplets agglomerate them and return the accumulated water back to the cooling tower.

2. Control the amount of dissolved minerals in the cooling water by limiting the TDS (Total Dissolved Solids) content of the cooling water. Water evaporation inside the cooling tower concentrates the mineral content of the cooli ng water. To counteract this, some water is removed from the tower (blowdown) and is re placed with fresh waster. Good operating

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# practices are employed to balance water cons umption via blowdown against acceptable TDS concentrations.



# 13.2 Cooling Towers Particulate Matter (PM) Emissions

13.2.1 Identification of Potent ial PM Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in
Section 4.0. Potential control technolog ies for PM emissions are the following:

• Drift Eliminators (Base Case)

• Follow good operating practices for limiting Tota l Dissolved Solids (TDS) in cooling water



# 13.2.2 Elimination of Technically Infeasible PM Control Options

The second step in the top-down BACT analysis is the elimination of techni cally infeasible control
technology options. For the DRI and Steel Mill co oling towers, there are no control technologies
identified that are not technically feasible.



# 13.2.3 Ranking of Remaining PM Control Technologies by Control Effectiveness
The drift eliminator and cooling water TDS control are the only viable cooling tower control option,
so a formal ranking is not required.



# 13.2.4 Evaluation of Most Effe ctive PM Contro l Technologies

Because the drift eliminator and cooling water TDS control are th e only viable control option, no
comparative performance, cost and ot her impacts analysis was conducted.

In order to reduce the TDS conten t of cooling water, some cooling water must be removed from the
cooling system and replace d with fresh water. Good operating practices are employed to balance
water consumption via bl owdown against acceptable TDS concentrations.



# 13.2.5 Cooling Towers PM BACT Selection

The BACT for cooling towers is:

• 

# Install drift eliminators which have a 0.005% drift rate specification. A 0.005% drift rate is consistent
with the lowest drift rate for cooling towers located at steel production facilities. A summary of the
RBLC data for steel production c ooling towers is listed below.

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## CT RBLC PM BACT Limits Summary
BACT-PSD PM %dri ft Emission Limits

MIN 0.005 %drift
MAX 0.008 %drift
MEDIAN 0.007 %drift
COUNT 3 CASES

• 

# Employ good operating practices for cooling water TDS control.

• 

# Insufficient vendor data for cooling tower circulati on rates are available at this time to specify mass

emission limits.
The summary of the RBLC search information for Minneso ta Steel’s cooling towers is in Attachment L

Table L-37.

Minnesota Steel will follow the BACT operating prac tices during start up and shutdown; so, no special
permit conditions are needed to startup and shutdown.



# 13.3 Cooling Tower Visible Emissions

Visible emissions from cooling towers are the result of particulate materials associated with dissolved
solids in cooling water droplets which are en trained in the cooling tower exhaust.



# 13.3.1 Cooling Tower Visible Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

In cooling towers, PM/PM 10 

# emissions are controlled by mist eliminators. Cooling tower exhaust
contains droplets of entrained coo ling water and the exhaust gas is satur ated with water vapor. The water
vapor condenses for form additional water droplets wh en the exhaust plume comes in contact with the
atmosphere. Both of these conditions contribute to fo rmation of a wet plume which is visible to the eye
due solely to water droplets in the plume. Because of the water in the exhaust stream it is impractical to
measure opacity on these sources. Therefore, a visible emission limt of 20% is recommended for the
cooling towers.

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# Proper operating practices and maintenance of the c ooling tower mist eliminators will minimize the
amount of particulate emitted. Monitoring of coolin g tower operating parameters will enable Minnesota
Steel to identify conditions where visible emissions could occur, and to take corrective measures.

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# 14.0 Emergency Generators & Pumps

14.1 Emergency Generators and Pumps Overview

Minnesota Steel will have a number of diesel powered emergency generato rs and pumps. This
emergency equipment is needed to supply electric ity, cooling water and fire water to critical
equipment in the event of a power failure, fire or other emergency. The capacity of emergency pumps
and generators is limited; it is not sized to operate the entire facili ty. Total capacity of the generators
and pumps is 6012 KW.

It is expected that the emergency equipment will rarely be operated for extended periods of time as
emergency events requiring their use should be infr equent. The most likely operating scenario is
operation for short periods of time to make sure the equipment is fully functional and available for
operation should an emergency arise.

In addition to the control technol ogies referenced in Section 4, the control technology review for
diesel powered emergenc y generators and pumps will includ e Emergency Generator Classification
(EGC) as a control option. This means that these sources will only operate for a limited number of
hours (< 500 hrs/yr), and only under limited circ umstances such as em ergency conditions and
periodic testing.

As noted in Section 3.5.4, EPA has recently prom ulgated NSPS Subpart I III emission standards for
stationary diesel engines. The new standard limits PM, NO x, 

# CO and VOC emissi ons from diesel
engines. For diesel engines in the size range Minnesota Steel Industries will use for emergency
equipment, these limits can be met with combustion controls, and no add-on emission controls will
be required. Subpart I III has emission limits based on the serv ice of the stationary diesel. The
service classifications include separate categories for emergency fire pump engines and non-fire
emergency use engines. SO 2 

# emissions will be limited by Subpart IIII fuel specifications. The
emergency use classifica tion is for engines operated for 100 hours per year or less. The BACT
control analysis is based on 500 hr/year of operati on. It is still valid at 100 hr/yr because emission
controls on a $/ton basis are more expensive at lower emission rates.

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# 14.2 Emergency Generato rs and Pumps Partic ulate Matter (PM) Emission Controls

Particulate matter emissions are created by combustion of low sulfur No. 2 fuel oil.



# 14.2.1 Identification of Potential PM Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous PM control technologies are discussed in
Section 4.0. Potential control technolog ies for PM emissions are the following:

• Good Combustion Practices

• Emergency Generator Classification

• Oxidation Catalyst

• Diesel Filter



# 14.2.2 Elimination of Technically Infeasible PM Control Options

Table 14-1 summarizes the technical feasibility of particulate control technologies for emissions
from diesel generators. The identified control technologies for PM emissions control are all
technically feasible.

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## Table 14-1 Technical Feasibility of PM Control Technologies for Emergency Diesel Generators and Pumps

Summary of Control Technology Feasibility


## Technology Description Feasible? Yes or No

Good Combustion Practices Good combustion practices are preventative measures that minimize the release of pollutants into the environment. Good combustion practices may include the proper design and maintenance of equipment, good housekeeping, and good operating practices. Yes

Emergency Generator Classification The proposed diesel generator is classified as an emergency generator that is anticipated to operate <500 hours per year. This limitation will effectively minimize particulate matter emissions. Yes

Oxidation Catalyst Add-on control using precious metals impregnated onto a high geometric surface area carrier that is placed in the exhaust stream. Yes

Diesel Filter Add-on control consisting of a filter positioned in the exhaust stream Yes



# 14.2.3 Ranking of Remaining PM Control Technologies by Control Effectiveness
Particulate control technologies applicable to emerge ncy generators are ranked based on control

effectiveness in Table 14-2.

Table 14-2 Ranking of Remaining Control Technologies for Emergency Diesel Generators and Pumps

PM Control Technology Ranking



## Rank Technology Estimated Control Efficiency

1 Emergency Generator Classification Minimum 98%

2 Diesel Filter 90% 3 Oxidation Catalyst 30% 4 GCP Varies by Design

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# 14.2.4 Evaluation of Most Effect ive PM Control Technologies and Documentation of Results
Oxidation catalyst and diesel filters can be elim inated as control technologi es based on excessive
dollar per ton control cost values for engines limi ted to emergency use. The detailed control cost
analyses are located in Attachment K.

Table 14-3 Evaluation of Most Effective PM / PM 10 

## Control Technologies for Emergency Generators and Pumps

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Emergency Generator Classification Minimum 98% 30.38* NA NA 

## Site Specific

Good Combustion Practices Varies by Design NA NA NA 

## Site Specific

Oxidation Catalyst 30% 0.53 $5,031,939 $552,480 $1,040,452



## Diesel Filter 90% 1.59 $4,206,913 $461,896 $289,954

* for 8760 hrs



# 14.2.5 Emergency Generators and Pumps PM BACT Selection

Emergency Generator Classification combined with Good Combustion Practices is ranked as the highest
control efficiency technology. Therefore, Emer gency Generator Classification combined with Good

Combustion Practices is BACT for control of PM emi ssions. Minnesota Steel Industries will also comply
with NSPS Subpart IIII emission limits for stationary emergency diesels as applicable based on the model
year size and service of the engine.

Minnesota Steel will follow BACT operating practices during start up and shutdown; so, no special
permit conditions are needed to startup and shutdown.



# 14.3 Emergency Gene rators and Pumps Visible Emissions

Visible emissions from emergency generators and pumps are the result particulate emissions associated
with incomplete combustion in the diesel engi nes which power the emergency equipment.



# 14.3.1 Emergency Generators and Pump s Visible Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

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# On emergency pumps and generators, PM/PM 10 

# emissions are controlled by good combustion practices.

A 5% opacity limit is recommended as BACT for visible emissions from emergency pumps and
generators. i.e. the average opacity of the emergenc y diesel exhaust cannot exceed 5% for more the one 6-
minute period during an hour. If Minnesota Steel iden tifies visible emissions from emergency generators
and pumps in excess of 5%, it will take corrective acti on as soon as it is practicable to do so. When this
equipment is operating under emer gency conditions, corrective action may be delay until the emergency
condition is over. Emergency equipm ent is exempt from opacity limits during startup until the time that
the diesel engine reaches proper operating temperatures.



# 14.4 Emergency Genera tors and Pumps SO 2 

# Emission Controls

SO 2 

# is created by combustion of low sulfur No.2 fuel oil containing elemental sulfur.



# 14.4.1 Identification of Potential SO 2 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous SO2 control technologi es are discussed in
Section 4.0. Potential control technolog ies for SO2 emissions are the following:



# • Low Sulfur Fuel



# • Operating Limitations



# • Add-on controls



# 14.4.2 Elimination of Te chnically Infeasible SO 2 

# Control Options

Table 14-4 summarizes the technical feasibility of SO 2 

# control technologies for emissions from

emergency generators. RACT/BACT Clearinghouse search in dicated no add-on controls for SO 2 

# BACT control for emergency genera tors. Low sulfur fuel oil and emergency generator classification
are both technically feasible.

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## Table 14-4 Technical Feasibility of SO 2 

## Control Technologies for Emergency Diesel Generators and Pumps

Summary of Control Technology Feasibility


## Technology Description Feasible? Yes or No

Low Sulfur Fuel Low Sulfur fuel oil combustion, less than or equal to 0.05 percent sulfur Yes

Emergency Generator Classification The proposed diesel generator is classified as an emergency generator that is anticipated to operate no more than 100 hours per year. This limitation will effectively minimize pollutant emissions. Yes



# 14.4.3 Ranking of Remaining SO 2 

# Control Technologies by Control Effectiveness

SO 2 

# control technologies applicable to emergenc y generators are ranked based on control

effectiveness in Table 14-5.

Table 14-5 Ranking of Remaining SO 2 

## Control Technologies for Emergency Generators and Pumps

SO 2 

## Control Technology Ranking



## Rank Technology Estimated Control Efficiency

1 Emergency Generator Classification Minimum 98%

2 Low Sulfur Fuel Varies by % Sulfur
content



# 14.4.4 Evaluation of Most Effective SO 2 

# Control Technologies and Document Results
The combination of Emergency Gene rator Classification (ope rating limitation) and low sulfur fuel is
the top control efficiency technology.

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## Table 14-6 Evaluation of Most Effective SO2 Control Technologies for Emergency Generators and Pumps

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Emergency Generator Classification Minimum 98% 20.8* NA NA 

## Site Specific

Low Sulfur Fuel Varies by % Sulfur
content Fuel specific NA NA 

## Site Specific

* for 8760 hrs



# 14.4.5 Emergency Generators and Pumps SO 2 

# BACT Selection

Emergency Generator Classification combined with Low Sulfur Fuel is ranked as the highest control
efficiency technology. Therefore, Emergency Gene rator Classification combined with Low Sulfur
Fuel (less than or equal to 0.05% sulfur) is BA CT for control of SO2 em issions. Minnesota Steel
Industries will also comply with NSPS Subpart IIII fuel specific ations for stationary emergency
diesels as applicable.

Since Minnesota Steel will use 0.05% S diesel fuel at all times when its diesel powered emergency
equipment is operating, no special permit conditions are required to control SO 2 

# emissions during
startup and shutdown.



# 14.5 Emergency Generators NO x 

# Emission Controls

NOx emissions are created by combusti on of low sulfur No. 2 fuel oil.



# 14.5.1 Identification of Potential NO x 

# Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the vari ous NOx control technologies are discussed in

Section 4.0. Potential control technol ogies for NOx emissions are the following:

• Good Combustion Practices

• Emergency Generator Classification

• Selective Catalytic Reduction (SCR)

• Non Selective Cataly tic Reduction (NSCR)

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# 14.5.2 Elimination of Technically Infeasible NOx Control Options

Table 14-7 summarizes the technical feas ibility of control technologies for NO
x 

# emissions from
emergency generators. NSCR contro l technology is technically infeas ible. Diesel engines are leanburn engines with an oxygen rich exhaust. Only ri ch burn engines can be controlled by NSCR due to
the need for an oxygen lean exhaust. The rema ining identified control technologies for NOx
emissions control are technically feasible.

Table 14-7 Technical Feasibility of NOx Control Technologies for Emergency Diesel Generators and Pumps

Summary of Control Technology Feasibility


## Technology Description Feasible? Yes or No

Good Combustion Practices Good combustion practices are preventative measures that minimize the release of particulate matter into the environment. Good combustion practices may include the proper design and maintenance of equipment, good housekeeping, good operating practices, and ignition retard. Yes

Emergency Generator Classification The proposed diesel generator is classified as an emergency generator that is anticipated to operate no more than 100 hours per year. This limitation will effectively minimize pollutant emissions. Yes

SCR Add-on control using precious metals impregnated onto a high geometric surface area carrier that is placed in the exhaust stream. The proposed generator is a rich burn engine with an oxygen deficient exhaust. Yes

NSCR Add-on controls for controlling rich-burn engines. Exhaust from the engine is passed through a metallic or ceramic honeycomb covered with precious metal catalyst. No



# 14.5.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness

NO
x 

# control technologies applicable to emergenc y generators are ranked based on control

effectiveness in Table 14-8

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## Table 14-8 Ranking of Remaining NOx Control Technologies for Emergency Generators and Pumps

NO x 

## Control Technology Ranking



## Rank Technology Estimated Control Efficiency

1 Emergency Generator Classification Minimum 98%

2 SCR 90%

3 Good Combustion Practices Varies by Design



# 14.5.4 Evaluation of Most Effective NOx Control Technol ogies and Document Results
An hours of operation limitation combined with Good Combustion Practices is the top control
technology for emergency ge nerators and pumps. Control costs ar e summarized below in Table 14-9.
NSCR controls are not cost effective for emergency generators and pumps. The detailed control cost
analyses are located in Attachment K.

Table 14-9 Evaluation of Most Effective NOx Control Technologies for Emergency Generators and Pumps

Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Emergency Generator Classification combined with Good Combustion Practices Minimum 98% 859* NA NA 

## Site Specific

SCR 90% 45 $11,685,869 $1,290,046 

## $28,645



# * based on 8760 hrs.



# 14.5.5 Emergency Generators NOx BACT Selection

Emergency Generator Classification combined with Good Combustion Practices is ranked as the highest
control efficiency technology. Therefore, Em ergency Generator Classification combined with Good

Combustion Practices is BACT for control of NO
x 

# emissions. Minnesota Steel Industries will also
comply with NSPS Subpart IIII emission limits for st ationary emergency diesels as applicable based on
the model year size and service of the engine.

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# Minnesota Steel will follow BACT operating practices during start up and shutdown; so, no special
permit conditions are needed to startup and shutdown.



# 14.6 Emergency Genera tors and Pumps VOC and CO Emission Controls

VOC and CO emissions are created by combustion of low sulfur No. 2 fuel oil.



# 14.6.1 Identification of Potential VOC and CO Control Technologies

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the variou s VOC and CO control te chnologies are discussed
in Section 4.0. Potential control technologi es for VOC and CO emissions are the following:

• Good Combustion Practices

• Emergency Generator Classification

• Oxidation Catalyst



# 14.6.2 Elimination of Technically Infe asible VOC and CO Control Options

Table 14-10 summarizes the techni cal feasibility of VOC and CO c ontrol technologies for emissions
from emergency generators. All id entified control technologies for VOC and CO emissions control
are technically feasible.

Table 14-10 Technical Feasibility of VOC and CO Control Technologies for Emergency Generators and Pumps

Summary of Control Technology Feasibility


## Technology Description Feasible? Yes or No

Good Combustion Practices Good combustion practices are preventative measures that minimize the release pollutants into the environment. Good combustion practices may include the proper design and maintenance of equipment, good housekeeping, and good operating practices. Yes

Emergency Generator Classification The proposed diesel generator is classified as an emergency generator that is anticipated to operate no more than 100 hours per year. This limitation will effectively minimize particulate matter emissions. Yes

Oxidation Catalyst Add-on control using precious metals impregnated onto a high geometric surface area carrier that is placed in the exhaust
stream. Yes

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# 14.6.3 Ranking of Remaining VOC and CO Control Technologies by Control Effectiveness

VOC and CO control technologies applicable to emerge ncy generators are ra nked based on control

effectiveness in Table 14-11.

Table 14-11 Ranking of Remaining VOC and CO Control Technologies for Emergency Generators and Pumps

VOC/CO Control Technology Ranking



## Rank Technology Estimated Control Efficiency

1 Emergency Generator Classification Minimum 98%

2 Oxidation Catalyst CO: 98%

VOC: 90%

3 Good Combustion Practices Varies by Design



# 14.6.4 Evaluation of Most Effective VOC and CO Control Technologies and Documentation of Results
An hours of operation limitation combined with Good Combustion Practices is the top CO/VOC
control technology for emergency generators and pumps. Control costs are summarized below in
Table 14-12. The detailed control cost analyses are located in Attachment K. Oxidation catalyst is
not economically feasible for diesel engines limited to emergency service.

Table 14-12 Evaluation of Most Effective VOC and CO Control Technologies for Emergency Generators and Pumps Control Technology Control Eff % Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Emergency Generator Classification combined with GCP Minimum 98% 225* NA NA 

## Site Specific

Oxidation Catalyst CO: 98%
VOC: 90% CO: 11 VOC:2 

## $5,031,393 $5,031,393 $522,480 $522,480 CO: $49,583 VOC: $352,797



# * based on 8760 hrs.



# 14.6.5 Emergency Generators VOC and CO BACT Selection

Emergency Generator Classification combined with Good Combustion Practices is ranked as the highest
control efficiency technology. Therefore, Em ergency Generator Classification combined with Good

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# Combustion Practices is BACT for control of VOC a nd CO emissions. Minnesota Steel Industries will
also comply with NSPS Subpart IIII emission limits fo r stationary emergency diesels as applicable based
on the model year size and service of the engine.

Minnesota Steel will follow BACT operating practices during start up and shutdown; so, no special
permit conditions are needed to startup and shutdown.

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# 15.0 Fugitive Dust

15.1 Fugitive Dust Process Description

Fugitive dust emissions are partic ulate emissions which occur from the mechanical disturbance of
granular material exposed to the air. These emissions are termed “fugitive” because they are not
discharged to the atmosphere in a confined flow stream. The dust-generation process is caused by
two basic physical phenomena:

1. Pulverization and abrasion of surface materials by application of mechanical force through
implements.

2. Entrainment of dust particles by the action of turbulent air currents associated with wind
blowing across open areas or piles and through materials as they are dropped for transfer.

Sources of fugitive emissions at Minnesota Steel include unpaved roads, storage piles, loading and
unloading operations, tailings basins, and materi al drops from mobile equipment. The individual
identification numbers of fugitive dust sources are listed in the Air Emissions Inventory,
Appendix 3B.



# 15.2 Fugitive Dust PM/PM 10 

# BACT Selection

Minnesota Steel will follow industry best practi ces for controlling fugitive dust emissions.

Minnesota Steel’s fugitive dust c ontrol plan is located in Appendi x O of the BACT report. The
control plan describes the measures Minnesota Steel will take to c ontrol dust emissions . Dust control
measures listed in the plan are consistent with dus t control techniques used by other mining facilities

in the area.

The proposed dust control measures se lected are based on control effe ctiveness and the practicality
of implementing such measures at each particular fugitive dust sour ce taking into account location,
availability water or other dust s uppressants, weather, nature of the mining equipment used and the
type of operation being performed.

The RBCL clearinghouse information for these source s is summarized in Attachment L, Tables 31,
32 and 33 for fugitive dust sources and in Tables L-35 and 36 for slag handling.

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# Minnesota Steel will follow BACT operating practices fo r controlling fugitive dust emissions during start
up and shutdown. In cases where wet suppression or si milar measures are used, water will be applied
prior to commencing operations. No excess fugitive emissions will occur as a result of equipment
startup/shutdown. No special permit conditions are n eeded for startup and shutdown of fugitive emission

sources.


# 15.3 Fugitive Dust Visible Emissions

Visible emission associated with fugitive dust emissi ons are due to particulate emissions which occur
from the mechanical disturbance of granular material exposed to the air or vehicle movement.



# 15.3.1 Fugitive Dust Visible Emissions BACT Selection

Because visible emissions are directly related to particulate emissions, BACT for control of visible

emission is the same as the PM/PM 10 

# BACT.

For fugitive dust sources, PM/PM 10 

# emissions are controlled by the fugitive dust management plan.

The proposed opacity limits for f ugitive dust sources are as follows:

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Mining & Crushing Opacity Best Practices & Dust Control Plan 5% Opacity NA

Concentrator Opacity Best Practices & Dust Control Plan 5% Opacity NA

Pelletizer Opacity Best Practices & Dust Control Plan 5% Opacity NA

DRI Opacity Best Practices & Dust Control Plan 5% Opacity NA

Melt Shop No fugitives

Slag Processing Opacity Best Practices & Dust Control Plan 5% Opacity NA

Roads Opacity Best Practices & Dust Control Plan 10% Opacity NA



# If a 5% opacity limit is recommended as BACT for visible emissions from a fugitive dust source, the
opacity of a fugitive dust source with a 5% opacity limit cannot exceed 5% for more the one 6-minute
period during an hour. If Minnesota Steel identifies visible emissions from fugitive dust sources in excess
of the proposed opacity limits, it will take correc tive action under the fugitive dust management plan as

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# soon as it is practicable to do so. The proposed opacity limits are consistent with recent RBLC
determinations for fugitive dust sources in the mini ng and steel making industries as shown in the table

below.

MH & Fug RBLC Opacity BACT Limits Summary

BACT-PSD PM gr/dscf Emission Limits Other (non-BACT)-case-by-case PM gr/dscf Emission Limits MIN 3 % Opacity MIN 10 % Opacity MAX 20 % Opacity MAX 20 % Opacity MEDIAN 10 % Opacity MEDIAN 10 % Opacity
COUNT 25 CASES COUNT 4 CASES



# See Attachment L, Table L-49 for a detailed listing of recent RBLC opacity determinations for fugitive
dust and material handling equipment



# 15.4 Fugitive Fluoride Du st (F-) BACT Selection

Fluoride salts are present in trace quantities in the ir on ore used at Minnesota Steel. It is emitted as a
particulate along with dust emitted from fugitive sour ces. Minnesota Steel will follow industry best
practices for controlling fugitive dust emissions to contro l F- emissions.

Minnesota Steel has prepared a fugitive dust control plan (Attachment O) which describes the

measures Minnesota Steel will take to control thes e emissions. Dust control measures listed in the
plan are consistent with dust control techniques us ed by other mining facilities in the area. Dust
control measures selected are based on control effectiveness and the practicality of implementing
such measures at each particular f ugitive dust source taking into ac count location, availability water
or other dust suppressants, weathe r, nature of the mining equipment used and the type of operation
being performed.

Minnesota Steel will follow BACT operating practices fo r controlling fugitive F- (dust) emissions during
start up and shutdown. In cases where wet suppression or similar measures are used, water will be
applied prior to commencing operations. No excess fugitive dust emissions will occur as a result of
implementing dust control practice for equipment star tup/shutdown. No special permit conditions are
needed for startup and shutdown of fugitive emission sources.

## Minnesota Steel Page - 346 Fugitive Dust

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# The RBCL clearinghouse information for these source s is summarized in Attachment L, Table 13 for
material handling and fugitive dust control, a nd Attachment L, Table 14 for slag handling.



# 15.5 Fugitive Lead (Pb) Dust BACT Selection

Lead salts are present in trace qua ntities in the iron ore used at Minnesota Steel; therefore, it is
emitted as a particulate along with dust emitted from fugitive sources. Minnesota Steel will follow
industry best practices for cont rolling fugitive dust emissions to control Pb emissions.

Minnesota Steel has prepared a fugitive dust control plan (Attachment O) which describes the

measures Minnesota Steel will take to control thes e emissions. Dust control measures listed in the
plan are consistent with dust control techniques us ed by other mining facilities in the area. Dust
control measures selected are based on control effectiveness and the practicality of implementing
such measures at each particular f ugitive dust source taking into ac count location, availability water
or other dust suppressants, weathe r, nature of the mining equipment used and the type of operation
being performed. The fugitive dust control measur es listed above are consistent with recent BACT
determination for the steel industry. The RBCL clearinghouse information for these sources is
summarized in Attachment L, Table 34 for material handling and fugitive dust control. No RBLC
listing was found for Pb emissions from for slag handling.

Minnesota Steel will follow BACT operating practices fo r controlling fugitive Pb (dust) emissions during
start up and shutdown. In cases where wet suppression or similar measures are used, water will be
applied prior to commencing operations. No excess f ugitive emissions will occur as a result of equipment
startup/shutdown. No special permit conditions are n eeded for startup and shutdown of fugitive emission

sources.

## Minnesota Steel Page - 347 Insignificant Activities

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# 16.0 Insignificant Activities

16.1 Insignificant Activi ties Process Description

Insignificant activities are small sources with low emissions rates that have negligible impacts on the
environment (e.g. water he aters). The Minnesota Pollution C ontrol Agency rule MN 7007.1300 lists
sources which are classified as insignificant activates by source type and/or emission rate.
Insignificant activities for Minnesota Steel are listed in this permit application on MPCA form IA-01.
The Minnesota Steel insignificant activities include the following source categories:

 

# Fugitive dust emission associat ed with mining activities

 

# Material handling and material storage

 

# Cooling Towers

 

# Diesel powered emergenc y generators and pumps

 

# Diesel and gasoline storage tanks

 

# Space heaters



# 16.2 Insignificant Actives Addr essed within th e BACT Report

The majority of insignificant activities listed in form IA-01 are in the BACT analysis and a BACT
limit has been specified for them. The BACT analysis for these sources is located in the following
BACT report sections:

Insignificant Activity BACT Report Section
Fugitive dust emissions from mining activities Section 15 and Attachment O Fugitive Dust Control Plan
Material handling and material storage Sections 11 and 12
Cooling Towers Section 13
Diesel powered emergency generators and
pumps Section 14

## Minnesota Steel Page - 348 Insignificant Activities

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# 16.3 Insignificant Activities Requiring Review

Petroleum Storage Tanks
Minnesota Steel will have two 900,000 gallon dies el storage tanks and one 10,000 gasoline storage
tank. They are sources of VOC em issions. These tanks will be used to supply the fuels needed to
operate mobile e quipment within the facility.

No VOC emission controls are recommended as BACT for the diesel storage tanks. Diesel fuel has a
very low vapor pressure; so, diesel storage tank s have low VOC emission ra tes. No VOC emission
controls are required for diesel storage tanks under New Source Performance Standards (40 CFR
Part 60) or Maximum Achievable Control Te chnology (40 CFR Part 63) standards.

No VOC emission controls are recommended as BA CT for the gasoline storage tank. At 10,000
gallons, the gasoline tank is relatively small. So , installation of VOC cont rols would not be cost
effective. The proposed gasoline storage tank is on e half of the de minimus size (20,0000 gallons)
for tanks requiring emission contro ls under New Source Performance Standards (40 CFR Part 60) or
Maximum Achievable Control Technology (40 CFR Part 63) standards. The fact that the gasoline
tank is too small to be regulated under NSPS or MA CT suggests that emission controls would not be

cost effective.

Space Heaters
Minnesota Steel will have a number of natural gas fired space heaters for heating buildings
throughout the facility. The spac e heaters are sources of PM, PM10, SO2, NOx, CO and VOCs.
Like the Degassing Boiler reviewed in Sections 9.12 through 9.19, these space heater s will have low
emission rates due the use of clean fuels (natural gas). Like the boiler, pollutant concentrations in
the space heater exhaust will be too low for add on cont rols to be cost effective. In Section 9.17, low

NO
x 

# burners are recommended as BACT fo r the Degassing Boiler. If low NO
x 

# burners are
commercially available for space heaters, they should be considered as BACT for NO
x 

# control.

# Attachment A

Indurator Hood Exhaust BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment A - Emission Control Cost AnalysisTable A-1: Cost Summary - Indurator Hood ExhaustPM/PM10 Control Cost Summary *Control TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber0.012gr/dscf177.5 1058.8 $3,299,221 $1,648,867 $1,061 NA None High Waste-waterDry ElectroStatic Precipitator(ESP)0.012gr/dscf177.5 1058.8 $8,890,668 $1,894,712 $1,789 NA None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)0.012gr/dscf177.5 1058.8 $21,923,877 $4,238,597 $4,003 NA None Low Waste-waterUncontrolled0% 1236.3* Based on highest emission rate if PM not equal to PM10SO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Absorber90.0% 13.4 120.3 $15,113,965 $2,703,203 $22,475NA WESP is inferiorcontrolNone Low Waste-waterBaghouse w/Dry Scrubber85.0% 20.0 113.6 $32,876,241 $5,637,085 $49,625 $209,293 None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)80.0% 26.7 106.9 $21,923,877 $4,238,597 $39,646 NA None Low Waste-waterUncontrolled0% 133.6NOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?LoTOx60% 244.2 366.3 $19,139,941 $6,661,302 $18,183NANone MediumWaste-waterUncontrolled0%610.6P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach A - Hood Exhaust Mar 2007 RevisionCost Summary3/8/2007Page 1 of 21Minnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment A - Emission Control Cost AnalysisTable A-1: Cost Summary - Indurator Hood ExhaustSulfuric Acid Mist Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Absorber90% 0.1 1.0 $15,113,965 $2,703,203 $2,727,229NA WESP is inferiorcontrolNone Low Waste-waterBaghouse w/Dry Scrubber90% 0.1 1.0 $32,876,241 $5,637,085 $5,687,189 NANone Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)90% 0.1 1.0 $21,923,877 $4,238,597 $4,276,271 NA None Low Waste-waterWet Scrubber (PM)50% 0.6 0.6 $3,299,221 $1,648,867 $2,040,224NANone High Waste-waterUncontrolled0% 1.1Fluoride Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Absorber93% 4.8E-02 6.4E-01 $15,113,965 $2,703,203 $4,217,690NA WESP is inferiorcontrolNone Low Waste-waterBaghouse w/Dry Scrubber93% 4.8E-02 6.4E-01 $32,876,241 $5,637,085 $8,795,300 NANone Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)93% 4.8E-02 6.4E-01 $21,923,877 $4,238,597 $6,613,300 NA None Low Waste-wateruncontrolled0% 6.9E-01Lead Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber93% 4.9E-02 6.6E-01 $3,299,221 $1,648,867 $2,509,625 NANone High Waste-waterDry ElectroStatic Precipitator(ESP)93% 4.9E-02 6.6E-01 $8,890,668 $1,894,712 $2,883,810 NA None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)93% 4.9E-02 6.6E-01 $21,923,877 $4,238,597 $6,451,274 NA None Low Waste-waterUncontrolled0% 7.1E-01The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual control efficiencies.Wet Scrubber/Absorber/LoTOx - Combined Pollutant Control Cost SummaryPollutantControlEff %AnnualizedOperatingCost $/yrPollutionControl Cost$/tonIncrementalOperating Cost$/yrIncrementalControl Cost $/tonParticulate Matter (PM)0.012gr/dscf$1,648,867 $1,061 Base Case Base CaseSulfur Dioxide (SO2)90% $2,703,203 $22,475 $1,054,336 $8,766Nitrogen Oxides (NOx)60% $6,661,302 $18,183 $3,958,099 $10,804P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach A - Hood Exhaust Mar 2007 RevisionCost Summary3/8/2007Page 2 of 21

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Indurator Hood Exhaust Study Year 2005 Emission Unit Number EU 038 Stack/Vent Number SV 018 Reference Item Unit Cos t Units Cos t Y ear Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.051 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.78 $/mgal 0.76 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation

Cooling Water 0.27 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.31 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.64 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.15 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 27.32 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3% inflation

Hazardous Waste Disposal 273.18 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3% inflation

Waste Transport 0.55 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycle 1.16 $/ton 1.00 2000 Corus Study for MN Iron and Steel Project Study use $1/ton to cover cost of materials movement

Chemicals & Supplie s Lime 25.31 $/ton 24.57 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation Caustic 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.44 Mscf 1.40 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation EPA Urea 179.1 $/ton A mmonia 0.101 $/lb Reagent #8 $/ton

Catalyst & Replacement Parts SCR Catalyst 500 $/ft 3 Cormetech, Inc. CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 Catalyst #4 Catalyst #5

Filter Bags 36.84 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Other Sales Tax 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Informatio n A nnual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 93% 2004 Kaar Consulting MSI Cost Model Equipment Life 20 yrs Engineering Estimate Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 480,406 scfm @ 32o F

Temperature 250 Deg F 250° F pellet plant exhaust temperature per MPCA comment, Hongming Jiang 120° F scrubber exhaust temperature per MN Steel Emission Inventory. Used for wet scrubber and wet ESP calcuations Moisture Content 9.4%

Actual Flow Rate 693,543 acfm ac f m b as i s 250 ° F process equipment exhaus t temperature Standardized Flow Rate 515,557 scfm @ 68o F Dry Std Flow Rate 467,095 dscfm @ 68o F

Max Emis Pollutan t Lb/H r Uncontrolled Conc PM10 334.6 0.08 gr/dscf Total Particulates 334.6 0.08 gr/dscf Nitrous Oxides (NOx) 165.2 49 ppm Sulfur Dioxide (SO 2 ) 36.2 8 ppm Sulfuric Acid Mist 0.30 0.042 ppm Fluorides 0.19 4.7E-05 gr/dscf 67.4 ppb Volatile Organic Compounds (VOC) 2.09 1.8 ppm Carbon Monoxide (CO) 4.35 2.1 ppm Lead (Pb) 0.191 4.8E-05 gr/dscf 13 ppb

Enter this data for each emission uni t Enter data for this study (applies to all units )

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 200 7)\Attachments\Attach A - Hood Exhaust Mar 2007 Revision Utility Chem$ Data 3/8/2007 Page 3 of 21

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-3: PM Control - Wet Wall ESP

Operating Unit: Indurator Hood Exhaust

Emission Unit Number EU 038 Stack/Vent Number SV 018 Chemical Engineering Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 480,406 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 250 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 693,543 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 515,557 scfm @ 68o F Dry Std Flow Rate 467,095 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 7,914,186 Purchased Equipment Total (B) 22% of control device cost (A) 9,615,736

Installation - Standard Costs 71% of purchased equip cost (B) 6,827,172 Installation - Site Specific Costs NA Installation Total 6,827,172 Total Direct Capital Cost, DC 16,442,908 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,480,969 Total Capital Investment (TCI) = DC + IC 21,923,877

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,116,623 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,121,975 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,238,597

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 0.012 gr/dscf 177.5 1,058.8 4,003 Total Particulates 334.6 1,236.3 0.006 gr/dscf 88.8 1,147.6 3,694 Nitrous Oxides (NOx) 165.2 610.6 610.6 - NA Sulfur Dioxide (SO 2 ) 36.2 133.6 80% 26.7 106.9 39,646
Sulfuric Acid Mist 0.3 1.1 90% 0.1 1.0 4,276,271 Fluorides 1.9E-01 6.9E-01 93% 4.8E-02 6.4E-01 6,613,300 Volatile Organic Compounds (VOC) 2.1 7.7 7.7 - NA Carbon Monoxide (CO) 4.3 16.1 16.1 - NA Lead (Pb) 0.2 0.7 93% 0.05 0.66 6,451,274

Notes & Assumptions
1 Sept 8, 2005 Cost Estimate from Durr Environmental
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
3 Piping cost estimated to be 5% of purchase price; same as PM wet scrubber. Change to account for additional piping needed for w ater sprays in WESP.
4 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation 5 ESP maintenance materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
6 ESP blower electrical use Eq 3.46 EPA Cont Cost Manual Section 6 Chapter 3 7 ESP grid electrical use Eq 3.48 EPA Cont Cost Manual Section 6 Chapter 3
8 WESP pump electrical use Eq 3.48 EPA Cont Cost Manual Section 6 Chapter 3
9 Estimated ESP Grid Area at 219 ft 2 per 1000 acfm EPA example problem Manual Section 6 Chapter 3.4.5.1
10 Used 0.6 power law factor to adjust price to calculated acfm value from bid basis of 291,000 acfm
11 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21
12 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies. 13 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-3: PM Control - Wet Wall ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 7,914,186

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 791,419 MN Sales Taxes 6.5% of control device cost (A) 514,422 Freight 5% of control device cost (A) 395,709 Purchased Equipment Total (B) 22% 9,615,736

Installation

Foundations & supports 4% of purchased equip cost (B) 384,629 Handling & erection 50% of purchased equip cost (B) 4,807,868 Electrical 8% of purchased equip cost (B) 769,259 Piping (3) 5% of purchased equip cost (B) 480,787 Insulation 2% of purchased equip cost (B) 192,315 Painting 2% of purchased equip cost (B) 192,315 Installation Subtotal Standard Expenses 71% 6,827,172

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 6,827,172 Total Direct Capital Cost, DC 16,442,908

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,923,147 Construction & field expenses 20% of purchased equip cost (B) 1,923,147 Contractor fees 10% of purchased equip cost (B) 961,574 Start-up 1% of purchased equip cost (B) 96,157 Performance test 1% of purchased equip cost (B) 96,157 Model Studies 2% of purchased equip cost (B) 192,315 Contingencies 3% of purchased equip cost (B) 288,472 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,480,969

Total Capital Investment (TCI) = DC + IC 21,923,877

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 21,923,877

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Supervisor 48% % of Operator Costs. 15,256
Maintenance

Maintenance Labor 151,886 ft2 grid area, 1.0 $/ft2 of grid area 149,403 Maintenance Materials 1 1% of purchased equipment cost 96,157 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 1,469 kW-hr, 7946 hr/yr, 93% utilization 549,630
NA NA - Water 0.78 $/mgal, 225 gpm, 7946 hr/yr, 93% utilization 77,949
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 142 gpm, 7946 hr/yr, 93% utilizatio n 102,896
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Caustic 280.00 $/ton, 90 lb/hr, 7946 hr/yr, 93% utilization 93,548
NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 1,116,623

Indirect Operating Costs Overhead 60% of total labor and material costs 175,561 Administration (2% total capital costs) 2% of total capital costs (TCI) 438,478 Property tax (1% total capital costs) 1% of total capital costs (TCI) 219,239 Insurance (1% total capital costs) 1% of total capital costs (TCI) 219,239 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,069,459 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,121,975

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,238,597

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-3: PM Control - Wet Wall ESP

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Us e

Flow acfm D P in H2O Efficiency Hp kW Blower Baghouse & ES P 693,543 9 1129.8 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq. flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 2832 gpm 1.000 40 0.5 42.6 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 142 gpm 1.000 40 0.5 2.1 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 151,886 ft 2 1.94E-03 kW/ft 2 294.7 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 1469.2

Reagent Use & Other Operating Costs WESP Pump 566,332 acfm 5 gpm/kacfm 2,832 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disc h 5% of circulating water rate = 142 gpm

Caustic Use 36.17 lb/hr SO2 2.50 lb NaOH/lb SO2 90 lb/hr Caustic

Scrubber Outlet Flow 566,332 acfm Scrubber Outlet Temp 120 °F Evap H2O Loss 83 gpm Water Makeup Rate 225 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 15,256 % of Operator Costs. Maintenance Maint Labor 151,886 ft2 grid area 0.984 $/ft 2 of grid area 149,403 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 96,157 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1469.2 kW-hr 10,856,989 549,630 $/kwh, 1,469 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 224.6 gpm 99,577 77,949 $/mgal, 225 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 141.6 gpm 62,776 102,896 $/mgal, 142 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 90 lb/hr 334 93,548 $/ton, 90 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-4: PM Control - Dry ESP

Operating Unit: Indurator Hood Exhaust

Emission Unit Number EU 038 Stack/Vent Number SV 018 Chemical Engineering Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 480,406 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 250 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 693,543 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 515,557 scfm @ 68o F Dry Std Flow Rate 467,095 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 3,266,706 Purchased Equipment Total (B) 22% of control device cost (A) 3,969,048

Installation - Standard Costs 67% of purchased equip cost (B) 2,659,262 Installation - Site Specific Costs NA Installation Total 2,659,262 Total Direct Capital Cost, DC 6,628,311 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,262,358 Total Capital Investment (TCI) = DC + IC 8,890,668

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 558,189 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,336,523 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,894,712

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 0.012 gr/dscf 177.5 1,058.8 1,789 Total Particulates 334.6 1,236.3 0.006 gr/dscf 88.8 1,147.6 1,651 Nitrous Oxides (NOx) 165.2 610.6 610.6 - NA Sulfur Dioxide (SO 2 ) 36.2 133.6 133.6 - NA
Sulfuric Acid Mist 0.3 1.1 1.1 - NA Fluorides 1.9E-01 6.9E-01 6.9E-01 0.0E+00 NA Volatile Organic Compounds (VOC) 2.1 7.7 7.7 - NA Carbon Monoxide (CO) 4.3 16.1 16.1 - NA Lead (Pb) 0.2 0.7 93% 0.05 0.66 2,883,810

Notes & Assumptions
1 Cost Estimate from 2001 Bids for Taconite Plant ESP and EPA Air Compliance Advisor Ver 7.7. Used average cost adjusted for infl ation.
2 Cost estimation basis 291,000 acfm. Used 0.6 power law factor to adjust price to calculated acfm
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
4 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation 5 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
6 Estimated ESP Grid Area at 219 ft 2 per 1000 acfm EPA example problem Manual Section 6 Chapter 3.4.5.1
7 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21
8 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-4: PM Control - Dry ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 3,266,706

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 326,671 MN Sales Taxes 6.5% of control device cost (A) 212,336 Freight 5% of control device cost (A) 163,335 Purchased Equipment Total (B) 22% 3,969,048

Installation

Foundations & supports 4% of purchased equip cost (B) 158,762 Handling & erection 50% of purchased equip cost (B) 1,984,524 Electrical 8% of purchased equip cost (B) 317,524 Piping 1% of purchased equip cost (B) 39,690 Insulation 2% of purchased equip cost (B) 79,381 Painting 2% of purchased equip cost (B) 79,381 Installation Subtotal Standard Expenses 67% 2,659,262

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 2,659,262 Total Direct Capital Cost, DC 6,628,311

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 793,810 Construction & field expenses 20% of purchased equip cost (B) 793,810 Contractor fees 10% of purchased equip cost (B) 396,905 Start-up 1% of purchased equip cost (B) 39,690 Performance test 1% of purchased equip cost (B) 39,690 Model Studies 2% of purchased equip cost (B) 79,381 Contingencies 3% of purchased equip cost (B) 119,071 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,262,358

Total Capital Investment (TCI) = DC + IC 8,890,668

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 8,890,668

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Supervisor 48% % of Operator Costs. 15,256
Maintenance

Maintenance Labor 151,886 ft2 grid area, 1.0 $/ft2 of grid area 149,403 Maintenance Materials 1 1% of purchased equipment cost 39,690 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 857 kW-hr, 7946 hr/yr, 93% utilization 320,622
NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization 1,433
NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 558,189

Indirect Operating Costs Overhead 60% of total labor and material costs 141,680 Administration (2% total capital costs) 2% of total capital costs (TCI) 177,813 Property tax (1% total capital costs) 1% of total capital costs (TCI) 88,907 Insurance (1% total capital costs) 1% of total capital costs (TCI) 88,907 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 839,216 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,336,523

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,894,712

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-4: PM Control - Dry ESP

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Us e

Flow acfm D P in H2O Efficiency Hp kW Blower Baghouse & ES P 693,543 4.48 562.4 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 151,886 ft 2 1.94E-03 kW/ft 2 294.7 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 857.0

Reagent Use & Other Operating Costs WESP Pump acfm 5 gpm/kacfm 0 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disc h 20% of circulating water rate = 0 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 15,256 % of Operator Costs. Maintenance Maint Labor 151,886 ft2 grid area 0.984 $/ft 2 of grid area 149,403 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 39,690 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 857.0 kW-hr 6,333,332 320,622 $/kwh, 857 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 Mi 0 0 $/ton-mi, 0 Mi, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.2 ton/hr 1,236 1,433 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-5: PM Control - Wet Scrubber

Stack/Vent Number(s): Operating Unit: Indurator Hood Exhaust

Emission Unit Number EU 038 Stack/Vent Number SV 018 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 480,406 scfm @ 32o F Expected Utilization Rate 93% Temperature 250 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% Annual Interest Rate 7.0% Actual Flow Rate 693,543 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 515,557 scfm @ 68o F Dry Std Flow Rate 467,095 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,421,680 Purchased Equipment Total (B) 22% of control device cost (A) 1,727,341

Installation - Standard Costs 56% of purchased equip cost (B) 967,311 Installation - Site Specific Costs NA Installation Total 967,311 Total Direct Capital Cost, DC 2,694,651 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 604,569 Total Capital Investment (TCI) = DC + IC 3,299,221

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,123,472 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 525,395 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,648,867

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 0.012 gr/dscf 177.5 1,058.8 1,061 Total Particulates 334.6 1,236.3 0.006 gr/dscf 88.8 1,147.6 979 Nitrous Oxides (NOx) 165.2 610.6 610.6 - NA Sulfur Dioxide (SO 2 ) 36.2 133.6 133.6 - NA
Sulfuric Acid Mist 0.3 1.1 50% 0.6 0.6 2,040,224
Fluorides 1.9E-01 6.9E-01 6.9E-01 0.0E+00 NA Volatile Organic Compounds (VOC) 2.1 7.7 7.7 - NA Carbon Monoxide (CO) 4.3 16.1 16.1 - NA Lead (Pb) 0.2 0.7 93% 0.05 0.66 2,509,625

Notes & Assumptions
1 Scrubber Cost per Barr Engineering 2004 Scrubber Project. Adjusted prices per Chemical Engineering Magazine CPI Index 2004 = 44 4, 2005 =465 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 2
3 Used 0.6 power law factor to adjust price to calculated acfm from bid basis of 500,000 acfm
4 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies. 5 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-5: PM Control - Wet Scrubbe r

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 1,421,680

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 142,168 MN Sales Taxes 6.5% of control device cost (A) 92,409 Freight 5% of control device cost (A) 71,084 Purchased Equipment Total (B) 22% 1,727,341

Installation

Foundations & supports 6% of purchased equip cost (B) 103,640 Handling & erection 40% of purchased equip cost (B) 690,936 Electrical 1% of purchased equip cost (B) 17,273 Piping 5% of purchased equip cost (B) 86,367 Insulation 3% of purchased equip cost (B) 51,820 Painting 1% of purchased equip cost (B) 17,273 Installation Subtotal Standard Expenses 56% 967,311

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 967,311 Total Direct Capital Cost, DC 2,694,651

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 172,734 Construction & field expenses 10% of purchased equip cost (B) 172,734 Contractor fees 10% of purchased equip cost (B) 172,734 Start-up 1% of purchased equip cost (B) 17,273 Performance test 1% of purchased equip cost (B) 17,273 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 51,820 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 604,569

Total Capital Investment (TCI) = DC + IC 3,299,221

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 3,299,221

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535 Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100.00 % of Maintenance Labor 31,784 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 2,154 kW-hr, 7946 hr/yr, 93% utilization 805,956
NA NA - Water 0.78 $/mgal, 225 gpm, 7946 hr/yr, 93% utilization 77,949
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 142 gpm, 7946 hr/yr, 93% utilizatio n 102,896
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 1,123,472

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 65,984 Property tax (1% total capital costs) 1% of total capital costs (TCI) 32,992 Insurance (1% total capital costs) 1% of total capital costs (TCI) 32,992 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 311,423 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 525,395

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,648,867

See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-5: PM Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3
Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Us e

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 693,543 15 0.6 2,727.9 2,034.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.40
L/G ratio* Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 10 1.125 40 0.5 157.9 117.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41
H2O WW Disch Pump 142 gpm 1.125 40 0.5 3.2 2.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41
Other Other
Other Total 2154.4 * L/G = Gal/1,000 acf

Reagent Use & Other Operating Costs
Caustic Use 36.17 lb/hr SO2 2.50 lb NaOH/lb SO2 90.42 lb/hr Caustic Lime Use 36.17 lb/hr SO2 1.53 lb Lime/lb SO2 55.34 lb/hr Lime Circulating Water Rate 5,663 gpm Water Makeup Rate/WW Disch = 2.5% of circulating water rate = 142 gpm

Scrubber Outlet Flow 566,332 acfm Scrubber Outlet Temp 120 °F Evap H2O Loss 83 gpm Water Makeup Rate 225 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2154.4 kW-hr 15,920,283 805,956 $/kwh, 2,154 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 224.6 gpm 99,577 77,949 $/mgal, 225 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 141.6 gpm 62,776 102,896 $/mgal, 142 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Urea 405 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-7: SO2 Control Dry Scrubbing with Baghouse

Operating Unit: Indurator Hood Exhaust

Emission Unit Number EU 038 Stack/Vent Number SV 018 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 480,406 scfm @ 32o F Expected Utilization Rate 93% Temperature 250 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% Annual Interest Rate 7.0% Actual Flow Rate 693,543 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 515,557 scfm @ 68o F Dry Std Flow Rate 467,095 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 12,355,541 Purchased Equipment Total (B) 22% of control device cost (A) 15,011,982

Installation - Standard Costs 74% of purchased equip cost (B) 11,108,867 Installation - Site Specific Costs NA Installation Total 11,108,867 Total Direct Capital Cost, DC 26,120,849 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 6,755,392 Total Capital Investment (TCI) = DC + IC 32,876,241

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,170,138 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,466,948 Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,637,085

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 0.012 gr/dscf 177.5 1,058.8 5,324 Total Particulates 334.6 1,236.3 0.006 gr/dscf 88.8 1,147.6 4,912 Nitrous Oxides (NOx) 165.2 610.6 610.6 - NA Sulfur Dioxide (SO 2 ) 36.2 133.6 85% 20.0 113.6 49,625

Sulfuric Acid Mist 0.3 1.1 90% 0.1 1.0 5,687,189 Fluorides 1.9E-01 6.9E-01 93% 4.8E-02 6.4E-01 8,795,300 Volatile Organic Compounds (VOC) 2.1 7.7 7.7 - NA Carbon Monoxide (CO) 4.3 16.1 16.1 - NA Lead (Pb) 0.2 0.7 0.71 - NA

Notes & Assumptions
1 Sept 2, 2005 Cost Estimate Environmental Elements
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1
3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapt er 1.5.1.8
4 Bag replacement at 10 min/bag EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min pe r bag. 5 Used 0.6 power law factor to adjust price to calculated dscfm from bid basis of 217,000 dscfm 6 $250,000 bag replacement cost from vendor adjusted for flow rate as noted above

7 Lime consumption per vendor 1.56 lb lime / lb SO 2 removed

8 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-7: SO2 Control Dry Scrubbing with Baghouse

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 12,355,541

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 1,235,554 MN Sales Taxes 6.5% of control device cost (A) 803,110 Freight 5% of control device cost (A) 617,777 Purchased Equipment Total (B) 22% 15,011,982

Installation

Foundations & supports 4% of purchased equip cost (B) 600,479 Handling & erection 50% of purchased equip cost (B) 7,505,991 Electrical 8% of purchased equip cost (B) 1,200,959 Piping 1% of purchased equip cost (B) 150,120 Insulation 7% of purchased equip cost (B) 1,050,839 Painting 4% of purchased equip cost (B) 600,479 Installation Subtotal Standard Expenses 74% 11,108,867

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 11,108,867 Total Direct Capital Cost, DC 26,120,849

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 1,501,198 Construction & field expenses 20% of purchased equip cost (B) 3,002,396 Contractor fees 10% of purchased equip cost (B) 1,501,198 Start-up 1% of purchased equip cost (B) 150,120 Performance test 1% of purchased equip cost (B) 150,120 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 450,359 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 6,755,392

Total Capital Investment (TCI) = DC + IC 32,876,241

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 32,522,515

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535
Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100% of maintenance labor costs 31,784 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 2,009 kW-hr, 7946 hr/yr, 93% utilization 751,388
NA NA - NA NA - NA NA - Comp Air 0.31 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 93% utilization 189,098

NA NA - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization 1,433 Lime 25.31 $/ton, 56 lb/hr, 7946 hr/yr, 93% utilization 5,277
NA NA - NA NA - NA NA - Filter Bags 33.71 $/bag, 795 bags, 7946 hr/yr, 93% utilization 86,270 Total Annual Direct Operating Costs 1,170,138

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 657,525 Property tax (1% total capital costs) 1% of total capital costs (TCI) 328,762 Insurance (1% total capital costs) 1% of total capital costs (TCI) 328,762 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,069,895 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,466,948

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,637,085

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-7: SO2 Control Dry Scrubbing with Baghouse

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages Equipment Life 5 years CRF 0.2439 Rep part cost per unit 33.711 $/bag Amount Required 795 Total Rep Parts Cost 346,603 Cost adjusted for freight & sales tax Installation Labo r 7,123 10 min per bag, Labor + Overhead (68% = $29.65/hr ) EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1. 4 Total Installed Cos t 353,726 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag

. Annualized Cost 86,270

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Baghouse 693,543 16 2008.5 Baghouse Shaker 0.0 Gross fabric area ft 2 0 EPA Cont Cost Manual 6th ed Section 6 Chapter 1 Eq 1.14 Other Other Other
Other
Other Total 2008.5

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Gross BH Filter Area 10,661 ft 2

Cages 10 ft long 5 in dia 13.42 area/cage ft 2 795 Cages 11.036 $/cage Bags 1.69 $/ft2 of fabric 22.68 $/bag
Total 33.711

Lime Use Rate 1.56 lb lime/lb SO2 removed 56 lb/hr Lime

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2008.5 kW-hr 14,842,385 751,388 $/kwh, 2,009 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 2 scfm/kacfm 615,016 189,098 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.2 ton/hr 1,236 1,433 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.31 $/ton 56 lb/hr 208 5,277 $/ton, 56 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 33.71 $/bag 795 bags NA 86,270 $/bag, 795 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-8: SO2 Control - Wet Scrubber

Operating Unit: Indurator Hood Exhaust

Emission Unit Number EU 038 Stack/Vent Number SV 018 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 480,406 scfm @ 32o F Expected Utilization Rate 93% Temperature 250 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% Annual Interest Rate 7.0% Actual Flow Rate 693,543 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 515,557 scfm @ 68o F Dry Std Flow Rate 467,095 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 5,654,308 Purchased Equipment Total (B) 22% of control device cost (A) 6,869,98 4

Installation - Standard Costs 85% of purchased equip cost (B) 5,839,487 Installation - Site Specific Costs NA Installation Total 5,839,487 Total Direct Capital Cost, DC 12,709,471 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 2,404,494 Total Capital Investment (TCI) = DC + IC 15,113,965

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 641,957 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,061,246 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,703,203

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 1236.3 - NA Total Particulates 334.6 1,236.3 1236.3 - NA Nitrous Oxides (NOx) 165.2 610.6 610.6 - NA Sulfur Dioxide (SO 2 ) 36.2 133.6 90% 13.4 120.3 22,475
Sulfuric Acid Mist 0.30 1.1 90% 0.11 1.0 2,727,229 Fluorides 1.9E-01 6.9E-01 93% 4.8E-02 6.4E-01 4,217,690 Volatile Organic Compounds (VOC) 2.1 7.7 7.7 - NA Carbon Monoxide (CO) 4.3 16.1 16.1 - NA Lead (Pb) 0.19 0.7 0.71 - NA

Notes & Assumptions
1 Sept 2, 2005 Cost Estimate Environmental Elements. Adjust downward (to $3.5M) for removal of vacuum filter and building
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Used 0.6 power law factor to adjust price to calculated dscfm from bid basis of 210,000 dscfm 6 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies. 7 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-8: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 5,654,308

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 565,431 MN Sales Taxes 6.5% of control device cost (A) 367,530 Freight 5% of control device cost (A) 282,715 Purchased Equipment Total (B) 22% 6,869,98 4

Installation

Foundations & supports 12% of purchased equip cost (B) 824,398 Handling & erection 40% of purchased equip cost (B) 2,747,994 Electrical 1% of purchased equip cost (B) 68,700 Piping 30% of purchased equip cost (B) 2,060,995 Insulation 1% of purchased equip cost (B) 68,700 Painting 1% of purchased equip cost (B) 68,700 Installation Subtotal Standard Expenses 85% 5,839,487

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 5,839,487 Total Direct Capital Cost, DC 12,709,471

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 686,998 Construction & field expenses 10% of purchased equip cost (B) 686,998 Contractor fees 10% of purchased equip cost (B) 686,998 Start-up 1% of purchased equip cost (B) 68,700 Performance test 1% of purchased equip cost (B) 68,700 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 206,100 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 2,404,494

Total Capital Investment (TCI) = DC + IC 15,113,965

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 15,113,965

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 1,085 kW-hr, 7946 hr/yr, 93% utilization 405,776
NA NA - Water 0.78 $/mgal, 225 gpm, 7946 hr/yr, 93% utilization 77,949
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 142 gpm, 7946 hr/yr, 93% utilizatio n 102,896
NA NA - NA NA - NA NA - NA NA - NA NA - Lime 25.31 $/ton, 56 lb/hr, 7946 hr/yr, 93% utilization 5,277
NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 641,957

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 302,279 Property tax (1% total capital costs) 1% of total capital costs (TCI) 151,140 Insurance (1% total capital costs) 1% of total capital costs (TCI) 151,140 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,426,651 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,061,246

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,703,203

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-8: SO2 Control - Wet Scrubber

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 693,543 8.55 0.7 - 991.1 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 5,663 gpm 1 60 0.7 - 91.3 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 142 gpm 1 60 0.7 - 2.3 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other
Other
Other Total 1084.7

Reagent Use & Other Operating Costs
Caustic Use 36.17 lb/hr SO2 2.50 lb NaOH/lb SO2 90.42 lb/hr Caustic
Lime Use 36.17 lb/hr SO2 1.56 lb Lime/lb SO2 56 lb/hr Lime

Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf Circulating Water Rate 5,663 gpm Water Makeup Rate/WW Disch = 2.5% of circulating water rate = 142 gpm Scrubber Outlet Flow 566,332 acfm Scrubber Outlet Temp 120 °F Evap H2O Loss 83 gpm Water Makeup Rate 225 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1084.7 kW-hr 8,015,405 405,776 $/kwh, 1,085 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 224.6 gpm 99,577 77,949 $/mgal, 225 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 141.6 gpm 62,776 102,896 $/mgal, 142 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 56.4 lb/hr 208 5,277 $/ton, 56 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-9: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Indurator Hood Exhaust

Emission Unit Number EU 038 Stack/Vent Number SV 018 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 480,406 scfm @ 32o F Expected Utilization Rate 93% Temperature 250 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% Annual Interest Rate 7.0% Actual Flow Rate 693,543 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 515,557 scfm @ 68o F Dry Std Flow Rat e 467,095 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 6,225,735 Purchased Equipment Total (B) 22% of control device cost (A) 7,564,268

Installation - Standard Costs 85% of purchased equip cost (B) 6,429,627 Installation - Site Specific Costs NA Installation Total 6,429,627 Total Direct Capital Cost, DC 13,993,895 Total Indirect Capital Costs, IC 35 % of purchased equip cost (B) 2,647,494 Total Capital Investment (TCI) = DC + IC 19,139,941

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,058,993 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,602,309 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 6,661,302

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 334.6 1,236.3 1236.3 - NA Total Particulates 334.6 1,236.3 1236.3 - NA Nitrous Oxides (NOx) 165.2 610.6 60% 244.2 366.3 18,183 Sulfur Dioxide (SO 2 ) 36.2 133.6 133.6 - NA
Sulfuric Acid Mist 0.3 1.1 1.1 - NA Fluorides 1.9E-01 6.9E-01 6.9E-01 - NA Volatile Organic Compounds (VOC) 2.1 7.7 7.7 - NA Carbon Monoxide (CO) 4.3 16.1 16.1 - NA Lead (Pb) 0.2 0.7 0.71 - NA

Notes & Assumptions
1 Sept 2005 Cost Estimate Procedure from BOC Gases

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Scrubber Cost per Barr Engineering 2004 Scrubber Project. Adjusted prices per Chemical Engineering Magazine CPI Index 2004 = 44 4, 2005 =465 6 Used 0.6 power law factor to adjust price to calculated acfm from bid basis of 500,000 acfm 7 Total scrubber equipment cost is the sum of the scrubber from note 5 and BOC gases procedure from note 1
8 Wastewater treatment costs provided by Nalco 6/8/06 email for reverse osmosis system, evaporator and crystallizer
9 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-9: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 6,225,735

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 622,573 MN Sales Taxes 6.5% of control device cost (A) 404,673 Freight 5% of control device cost (A) 311,287 Purchased Equipment Total (B) 22% 7,564,268

Installation

Foundations & supports 12% of purchased equip cost (B) 907,712 Handling & erection 40% of purchased equip cost (B) 3,025,707 Electrical 1% of purchased equip cost (B) 75,643 Piping 30% of purchased equip cost (B) 2,269,280 Insulation 1% of purchased equip cost (B) 75,643 Painting 1% of purchased equip cost (B) 75,643 Installation Subtotal Standard Expenses 85% 6,429,627

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 6,429,627 Total Direct Capital Cost, DC 13,993,895

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 756,427 Construction & field expenses 10% of purchased equip cost (B) 756,427 Contractor fees 10% of purchased equip cost (B) 756,427 Start-up 1% of purchased equip cost (B) 75,643 Performance test 1% of purchased equip cost (B) 75,643 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 226,928 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 2,647,494 Ozone Generator, Installed Cost 2,498,553 Total Capital Investment (TCI) = DC + IC 19,139,941

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 19,139,941

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 2,591 kW-hr, 7946 hr/yr, 93% utilization 969,399
NA NA - Water 0.78 $/mgal, 225 gpm, 7946 hr/yr, 93% utilization 77,949 Cooling Water 0.27 $/mgal, 744 gpm, 7946 hr/yr, 93% utilization 88,580
NA NA - NA NA - WW Treat R/O 40.10 $/mgal, 142 gpm, 7946 hr/yr, 93% utilization 2,517,414
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Oxygen 1.44 Mscf, 33 Mscf/hr, 7946 hr/yr, 93% utilization 355,591
NA NA - NA NA - Total Annual Direct Operating Costs 4,058,993

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 382,799 Property tax (1% total capital costs) 1% of total capital costs (TCI) 191,399 Insurance (1% total capital costs) 1% of total capital costs (TCI) 191,399 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,806,675 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,602,309

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 6,661,302

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment A - Emission Control Cost Analysis Table A-9: NOx Control - LoTOx - (Low Temperature Oxidation) Wastewater Treating Costs for LoTOx 8
Capital Recovery Factors 76 gpm, R/O System Design Rate Primary Installation 3,740,000 Installed Capital Cost Interest Rate 7.00% 353,030 Capital Recovery Cost Equipment Life 20 years 1,100,000 Operating & Maintenance Cost CRF 0.0944 1,453,030 A nnual Operating Cost 40.10 Wastewater Treatment Cost $/kgal Replacement Parts & Equipment: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp k W Blower, Scrubber 693,543 10 0.7 - 1,159.2 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 5,663 gpm 1 60 0.7 - 91.3 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 142 gpm 1 60 0.7 - 2.3 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
LTO Electric Use 4.5 kW/lb O 3 1,339

Total 2591.3

Reagent Use & Other Operating Costs Ozone Needed 1.8 lb O3/lb NOx 297.4 lb/hr O3 Oxygen Needed 10% wt O2 to O3 conversion 2974.46749 lb/hr O2 33,370 scfh O2 LTO Cooling Water 150 gal/lb O3 744 gpm Ozone Generator $350 lb O3/day $2,498,553 Installed Installed cost factor per BOC. Scrubber Cost 10 $/scfm Gas $4,804,055 Incremental cost per BOC. Need to increase vessel size over standard absorber. Scrubber Outlet Flow 566,332 acfm Scrubber Outlet Temp 120 °F Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf Circulating Water Rate 5,663 gpm Waste WaterDisch = 2.5% of circulating water rate = 142 gpm Evap H2O Loss 83 gpm Water Makeup Rate 225 gpm

Operating Cost Calculation s Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit o f Use Unit o f A nnual A nnual Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2591.3 kW-hr 19,148,815 969,399 $/kwh, 2,591 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 224.6 gpm 99,577 77,949 $/mgal, 225 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 743.6 gpm 329,710 88,580 $/mgal, 744 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization WW Treat R/O 40.10 $/mgal 141.6 gpm 62,776 2,517,414 $/mgal, 142 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 33.4 Mscf/hr 246,596 355,591 Mscf, 33 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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# Attachment B

Indurator Waste Gas Stack BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment B - Emission Control Cost AnalysisTable B-1: Cost Summary - Indurator Waste Gas ExhaustPM/PM10 Control Cost Summary *Control TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber0.012gr/dscf120.1 1116.2 $2,609,897 $1,246,444 $729 NA None High Waste-waterDry ElectroStatic Precipitator(ESP)0.012gr/dscf120.1 1116.2 $7,033,094 $1,450,822 $1,300 NA None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)0.012gr/dscf120.1 1116.2 $17,343,207 $3,459,351 $3,099 NA None Low Waste-waterUncontrolled0% 1236.3* Based on highest emission rate if PM not equal to PM10SO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Absorber90.0% 38.0 342.3 $11,956,125 $2,108,175 $6,158NA WESP is inferiorcontrolNone Low Waste-waterBaghouse w/Dry Scrubber85.0% 57.1 323.3 $26,007,235 $4,419,559 $13,670 -$50,490 None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)90.0% 38.0 342.3 $17,343,207 $3,459,351 $10,106 NA None Low Waste-waterUncontrolled0% 380.4NOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?LoTOx90% 171.4 1543.0 $18,710,779 $7,330,492 $4,751NANone MediumWaste-waterUncontrolled0%1714.5P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach B - Indurator Waste Gas Mar 2007 RevisionCost Summary3/13/2007Page 1 of 21Minnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment B - Emission Control Cost AnalysisTable B-1: Cost Summary - Indurator Waste Gas ExhaustSulfuric Acid Mist Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Absorber90% 0.3 2.8 $11,956,125 $2,108,175 $747,294NA WESP is inferiorcontrolNone Low Waste-waterBaghouse w/Dry Scrubber90% 0.3 2.8 $26,007,235 $4,419,559 $1,566,620 #DIV/0! None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)90% 0.3 2.8 $17,343,207 $3,459,351 $1,226,251 NA None Low Waste-waterUncontrolled0% 3.1Fluoride Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Absorber95% 9.2E-01 1.7E+01 $11,956,125 $2,108,175 $121,264NA WESP is inferiorcontrolNone Low Waste-waterBaghouse w/Dry Scrubber95% 9.2E-01 1.7E+01 $26,007,235 $4,419,559 $254,216$349,802None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)80% 3.7E+00 1.5E+01 $17,343,207 $3,459,351 $236,294 NA None Low Waste-wateruncontrolled0% 1.8E+01Lead Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber95% 4.9E-02 9.4E-01 $2,609,897 $1,246,444$1,326,561 NANone High Waste-waterDry ElectroStatic Precipitator(ESP)95% 4.9E-02 9.4E-01 $7,033,094 $1,450,822 $1,544,076 NA None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)95% 4.9E-02 9.4E-01 $17,343,207 $3,459,351 $3,681,707 NA None Low Waste-waterUncontrolled0% 9.9E-01The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual control efficiencies.Wet Scrubber/Absorber/LoTOx - Combined Pollutant Control Cost SummaryPollutantControlEff %AnnualizedOperatingCost $/yrPollutionControl Cost$/tonIncrementalOperating Cost$/yrIncrementalControl Cost $/tonParticulate Matter (PM)0.012gr/dscf$1,246,444 $729 Base Case Base CaseSulfur Dioxide (SO2)90% $2,108,175 $6,158 $861,731 $2,517Nitrogen Oxides (NOx)90% $7,330,492 $4,751 $5,222,317 $3,384P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach B - Indurator Waste Gas Mar 2007 RevisionCost Summary3/13/2007Page 2 of 21

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Indurator Waste Gas Stack Study Year 2005 Emission Unit Number EU 039 Stack/Vent Number SV 019 Reference Item Unit Cos t Units Cos t Y ear Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.051 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.78 $/mgal 0.76 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation

Cooling Water 0.27 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.31 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.64 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.15 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 27.32 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3% inflation

Hazardous Waste Disposal 273.18 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3% inflation

Waste Transport 0.55 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycle 1.16 $/ton 1.00 2000 Corus Study for MN Iron and Steel Project Study use $1/ton to cover cost of materials movement

Chemicals & Supplie s Lime 25.31 $/ton 24.57 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation Caustic 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.44 Mscf 1.40 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation EPA Urea 179.1 $/ton

Ammonia 0.17 $/lb R.G Hoeff & E.D Nafzinger Dept of Crop Sciences, Univ of Ill Jan 2001 Basis delivered price of ammonia $400 per ton at $8 MMBtu natural gas price. Adjusted price per MN Steel natual gas price Reagent #8 $/ton

Catalyst & Replacement Parts SCR Catalyst 500 $/ft 3 Cormetech, Inc. CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 Catalyst #4 Catalyst #5

Filter Bags 36.84 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Other Sales Tax 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Informatio n A nnual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 93% 2004 Kaar Consulting MSI Cost Model Equipment Life 20 yrs Engineering Estimate Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 325,058 scfm @ 32o F

Temperature 250 Deg F 250° F pellet plant exhaust temperature per MPCA comment, Hongming Jiang 120° F scrubber exhaust temperature per MN Steel Emission Inventory. Used for wet scrubber and wet ESP calcuations Moisture Content 9.4%

Actual Flow Rate 469,275 acfm ac f m b as i s 250 ° F process equipment exhaus t temperature Standardized Flow Rate 348,843 scfm @ 68o F Dry Std Flow Rate 316,052 dscfm @ 68o F

Max Emis Pollutan t Lb/H r Uncontrolled Conc PM10 334.6 0.12 gr/dscf Total Particulates 334.6 0.12 gr/dscf Nitrous Oxides (NOx) 464.0 205 ppm Sulfur Dioxide (SO 2 ) 102.9 33 ppm Sulfuric Acid Mist 0.85 0.2 ppm Fluorides 4.95 1.8E-03 gr/dscf 2,646.9 ppb Volatile Organic Compounds (VOC) 5.9 8 ppm Carbon Monoxide (CO) 12.4 9 ppm Lead (Pb) 0.27 9.9E-05 gr/dscf 26 ppb

Enter this data for each emission uni t Enter data for this study (applies to all units )

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-3: PM Control - Wet Wall ESP

Operating Unit: Indurator Waste Gas Stack

Emission Unit Number EU 039 Stack/Vent Number SV 019 Chemical Engineering Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 325,058 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 250 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 469,275 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 348,843 scfm @ 68o F Dry Std Flow Rate 316,052 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 6,260,633 Purchased Equipment Total (B) 22% of control device cost (A) 7,606,670

Installation - Standard Costs 71% of purchased equip cost (B) 5,400,735 Installation - Site Specific Costs NA Installation Total 5,400,735 Total Direct Capital Cost, DC 13,007,405 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,335,802 Total Capital Investment (TCI) = DC + IC 17,343,207

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 994,028 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,465,323 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,459,351

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 0.012 gr/dscf 120.1 1,116.2 3,099 Total Particulates 334.6 1,236.3 0.006 gr/dscf 60.1 1,176.3 2,941 Nitrous Oxides (NOx) 464.0 1,714.5 1714.5 - NA Sulfur Dioxide (SO 2 ) 102.9 380.4 90% 38.0 342.3 10,106
Sulfuric Acid Mist 0.8 3.1 90% 0.3 2.8 1,226,251 Fluorides 5.0E+00 1.8E+01 80% 3.7E+00 1.5E+01 236,294 Volatile Organic Compounds (VOC) 5.9 22.0 22.0 - NA Carbon Monoxide (CO) 12.4 45.7 45.7 - NA Lead (Pb) 0.3 1.0 95% 0.05 0.94 3,681,707

Notes & Assumptions
1 Sept 8, 2005 Cost Estimate from Durr Environmental
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
3 Piping cost estimated to be 5% of purchase price; same as PM wet scrubber. Change to account for additional piping needed for w ater sprays in WESP.
4 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation 5 ESP maintenance materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
6 ESP blower electrical use Eq 3.46 EPA Cont Cost Manual Section 6 Chapter 3 7 ESP grid electrical use Eq 3.48 EPA Cont Cost Manual Section 6 Chapter 3
8 WESP pump electrical use Eq 3.48 EPA Cont Cost Manual Section 6 Chapter 3
9 Estimated ESP Grid Area at 219 ft 2 per 1000 acfm EPA example problem Manual Section 6 Chapter 3.4.5.1
10 Used 0.6 power law factor to adjust price to calculated acfm value from bid basis of 291,000 acfm
11 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21
12 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies. 13 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-3: PM Control - Wet Wall ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 6,260,633

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 626,063 MN Sales Taxes 6.5% of control device cost (A) 406,941 Freight 5% of control device cost (A) 313,032 Purchased Equipment Total (B) 22% 7,606,670

Installation

Foundations & supports 4% of purchased equip cost (B) 304,267 Handling & erection 50% of purchased equip cost (B) 3,803,335 Electrical 8% of purchased equip cost (B) 608,534 Piping (3) 5% of purchased equip cost (B) 380,333 Insulation 2% of purchased equip cost (B) 152,133 Painting 2% of purchased equip cost (B) 152,133 Installation Subtotal Standard Expenses 71% 5,400,735

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 5,400,735 Total Direct Capital Cost, DC 13,007,405

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,521,334 Construction & field expenses 20% of purchased equip cost (B) 1,521,334 Contractor fees 10% of purchased equip cost (B) 760,667 Start-up 1% of purchased equip cost (B) 76,067 Performance test 1% of purchased equip cost (B) 76,067 Model Studies 2% of purchased equip cost (B) 152,133 Contingencies 3% of purchased equip cost (B) 228,200 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,335,802

Total Capital Investment (TCI) = DC + IC 17,343,207

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 17,343,207

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Supervisor 48% % of Operator Costs. 15,256
Maintenance

Maintenance Labor 102,771 ft2 grid area, 1.0 $/ft2 of grid area 101,091 Maintenance Materials 1 1% of purchased equipment cost 76,067 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 994 kW-hr, 7946 hr/yr, 93% utilization 371,898
NA NA - Water 0.78 $/mgal, 179 gpm, 7946 hr/yr, 93% utilization 62,058
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 96 gpm, 7946 hr/yr, 93% utilizatio n 69,623
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Caustic 280.00 $/ton, 257 lb/hr, 7946 hr/yr, 93% utilization 266,251
NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 994,028

Indirect Operating Costs Overhead 60% of total labor and material costs 134,519 Administration (2% total capital costs) 2% of total capital costs (TCI) 346,864 Property tax (1% total capital costs) 1% of total capital costs (TCI) 173,432 Insurance (1% total capital costs) 1% of total capital costs (TCI) 173,432 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,637,076 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,465,323

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,459,351

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-3: PM Control - Wet Wall ESP

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Us e

Flow acfm D P in H2O Efficiency Hp kW Blower Baghouse & ES P 469,275 9 764.4 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq. flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 1916 gpm 1.000 40 0.5 28.8 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 96 gpm 1.000 40 0.5 1.4 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 102,771 ft 2 1.94E-03 kW/ft 2 199.4 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 994.1

Reagent Use & Other Operating Costs WESP Pump 383,199 acfm 5 gpm/kacfm 1,916 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disc h 5% of circulating water rate = 96 gpm

Caustic Use 102.94 lb/hr SO2 2.50 lb NaOH/lb SO2 257 lb/hr Caustic

Scrubber Outlet Flow 383,199 acfm Scrubber Outlet Temp 120 °F Evap H2O Loss 83 gpm Water Makeup Rate 179 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 15,256 % of Operator Costs. Maintenance Maint Labor 102,771 ft2 grid area 0.984 $/ft 2 of grid area 101,091 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 76,067 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 994.1 kW-hr 7,346,201 371,898 $/kwh, 994 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 178.8 gpm 79,277 62,058 $/mgal, 179 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 95.8 gpm 42,476 69,623 $/mgal, 96 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 257 lb/hr 951 266,251 $/ton, 257 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-4: PM Control - Dry ESP

Operating Unit: Indurator Waste Gas Stack

Emission Unit Number EU 039 Stack/Vent Number SV 019 Chemical Engineering Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 325,058 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 250 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 469,275 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 348,843 scfm @ 68o F Dry Std Flow Rate 316,052 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 2,584,176 Purchased Equipment Total (B) 22% of control device cost (A) 3,139,77 4

Installation - Standard Costs 67% of purchased equip cost (B) 2,103,649 Installation - Site Specific Costs NA Installation Total 2,103,649 Total Direct Capital Cost, DC 5,243,423 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,789,671 Total Capital Investment (TCI) = DC + IC 7,033,09 4

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 397,906 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,052,916 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,450,822

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 0.012 gr/dscf 120.1 1,116.2 1,300 Total Particulates 334.6 1,236.3 0.006 gr/dscf 60.1 1,176.3 1,233 Nitrous Oxides (NOx) 464.0 1,714.5 1714.5 - NA Sulfur Dioxide (SO 2 ) 102.9 380.4 380.4 - NA
Sulfuric Acid Mist 0.8 3.1 3.1 - NA Fluorides 5.0E+00 1.8E+01 1.8E+01 0.0E+00 NA Volatile Organic Compounds (VOC) 5.9 22.0 22.0 - NA Carbon Monoxide (CO) 12.4 45.7 45.7 - NA Lead (Pb) 0.3 1.0 95% 0.05 0.94 1,544,076

Notes & Assumptions
1 Cost Estimate from 2001 Bids for Taconite Plant ESP and EPA Air Compliance Advisor Ver 7.7. Used average cost adjusted for infl ation.
2 Cost estimation basis 291,000 acfm. Used 0.6 power law factor to adjust price to calculated acfm
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
4 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation 5 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
6 Estimated ESP Grid Area at 219 ft 2 per 1000 acfm EPA example problem Manual Section 6 Chapter 3.4.5.1
7 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21
8 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-4: PM Control - Dry ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 2,584,176

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 258,418 MN Sales Taxes 6.5% of control device cost (A) 167,971 Freight 5% of control device cost (A) 129,209 Purchased Equipment Total (B) 22% 3,139,77 4

Installation

Foundations & supports 4% of purchased equip cost (B) 125,591 Handling & erection 50% of purchased equip cost (B) 1,569,887 Electrical 8% of purchased equip cost (B) 251,182 Piping 1% of purchased equip cost (B) 31,398 Insulation 2% of purchased equip cost (B) 62,795 Painting 2% of purchased equip cost (B) 62,795 Installation Subtotal Standard Expenses 67% 2,103,649

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 2,103,649 Total Direct Capital Cost, DC 5,243,423

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 627,955 Construction & field expenses 20% of purchased equip cost (B) 627,955 Contractor fees 10% of purchased equip cost (B) 313,977 Start-up 1% of purchased equip cost (B) 31,398 Performance test 1% of purchased equip cost (B) 31,398 Model Studies 2% of purchased equip cost (B) 62,795 Contingencies 3% of purchased equip cost (B) 94,193 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,789,671

Total Capital Investment (TCI) = DC + IC 7,033,09 4

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,033,09 4

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Supervisor 48% % of Operator Costs. 15,256
Maintenance

Maintenance Labor 102,771 ft2 grid area, 1.0 $/ft2 of grid area 101,091 Maintenance Materials 1 1% of purchased equipment cost 31,398 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 580 kW-hr, 7946 hr/yr, 93% utilization 216,943
NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization 1,433
NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 397,906

Indirect Operating Costs Overhead 60% of total labor and material costs 107,718 Administration (2% total capital costs) 2% of total capital costs (TCI) 140,662 Property tax (1% total capital costs) 1% of total capital costs (TCI) 70,331 Insurance (1% total capital costs) 1% of total capital costs (TCI) 70,331 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 663,874 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,052,916

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,450,822

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-4: PM Control - Dry ESP

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Us e

Flow acfm D P in H2O Efficiency Hp kW Blower Baghouse & ES P 469,275 4.48 380.5 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 102,771 ft 2 1.94E-03 kW/ft 2 199.4 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 579.9

Reagent Use & Other Operating Costs WESP Pump acfm 5 gpm/kacfm 0 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disc h 20% of circulating water rate = 0 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 15,256 % of Operator Costs. Maintenance Maint Labor 102,771 ft2 grid area 0.984 $/ft 2 of grid area 101,091 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 31,398 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 579.9 kW-hr 4,285,343 216,943 $/kwh, 580 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 Mi 0 0 $/ton-mi, 0 Mi, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.2 ton/hr 1,236 1,433 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-5: PM Control - Wet Scrubber

Stack/Vent Number(s): Operating Unit: Indurator Waste Gas Stack

Emission Unit Number EU 039 Stack/Vent Number SV 019 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 325,058 scfm @ 32o F Expected Utilization Rate 93% Temperature 250 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% Annual Interest Rate 7.0% Actual Flow Rate 469,275 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 348,843 scfm @ 68o F Dry Std Flow Rate 316,052 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,124,641 Purchased Equipment Total (B) 22% of control device cost (A) 1,366,438

Installation - Standard Costs 56% of purchased equip cost (B) 765,205 Installation - Site Specific Costs NA Installation Total 765,205 Total Direct Capital Cost, DC 2,131,644 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 478,253 Total Capital Investment (TCI) = DC + IC 2,609,897

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 813,689 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 432,754 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,246,44 4

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 0.012 gr/dscf 120.1 1,116.2 729 Total Particulates 334.6 1,236.3 0.006 gr/dscf 60.1 1,176.3 692 Nitrous Oxides (NOx) 464.0 1,714.5 1714.5 - NA Sulfur Dioxide (SO 2 ) 102.9 380.4 380.4 - NA
Sulfuric Acid Mist 0.8 3.1 3.1 - NA
Fluorides 5.0E+00 1.8E+01 1.8E+01 0.0E+00 NA Volatile Organic Compounds (VOC) 5.9 22.0 22.0 - NA Carbon Monoxide (CO) 12.4 45.7 45.7 - NA Lead (Pb) 0.3 1.0 95% 0.05 0.94 1,326,561

Notes & Assumptions
1 Scrubber Cost per Barr Engineering 2004 Scrubber Project. Adjusted prices per Chemical Engineering Magazine CPI Index 2004 = 44 4, 2005 =465 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 2
3 Used 0.6 power law factor to adjust price to calculated acfm from bid basis of 500,000 acfm
4 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies. 5 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-5: PM Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 1,124,641

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 112,464 MN Sales Taxes 6.5% of control device cost (A) 73,102 Freight 5% of control device cost (A) 56,232 Purchased Equipment Total (B) 22% 1,366,438

Installation

Foundations & supports 6% of purchased equip cost (B) 81,986 Handling & erection 40% of purchased equip cost (B) 546,575 Electrical 1% of purchased equip cost (B) 13,664 Piping 5% of purchased equip cost (B) 68,322 Insulation 3% of purchased equip cost (B) 40,993 Painting 1% of purchased equip cost (B) 13,664 Installation Subtotal Standard Expenses 56% 765,205

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 765,205 Total Direct Capital Cost, DC 2,131,64 4

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 136,644 Construction & field expenses 10% of purchased equip cost (B) 136,644 Contractor fees 10% of purchased equip cost (B) 136,644 Start-up 1% of purchased equip cost (B) 13,664 Performance test 1% of purchased equip cost (B) 13,664 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 40,993 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 478,253

Total Capital Investment (TCI) = DC + IC 2,609,897

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,609,897

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535 Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100.00 % of Maintenance Labor 31,784 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 1,458 kW-hr, 7946 hr/yr, 93% utilization 545,337
NA NA - Water 0.78 $/mgal, 179 gpm, 7946 hr/yr, 93% utilization 62,058
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 96 gpm, 7946 hr/yr, 93% utilizatio n 69,623
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 813,689

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 52,198 Property tax (1% total capital costs) 1% of total capital costs (TCI) 26,099 Insurance (1% total capital costs) 1% of total capital costs (TCI) 26,099 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 246,356 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 432,754

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,246,44 4

See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-5: PM Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3
Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Us e

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 469,275 15 0.6 1,845.8 1,376.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.40
L/G ratio* Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 10 1.125 40 0.5 106.9 79.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41
H2O WW Disch Pump 96 gpm 1.125 40 0.5 2.2 1.6 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41
Other Other
Other Total 1457.7 * L/G = Gal/1,000 acf

Reagent Use & Other Operating Costs
Caustic Use 102.94 lb/hr SO2 2.50 lb NaOH/lb SO2 257.35 lb/hr Caustic Lime Use 102.94 lb/hr SO2 1.53 lb Lime/lb SO2 157.50 lb/hr Lime Circulating Water Rate 3,832 gpm Water Makeup Rate/WW Disch = 2.5% of circulating water rate = 96 gpm

Scrubber Outlet Flow 383,199 acfm Scrubber Outlet Temp 120 °F Evap H2O Loss 83 gpm Water Makeup Rate 179 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1457.7 kW-hr 10,772,195 545,337 $/kwh, 1,458 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 178.8 gpm 79,277 62,058 $/mgal, 179 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 95.8 gpm 42,476 69,623 $/mgal, 96 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Urea 405 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-7: SO2 Control Dry Scrubbing with Baghouse

Operating Unit: Indurator Waste Gas Stack

Emission Unit Number EU 039 Stack/Vent Number SV 019 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 325,058 scfm @ 32o F Expected Utilization Rate 93% Temperature 250 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% Annual Interest Rate 7.0% Actual Flow Rate 469,275 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 348,843 scfm @ 68o F Dry Std Flow Rate 316,052 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 9,774,033 Purchased Equipment Total (B) 22% of control device cost (A) 11,875,450

Installation - Standard Costs 74% of purchased equip cost (B) 8,787,833 Installation - Site Specific Costs NA Installation Total 8,787,833 Total Direct Capital Cost, DC 20,663,283 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 5,343,952 Total Capital Investment (TCI) = DC + IC 26,007,235

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 875,757 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,543,802 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,419,559

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 0.012 gr/dscf 120.1 1,116.2 3,959 Total Particulates 334.6 1,236.3 0.006 gr/dscf 60.1 1,176.3 3,757 Nitrous Oxides (NOx) 464.0 1,714.5 1714.5 - NA Sulfur Dioxide (SO 2 ) 102.9 380.4 85% 57.1 323.3 13,670

Sulfuric Acid Mist 0.8 3.1 90% 0.31 2.8 1,566,620 Fluorides 5.0E+00 1.8E+01 95% 9.2E-01 1.7E+01 254,216 Volatile Organic Compounds (VOC) 5.9 22.0 22.0 - NA Carbon Monoxide (CO) 12.4 45.7 45.7 - NA Lead (Pb) 0.3 1.0 0.99 - NA

Notes & Assumptions
1 Sept 2, 2005 Cost Estimate Environmental Elements
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1
3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapt er 1.5.1.8
4 Bag replacement at 10 min/bag EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min pe r bag. 5 Used 0.6 power law factor to adjust price to calculated dscfm from bid basis of 217,000 dscfm 6 $250,000 bag replacement cost from vendor adjusted for flow rate as noted above

7 Lime consumption per vendor 1.56 lb lime / lb SO 2 removed

8 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-7: SO2 Control Dry Scrubbing with Baghouse

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 9,774,033

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 977,403 MN Sales Taxes 6.5% of control device cost (A) 635,312 Freight 5% of control device cost (A) 488,702 Purchased Equipment Total (B) 22% 11,875,450

Installation

Foundations & supports 4% of purchased equip cost (B) 475,018 Handling & erection 50% of purchased equip cost (B) 5,937,725 Electrical 8% of purchased equip cost (B) 950,036 Piping 1% of purchased equip cost (B) 118,754 Insulation 7% of purchased equip cost (B) 831,281 Painting 4% of purchased equip cost (B) 475,018 Installation Subtotal Standard Expenses 74% 8,787,833

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 8,787,833 Total Direct Capital Cost, DC 20,663,283

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 1,187,545 Construction & field expenses 20% of purchased equip cost (B) 2,375,090 Contractor fees 10% of purchased equip cost (B) 1,187,545 Start-up 1% of purchased equip cost (B) 118,754 Performance test 1% of purchased equip cost (B) 118,754 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 356,263 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 5,343,952

Total Capital Investment (TCI) = DC + IC 26,007,235

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 25,653,510

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535
Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100% of maintenance labor costs 31,784 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 1,359 kW-hr, 7946 hr/yr, 93% utilization 508,414
NA NA - NA NA - NA NA - Comp Air 0.31 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 93% utilization 127,950

NA NA - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization 1,433 Lime 25.31 $/ton, 161 lb/hr, 7946 hr/yr, 93% utilization 15,018
NA NA - NA NA - NA NA - Filter Bags 33.71 $/bag, 795 bags, 7946 hr/yr, 93% utilization 86,270 Total Annual Direct Operating Costs 875,757

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 520,145 Property tax (1% total capital costs) 1% of total capital costs (TCI) 260,072 Insurance (1% total capital costs) 1% of total capital costs (TCI) 260,072 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,421,510 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,543,802

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,419,559

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-7: SO2 Control Dry Scrubbing with Baghouse

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages Equipment Life 5 years CRF 0.2439 Rep part cost per unit 33.711 $/bag Amount Required 795 Total Rep Parts Cost 346,603 Cost adjusted for freight & sales tax Installation Labo r 7,123 10 min per bag, Labor + Overhead (68% = $29.65/hr ) EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1. 4 Total Installed Cos t 353,726 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag

. Annualized Cost 86,270

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Baghouse 469,275 16 1359.0 Baghouse Shaker 0.0 Gross fabric area ft 2 0 EPA Cont Cost Manual 6th ed Section 6 Chapter 1 Eq 1.14 Other Other Other
Other
Other Total 1359.0

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Gross BH Filter Area 10,661 ft 2

Cages 10 ft long 5 in dia 13.42 area/cage ft 2 795 Cages 11.036 $/cage Bags 1.69 $/ft2 of fabric 22.68 $/bag
Total 33.711

Lime Use Rate 1.56 lb lime/lb SO2 removed 161 lb/hr Lime

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1359.0 kW-hr 10,042,853 508,414 $/kwh, 1,359 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 2 scfm/kacfm 416,140 127,950 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.2 ton/hr 1,236 1,433 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.31 $/ton 161 lb/hr 593 15,018 $/ton, 161 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 33.71 $/bag 795 bags NA 86,270 $/bag, 795 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-8: SO2 Control - Wet Scrubber

Operating Unit: Indurator Waste Gas Stack

Emission Unit Number EU 039 Stack/Vent Number SV 019 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 325,058 scfm @ 32o F Expected Utilization Rate 93% Temperature 250 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 9.4% Annual Interest Rate 7.0% Actual Flow Rate 469,275 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 348,843 scfm @ 68o F Dry Std Flow Rate 316,052 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 4,472,924 Purchased Equipment Total (B) 22% of control device cost (A) 5,434,602

Installation - Standard Costs 85% of purchased equip cost (B) 4,619,412 Installation - Site Specific Costs NA Installation Total 4,619,412 Total Direct Capital Cost, DC 10,054,015 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 1,902,111 Total Capital Investment (TCI) = DC + IC 11,956,125

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 471,320 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,636,855 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,108,175

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 334.6 1,236.3 1236.3 - NA Total Particulates 334.6 1,236.3 1236.3 - NA Nitrous Oxides (NOx) 464.0 1,714.5 1714.5 - NA Sulfur Dioxide (SO 2 ) 102.9 380.4 90% 38.0 342.3 6,158
Sulfuric Acid Mist 0.8 3.1 90% 0.3 2.8 747,294 Fluorides 5.0E+00 1.8E+01 95% 9.2E-01 1.7E+01 121,264 Volatile Organic Compounds (VOC) 5.9 22.0 22.0 - NA Carbon Monoxide (CO) 12.4 45.7 45.7 - NA Lead (Pb) 0.3 1.0 0.99 - NA

Notes & Assumptions
1 Sept 2, 2005 Cost Estimate Environmental Elements. Adjust downward (to $3.5M) for removal of vacuum filter and building
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Used 0.6 power law factor to adjust price to calculated dscfm from bid basis of 210,000 dscfm 6 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies. 7 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-8: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 4,472,924

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 447,292 MN Sales Taxes 6.5% of control device cost (A) 290,740 Freight 5% of control device cost (A) 223,646 Purchased Equipment Total (B) 22% 5,434,602

Installation

Foundations & supports 12% of purchased equip cost (B) 652,152 Handling & erection 40% of purchased equip cost (B) 2,173,841 Electrical 1% of purchased equip cost (B) 54,346 Piping 30% of purchased equip cost (B) 1,630,381 Insulation 1% of purchased equip cost (B) 54,346 Painting 1% of purchased equip cost (B) 54,346 Installation Subtotal Standard Expenses 85% 4,619,412

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 4,619,412 Total Direct Capital Cost, DC 10,054,015

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 543,460 Construction & field expenses 10% of purchased equip cost (B) 543,460 Contractor fees 10% of purchased equip cost (B) 543,460 Start-up 1% of purchased equip cost (B) 54,346 Performance test 1% of purchased equip cost (B) 54,346 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 163,038 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 1,902,111

Total Capital Investment (TCI) = DC + IC 11,956,125

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 11,956,125

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 734 kW-hr, 7946 hr/yr, 93% utilization 274,561
NA NA - Water 0.78 $/mgal, 179 gpm, 7946 hr/yr, 93% utilization 62,058
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 96 gpm, 7946 hr/yr, 93% utilizatio n 69,623
NA NA - NA NA - NA NA - NA NA - NA NA - Lime 25.31 $/ton, 161 lb/hr, 7946 hr/yr, 93% utilization 15,018
NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 471,320

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 239,123 Property tax (1% total capital costs) 1% of total capital costs (TCI) 119,561 Insurance (1% total capital costs) 1% of total capital costs (TCI) 119,561 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,128,574 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,636,855

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,108,175

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-8: SO2 Control - Wet Scrubber

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 469,275 8.55 0.7 - 670.6 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 3,832 gpm 1 60 0.7 - 61.7 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 96 gpm 1 60 0.7 - 1.5 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other
Other
Other Total 733.9

Reagent Use & Other Operating Costs
Caustic Use 102.94 lb/hr SO2 2.50 lb NaOH/lb SO2 257.35 lb/hr Caustic
Lime Use 102.94 lb/hr SO2 1.56 lb Lime/lb SO2 161 lb/hr Lime

Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf Circulating Water Rate 3,832 gpm Water Makeup Rate/WW Disch = 2.5% of circulating water rate = 96 gpm Scrubber Outlet Flow 383,199 acfm Scrubber Outlet Temp 120 °F Evap H2O Loss 83 gpm Water Makeup Rate 179 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 733.9 kW-hr 5,423,490 274,561 $/kwh, 734 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 178.8 gpm 79,277 62,058 $/mgal, 179 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 95.8 gpm 42,476 69,623 $/mgal, 96 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 160.6 lb/hr 593 15,018 $/ton, 161 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-9: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Indurator Waste Gas Stack

Emission Unit Number EU 039 Stack/Vent Number SV 019 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 325,058 scfm @ 32o F Expected Utilization Rat e 93% Temperature 250 Deg F Expected Annual Hours of Operatio n 7,94 6 Hours Moisture Conten t 9.4% Annual Interest Rate 7.0% Actual Flow Rate 469,275 acfm Expected Equipment Life 20 yrs Standardized Flow Rat e 348,84 3 scfm @ 68o F Dry Std Flow Rat e 316,05 2 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A ) 4,375,22 4 Purchased Equipment Total (B ) 22% of control device cost (A ) 5,315,89 8

Installation - Standard Costs 85% of purchased equip cost (B) 4,518,513 Installation - Site Specific Costs NA Installation Total 4,518,513 Total Direct Capital Cost, DC 9,834,411 Total Indirect Capital Costs, IC 35 % of purchased equip cost (B ) 1,860,56 4 Total Capital Investment (TCI) = DC + IC 18,710,77 9

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,785,860 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,544,632 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 7,330,49 2

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 334.6 1,236.3 1236.3 - NA Total Particulate s 334. 6 1,236. 3 1236. 3

- N A Nitrous Oxides (NOx) 464.0 1,714.5 90% 171.4 1,543.0 4,751 Sulfur Dioxide (SO 2 ) 102.9 380.4 380.4 - NA
Sulfuric Acid Mist 0.8 3.1 3.1 - NA Fluorides 5.0E+00 1.8E+01 1.8E+01 - NA Volatile Organic Compounds (VOC) 5.9 22.0 22.0 - NA Carbon Monoxide (CO) 12.4 45.7 45.7 - NA Lead (Pb) 0.3 1.0 0.99 - N A

Notes & Assumptions 1 Sept 2005 Cost Estimate Procedure from BOC Gases

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers )
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Scrubber Cost per Barr Engineering 2004 Scrubber Project. Adjusted prices per Chemical Engineering Magazine CPI Index 2004 = 44 4, 2005 =465 6 Used 0.6 power law factor to adjust price to calculated acfm from bid basis of 500,000 acfm 7 Total scrubber equipment cost is the sum of the scrubber from note 5 and BOC gases procedure from note 1
8 Wastewater treatment costs provided by Nalco 6/8/06 email for reverse osmosis system, evaporator and crystallizer
9 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-9: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 4,375,224

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A ) 437,52 2 MN Sales Taxes 6.5% of control device cost (A ) 284,39 0 Freight 5% of control device cost (A) 218,761 Purchased Equipment Total (B) 22% 5,315,89 8

Installation

Foundations & supports 12% of purchased equip cost (B) 637,908 Handling & erection 40% of purchased equip cost (B) 2,126,359 Electrical 1% of purchased equip cost (B ) 53,15 9 Piping 30% of purchased equip cost (B) 1,594,769 Insulation 1% of purchased equip cost (B ) 53,15 9 Painting 1% of purchased equip cost (B ) 53,15 9 Installation Subtotal Standard Expense s 85% 4,518,51 3

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 4,518,51 3 Total Direct Capital Cost, DC 9,834,411

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 531,590 Construction & field expense s 10% of purchased equip cost (B) 531,590 Contractor fee s 10% of purchased equip cost (B ) 531,59 0 Start-up 1% of purchased equip cost (B) 53,159 Performance tes t 1% of purchased equip cost (B) 53,159 Model Studie s N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 159,477 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 1,860,564 Ozone Generator, Installed Cost 7,015,804 Total Capital Investment (TCI) = DC + IC 18,710,77 9

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 18,710,77 9

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Cost s 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 4,606 kW-hr, 7946 hr/yr, 93% utilizatio n 1,723,16 6
NA NA - Water 0.78 $/mgal, 179 gpm, 7946 hr/yr, 93% utilization 62,058 Cooling Water 0.27 $/mgal, 2,088 gpm, 7946 hr/yr, 93% utilization 248,729
NA NA - N A N A - WW Treat R/O 40.10 $/mgal, 96 gpm, 7946 hr/yr, 93% utilization 1,703,366
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Oxygen 1.44 Mscf, 94 Mscf/hr, 7946 hr/yr, 93% utilization 998,480
NA NA - NA NA - Total Annual Direct Operating Cost s 4,785,86 0

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 374,216 Property tax (1% total capital costs) 1% of total capital costs (TCI) 187,108 Insurance (1% total capital costs) 1% of total capital costs (TCI) 187,108 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,766,165 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 2,544,63 2

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 7,330,49 2

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment B - Emission Control Cost Analysis Table B-9: NOx Control - LoTOx - (Low Temperature Oxidation) Wastewater Treating Costs for LoTOx 8
Capital Recovery Factors 76 gpm, R/O System Design Rate Primary Installation 3,740,000 Installed Capital Cost Interest Rate 7.00% 353,030 Capital Recovery Cost Equipment Life 20 years 1,100,000 Operating & Maintenance Cost CRF 0.094 4 1,453,03 0 A nnual Operating Cos t
40.1 0 Wastewater Treatment Cost $/kgal Replacement Parts & Equipment: Equipment Life 5 years CRF 0.000 0 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement )
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cos t 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 469,27 5 10 0.7 - 784.4 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.4 8
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 3,832 gpm 1 60 0.7 - 61.7 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 96 gpm 1 60 0.7 - 1.5 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
LTO Electric Use 4.5 kW/lb O 3 3,758

Total 4606.1

Reagent Use & Other Operating Costs Ozone Neede d 1.8 lb O3/lb NOx 835.2 lb/hr O3 Oxygen Needed 10% wt O2 to O3 conversion 8352.14713 lb/hr O2 93,701 scfh O2 LTO Cooling Water 150 gal/lb O3 2,088 gpm Ozone Generator $350 lb O3/day $7,015,804 Installed Installed cost factor per BOC. Scrubber Cost 10 $/scfm Gas $3,250,584 Incremental cost per BOC. Need to increase vessel size over standard absorber. Scrubber Outlet Flow 383,199 acfm Scrubber Outlet Temp 120 °F Liquid/Gas rati o 10.0 * L/G = Gal/1,000 ac f Circulating Water Rate 3,832 gpm Waste WaterDisch = 2.5% of circulating water rate = 96 gpm Evap H2O Loss 83 gpm Water Makeup Rate 179 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 4606.1 kW-hr 34,038,184 1,723,166 $/kwh, 4,606 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 178.8 gpm 79,277 62,058 $/mgal, 179 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 2,088. 0 gpm 925,80 8 248,72 9 $/mgal, 2,088 gpm, 7946 hr/yr, 93% utilizatio n Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization WW Treat R/O 40.10 $/mgal 95.8 gpm 42,476 1,703,366 $/mgal, 96 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.30998 4 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilizatio n Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 93.7 Mscf/hr 692,427 998,480 Mscf, 94 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalys t 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilizatio n Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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# Attachment C

DRI Package Boiler BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment C - Emission Control Cost AnalysisTable C-1: Cost Summary - DRI Package BoilerNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?LoTOx70% 9.4 22.0 $724,544 $619,859 $28,142NA LoTOx is inferiorcontrolNone Medium Waste-WaterSelective Catalytic Reduction(SCR)70% 9.4 22.0 $1,676,449 $449,601 $20,412 $90,207 NH3 Slip Low Catalyst WasteULNB / LNB-FGR56%13.8 17.7 $429,399 $59,310 $3,351 NANone Low NoneSelective Non-CatalyticReduction (SNCR)25% 23.6 7.9 $861,742 $217,176 $27,608NA SNCR is inferiorcontrolNH3 Slip Low NoneBase CaseNA31.5CO Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Thermal OxidizerRecuperative90% 3.2 29.2 $622,596 $851,566 $29,194 NA None High NoneThermal OxidizerRegenerative90% 3.2 29.2 $801,987 $595,648 $20,420 NA None High Solid WasteCatalytic Oxidizer90%3.2 29.2 $764,279 $479,750 $16,447 NANone Medium Catalyst WasteUncontrolled0%32.4VOC Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Thermal OxidizerRecuperative90% 0.21 1.9 $622,596 $851,566 $446,128 NA None High NoneThermal OxidizerRegenerative90% 0.21 1.9 $801,987 $595,648 $312,055 NA None High Solid WasteCatalytic Oxidizer90%0.21 1.9 $764,279 $479,750 $251,337 NANone Low Catalyst WasteUncontrolled0%2.1P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach C - DRI Package Boiler Mar 2007 RevisionCost Summary3/6/2007Page 1 of 27

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: DRI Package Boiler Study Year 2005
Emission Unit Number EU 065 & 082 Stack/Vent Number SV 028 & 065 Reference Item Unit Cos t Units Cos t Year Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.051 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.78 $/mgal 0.76 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation

Cooling Water 0.27 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.31 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.64 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.15 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 27.32 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3%
inflation

Hazardous Waste Disposal 273.18 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3%
inflation

Waste Transport 0.55 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycle 1.16 $/ton 1.00 2000 Corus Study for MN Iron and Steel Project Study use $1/ton to cover cost of materials movement

Chemicals & Supplies Lime 25.31 $/ton 24.57 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation Caustic 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.44 Mscf 1.40 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation EPA Urea 179.1 $/ton
A mmonia 0.101 $/lb Reagent #8 $/ton

Catalyst & Replacement Parts SCR Catalyst 140 $/ft 3 Cormetech, Inc., 1/2006 bid CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 Catalyst #4 Catalyst #5

Filter Bags 36.84 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Othe r Sales Tax 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Information A nnual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 100% 2004 Kaar Consulting MSI Cost Model Equipment Life 20 yrs Engineering Estimate Design Capacity 99.0 MMBtu/hr Standardized Flow Rate 22,626 scfm @ 32o F Temperature 356 Deg F Moisture Content 18.1% Actual Flow Rate 37,543 acfm Standardized Flow Rate 22,173 Dry Std Flow Rate 18,160 dscfm @ 68o F

Max Emis Pollutan t Lb/Hr Uncontrolled Conc PM10 0.74 0.005 gr/dscf Total Particulates 0.74 0.005 gr/dscf NOx Control Efficiency Calculations Nitrous Oxides (NOx) 7.92 45 ppm 3.47 lb/hr NOx at 0.035 lb NOx/MMBtu Sulfur Dioxide (SO 2 ) 0.058 0.24 ppm 7.92 lb/hr NOx at 0.08 lb NOx/MMBtu Sulfuric Acid Mist 0.0 ppm 56.3% Control efficiency for LNB/FGR or UNLB @0.035 lb NOx/MMBtu Fluorides 0.0E+00 gr/dscf 70.0% SCR & LoTOX control efficiency Volatile Organic Compounds (VOC) 0.53 9 ppm 18 ppm NOx dry at SCR/LoTOx control efficiency Carbon Monoxide (CO) 8.16 77 ppm 25.0% SNCR control efficiency Lead (Pb) 0.0E+00 gr/dscf 46 ppm NOx dry at SNCR control efficiency 27 ULNB ppm NOx dry Enter this data for each emission uni t 61 Base Case ppm NOx dry Enter data for this study (applies to all units ) 31.5 T/yr NOx Base Case

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Operating Unit: DRI Package Boiler

Emission Unit Number EU 065 & 082 Stack/Vent Number SV 028 & 065 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 22,626 scfm @ 32o F Chemical Plant Cost Inde x Expected Utilization Rate 100% Temperature 356 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 37,543 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 24,282 scfm @ 68o F Dry Std Flow Rate 18,160 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 219,512 Purchased Equipment Total (B) 22% of control device cost (A) 266,707

Installation - Standard Costs 30% of purchased equip cost (B) 80,012 Installation - Site Specific Costs NA Installation Total 80,012 Total Direct Capital Cost, DC 346,720 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 82,679 Total Capital Investment (TCI) = DC + IC 429,399

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,001 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,309 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 59,310

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 2.9 2.9 - NA Total Particulates 0.7 2.9 2.9 - N A Nitrous Oxides (NOx) 7.9 31.5 56% 13.8 17.7 3,351 Sulfur Dioxide (SO 2 ) 0.1 0.2 0.2 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.5 2.1 2.1 - NA Carbon Monoxide (CO) 8.2 32.4 32.4 - NA Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Coen Burner, January, 2006 cost estimate
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Thermal Oxidizer factor used for low NOx burners because it has the lowest multipiler for installation cost
4 Used 0.6 power law factor to adjust price from bid basis of 50 MMBtu/hr

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 219,512

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 21,951 MN Sales Taxes 6.5% of control device cost (A) 14,268 Freight 5% of control device cost (A) 10,976 Purchased Equipment Total (B) 22% 266,707

Installation

Foundations & supports 8% of purchased equip cost (B) 21,337 Handling & erection 14% of purchased equip cost (B) 37,339 Electrical 4% of purchased equip cost (B) 10,668 Piping 2% of purchased equip cost (B) 5,334 Insulation 1% of purchased equip cost (B) 2,667 Painting 1% of purchased equip cost (B) 2,667 Installation Subtotal Standard Expense s 30% 80,012

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 80,012 Total Direct Capital Cost, DC 346,720

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 26,671 Construction & field expenses 5% of purchased equip cost (B) 13,335 Contractor fees 10% of purchased equip cost (B) 26,671 Start-up 2% of purchased equip cost (B) 5,334 Performance test 1% of purchased equip cost (B) 2,667 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 8,001 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 82,679

Total Capital Investment (TCI) = DC + IC 429,399

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 429,399

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr 318 Supervisor 15% 15% of Operator Costs 48
Maintenance

Maintenance Labor 32.00 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr 318 Maintenance Materials 100% of maintenance labor costs 318 Utilities, Supplies, Replacements & Waste Managemen t

N A N A - NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 1,001

Indirect Operating Costs Overhead 60% of total labor and material costs 601 Administration (2% total capital costs) 2% of total capital costs (TCI) 8,588 Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,294 Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,294 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 40,532 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 58,309

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 59,310

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 2 years CRF 0.5531 Rep part cost per unit 650 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 0 19 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 0.0

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 100.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.01 hr/8 hr shift 10 318 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 48 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.01 hr/8 hr shift 10 318 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 318 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-4: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: DRI Package Boiler

Emission Unit Number E U 065 & 082 Stack/Vent Number SV 028 & 065 Design Capacity 99 MMBtu/hr Standardized Flow Rate 22,626 scfm @ 32o F Expected Utilization Rate 100% Temperature 356 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% Annual Interest Rate 7.0% Actual Flow Rate 37,543 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 24,282 scfm @ 68o F Dry Std Flow Rate 18,160 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 226,260 Purchased Equipment Total (B) 22% of control device cost (A) 274,906

Installation - Standard Costs 85% of purchased equip cost (B) 233,670 Installation - Site Specific Costs NA Installation Total 233,670 Total Direct Capital Cost, DC 508,577 Total Indirect Capital Costs, IC 3 5 % of purchased equip cost (B) 96,217 Total Capital Investment (TCI) = DC + IC 724,544

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 492,449 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 127,409 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 619,859

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 2.9 2.9 - NA Total Particulates 0.7 2.9 2.9 - N A Nitrous Oxides (NOx) 7.9 31.5 70% 9.4 22.0 28,142 Sulfur Dioxide (SO 2 ) 0.1 0.2 0.2 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.5 2.1 2.1 - NA Carbon Monoxide (CO) 8.2 32.4 32.4 - NA Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Sept 2005 Cost Estimate Procedure from BOC Gases
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Wastewater Treatment Costs provided by Nalco 6/8/06 email for reverse osmosis system, evaporator and crystallizer 6 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-4: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 226,260

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 22,626 MN Sales Taxes 6.5% of control device cost (A) 14,707 Freight 5% of control device cost (A) 11,313 Purchased Equipment Total (B) 22% 274,906

Installation

Foundations & supports 12% of purchased equip cost (B) 32,989 Handling & erection 40% of purchased equip cost (B) 109,963 Electrical 1% of purchased equip cost (B) 2,749 Piping 30% of purchased equip cost (B) 82,472 Insulation 1% of purchased equip cost (B) 2,749 Painting 1% of purchased equip cost (B) 2,749 Installation Subtotal Standard Expense s 85% 233,670

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 233,670 Total Direct Capital Cost, DC 508,577

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 27,491 Construction & field expenses 10% of purchased equip cost (B) 27,491 Contractor fees 10% of purchased equip cost (B) 27,491 Start-up 1% of purchased equip cost (B) 2,749 Performance test 1% of purchased equip cost (B) 2,749 Model Studies N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 8,247 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 96,217 Ozone Generator, Installed Cost 119,750 Total Capital Investment (TCI) = DC + IC 724,544

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 724,544

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 133 kW-hr, 7946 hr/yr, 100% utilization 53,603
NA NA - Water 0.78 $/mgal, 19 gpm, 7946 hr/yr, 100% utilization 7,006 Cooling Water 0.27 $/mgal, 36 gpm, 7946 hr/yr, 100% utilization 4,565
NA NA - N A N A - WW Treat R/O 40.10 $/mgal, 19 gpm, 7946 hr/yr, 100% utilization 358,890
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Oxygen 1.44 Mscf, 2 Mscf/hr, 7946 hr/yr, 100% utilization 18,326
NA NA - NA NA - Total Annual Direct Operating Cost s 492,449

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 14,491 Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,245 Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,245 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 68,392 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 127,409

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 619,859

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-4: NOx Control - LoTOx - (Low Temperature Oxidation) Wastewater Treating Costs for LoTOx 5
Capital Recovery Factors 76 gpm, R/O System Design Rate Primary Installation 3,740,000 Installed Capital Cost Interest Rate 7.00% 353,030 Capital Recovery Cost Equipment Life 20 years 1,100,000 Operating & Maintenance Cost CRF 0.0944 1,453,030 A nnual Operating Cost 40.10 Wastewater Treatment Cost $/kgal Replacement Parts & Equipment: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 140 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficienc y Hp kW Blower, Scrubber 37,543 10 0.7 - 62.8 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 375 gpm 1 60 0.7 - 6.0 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 19 gpm 1 60 0.7 - 0.3 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
LTO Electric Use 4.5 kW/lb O 3 64

Total 133.3

Reagent Use & Other Operating Costs Ozone Needed 1.8 lb O3/lb NOx 14.3 lb/hr O3 Oxygen Needed 10% wt O2 to O3 conversion 142.56 lb/hr O2 1,599 scfh O2 LTO Cooling Water 150 gal/lb O3 36 gpm Ozone Generator $350 lb O3/day $119,750 Installed Installed cost factor per BOC. Scrubber Cost 10 $/scfm Gas $226,260 Incremental cost per BOC. Need to increase vessel size over standard absorber. Scrubber Outlet Flow 26,673 acfm Scrubber Outlet Temp 120 °F Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf Circulating Water Rate 375 gpm Waste WaterDisch = 5% of circulating water rate = 19 gpm Evap H2O Loss 0 gpm Water Makeup Rate 19 gpm

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 100.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 133.3 kW-hr 1,058,842 53,603 $/kwh, 133 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 18.8 gpm 8,950 7,006 $/mgal, 19 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 35.6 gpm 16,992 4,565 $/mgal, 36 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization WW Treat R/O 40.10 $/mgal 18.8 gpm 8,950 358,890 $/mgal, 19 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 1.6 Mscf/hr 12,708 18,326 Mscf, 2 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Operating Unit: DRI Package Boiler

Emission Unit Number E U 065 & 082 Stack/Vent Number SV 028 & 065 Design Capacity 99 MMBtu/hr Standardized Flow Rate 22,626 scfm @ 32o F Expected Utilization Rate 100% Temperature 356 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% Annual Interest Rate 7.0% Actual Flow Rate 37,543 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 24,282 scfm @ 68o F Dry Std Flow Rate 18,160 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) N A Purchased Equipment Total (B) 22% of control device cost (A) N A

Installation - Standard Costs 30% of purchased equip cost (B) NA Installation - Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA Total Capital Investment (TCI) = DC + IC 1,676,449

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 221,752 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 227,849 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 449,601

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 2.9 2.9 - NA Total Particulates 0.7 2.9 2.9 - N A Nitrous Oxides (NOx) 7.9 31.5 70% 9.4 22.0 20,412 Sulfur Dioxide (SO 2 ) 0.1 0.2 0.2 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.5 2.1 2.1 - NA Carbon Monoxide (CO) 8.2 32.4 32.4 - NA Lead (Pb) - - 0.0 - N A

Notes & Assumption s

Basis for SCR control cost:
1 The SCR capital investment is from vendor estimates (Babcok Power Inc, 2005).
2 SCR catalyst quote based on information obtained from Cormetech, Inc. It is used for catalyst replacement costs. 3 The total direct and indirect operating costs are based on operation and maintenance costs in the

"Pwr Plt SCR $" tab per EPA correlation of SCR costs for power plants.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) NA

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) N A MN Sales Taxes 6.5% of control device cost (A) N A Freight 5% of control device cost (A) NA Purchased Equipment Total (B) 22% NA

Installation

Foundations & supports 8% of purchased equip cost (B) NA Handling & erection 14% of purchased equip cost (B) NA Electrical 4% of purchased equip cost (B) N A Piping 2% of purchased equip cost (B) NA Insulation 1% of purchased equip cost (B) N A Painting 1% of purchased equip cost (B) N A Installation Subtotal Standard Expense s 30% NA

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) NA Construction & field expenses 5% of purchased equip cost (B) NA Contractor fees 10% of purchased equip cost (B) N A Start-up 2% of purchased equip cost (B) NA Performance test 1% of purchased equip cost (B) NA Model Studies of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC 1,676,449

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 1,633,094

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator NA - Supervisor N A - Maintenance

Maintenance Labor NA - Maintenance Materials 100% of maintenance labor costs - Utilities, Supplies, Replacements & Waste Managemen t

N A N A - NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization 16,521
NA NA - Total Annual Direct Operating Cost s 221,752

Indirect Operating Costs Overhead 60% of total labor and material costs 6,639 Administration (2% total capital costs) 2% of total capital costs (TCI) 33,529 Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,764 Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,764 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 154,152 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 227,849

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 449,601

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalys t Estimate amount of catalyst required Equipment Life 3 years Vol. #1 5000 ft3 CRF 0.3811 Flow #1 359,256 acfm Basis SCR Bids for proposed 2001 Taconite Plant Rep part cost per unit 65 $/ft 3 Flow #2 37,543 acfm Amount Required 522.5 ft 3 Vol #2 522.5 ft3 Catalyst Cost 37,700 Cost adjusted for freight & sales tax Installation Labor 5,655 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 43,355 Zero out if no replacement parts needed A nnualized Cost 16,521

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 37,543 19 0.6 139.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 37,543 23 0.6 168.4 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type Catalyti c (catalytic or thermal) 168.4

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 100.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 0 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 168.4 kW-hr 0 0 $/kwh, 168 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 14676 scfm 0 0 $/mscf, 14,676 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 16,521 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

EPA SCR Cost Worksheet for Coal Fired Power Plants

Determine Comparable Boiler Size Based on Flue Gas Exhaust Rate stack exhaust flow scfm 24,282 Moisture Content 10% Stack exhaust flow dcfm 18,160 Coal F Factor dscf/MMBtu 10,000 Equivalent Duty MMBtu/hr 109 Est. Power Plant Efficiency 35% Watt per Btu/hr 0.29307 Equivalent Power Plant kW 11,176 Uncontrolled NOx t/yr 31 A nnual Operating Hours 8,000
Uncontrolled NOx lb/MMBtu 0.072

Plant Capacity kW A 11,176 Uncontrolled NOx lb/MMBtu B 0.072 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Total Capital Cost $1,676,449

D= 75*(300,000((B/1.5)^0.05*(C/100)^0.04/A)^0.35

Plant Capacity kW A 11,176 Capital Cost $/kW D $150.00 Fixed O&M Cost, $/yr E $11,065

E = D*A*0.0066

Plant Capacity kW A 11,176
Uncontrolled NOx lb/MMBtu B 0.07 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Annual Capacity Factor G 0.82 Heat Input MMBtu/hr H 6000 Variable O&M Cost $/yr F $221,752

F = G*(225(0.37*B*H*C/100*8760/2000)*1.005+0.075*D*A*((B/1.5)^0.05*(c/100)^.4)+1.45*A) Note: used worst case factor for catalyst replacement Note: Capital Cost kW is estimate from Tom Robinson @ Babcock Power Inc.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-6: Selective Non-Catalytic Reduction SNCR

Operating Unit: DRI Package Boiler

Emission Unit Number E U 065 & 082 Stack/Vent Number SV 028 & 065 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 22,626 scfm @ 32o F Chemical Plant Cost Inde x Expected Utilization Rate 100% Temperature 356 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 37,543 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 24,282 scfm @ 68o F Dry Std Flow Rate 18,160 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year Direct Capital Costs EPRI Correlation, 1998 $'s 99 25% 0.08 1998 513,335 Purchased Equipment (A) 2005 612,053 Purchased Equipment Total (B) 0% of control device cost (A) 612,053

Installation - Standard Costs 15% of purchased equip cost (B) 110,170 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC 861,742

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 135,834 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 81,342 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 217,176

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 2.9 2.9 - NA Total Particulates 0.7 2.9 2.9 - N A Nitrous Oxides (NOx) 7.9 31.5 25% 23.6 7.9 27,608 Sulfur Dioxide (SO 2 ) 0.1 0.2 0.2 - NA
Sulfuric Acid Mist - - 0.0 - NA
Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.5 2.1 2.1 - NA Carbon Monoxide (CO) 8.2 32.4 32.4 - NA Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Cost Estimate from EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 and adjusted for inflation 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 5 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25 6 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29
7 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 8 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
9 No coal ash disposal cost; fuel is natural gas

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-6: Selective Non-Catalytic Reduction SNCR

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 612,053 Instrumentation 10% of control device cost (A) N A MN Sales Taxes 6.5% of control device cost (A) N A Freight 5% of control device cost (A) NA Purchased Equipment Total (A ) 612,053

Indirect Installation

General Facilities 5% of purchased equip cost (A) 30,603 Engineering & Home Office 10% of purchased equip cost (A) 61,205 Process Contingency 5% of purchased equip cost (A) 30,603

Total Indirect Installation Costs (B ) 20% of purchased equip cost (A) 122,411

Project Contingency ( C ) 15% of (A + B) 110,170

Total Plant Cost D A + B + C 844,633

Allowance for Funds During Construction (E ) 0 for SNCR 0

Royalty Allowance (F ) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 16,893

Inventor y Ca p ital Reagent Vol * $/gal 216

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 861,742

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 861,742

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labo r

Operator N A - Supervisor NA - Maintenanc e

Maintenance Total 15.00 % of Total Capital Investment 129,261 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 0 kW-hr, 7946 hr/yr, 100% utilization 74 Natural Gas 6.85 $/mscf, 0 scfh, 7946 hr/yr, 100% utilization 1,374 Water 0.78 $/mgal, 2 gph, 7946 hr/yr, 100% utilization 9
NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Urea 405.00 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization 5,115
NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 135,834

Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 81,342 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 81,342

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 217,176

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-6: Selective Non-Catalytic Reduction SNCR

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalys t <- Enter Equipment Name to Get Cost Equipment Life 5 years CRF 0.2439 Rep part cost per unit 140 $/ft 3 Amount Required 12 ft 3 Packing Cost 1,873 Cost adjusted for freight & sales tax Installation Labor 281 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost Equipment Life 2 years CRF 0.0000 Rep part cost per unit 37 $/ft 3 Amount Required 0 Cages Total Rep Parts Cost 0 Cost adjusted for freight & sales tax See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr) Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag. A nnualized Cost 0

Electrical Use NOx in 0.08 lb/MMBtu kW NS R 0.47
Power 0.2

Total 0.2

Reagent Use & Other Operating Costs Urea Use
NOx in 0.08 lb/MMBtu 2 lb/hr Neat Efficiency 25% 50% solution 71.0 lb/ft 3 Density 50% Solution Duty 99 MMBtu/hr 3 lb/hr 0.3 gal/hr Volume 14 day inventory 113 gal $216 Inventory Cost

Water Use 2 gal/hr Inject at 10% solution

Fuel Use 0.0 MMBtu/hr 0.0 mscfh natural gas

A sh Generation 0.2 lb/hr

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 100.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenanc e Maintenance Total 15 % of Total Capital Investment 129,261 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 0.2 kW-hr 1,455 74 $/kwh, 0 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0.0 scfh 201 1,374 $/mscf, 0 scfh, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 1.5 gph 12 9 $/mgal, 2 gph, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 0.0 scfm/kacfm* * 0 0 $/mscf, 0 scfm/kacfm**, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Urea 405 $/ton 0.0016 ton/hr 13 5,115 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-7: CO/VOC Control - Thermal Oxidizer

Operating Unit: DRI Package Boiler

Emission Unit Number E U 065 & 082 Stack/Vent Number SV 028 & 065 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 22,626 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 356 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 37,543 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 24,282 scfm @ 68o F Dry Std Flow Rate 18,160 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 318,276 Purchased Equipment Total (B) 22% of control device cost (A) 386,706

Installation - Standard Costs 30% of purchased equip cost (B) 116,012 Installation - Site Specific Costs NA
Installation Total 116,012 Total Direct Capital Cost, DC 502,718 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 119,879 Total Capital Investment (TCI) = DC + IC 622,596

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 737,858 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 113,708 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 851,566

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 2.9 2.9 - NA Total Particulates 0.7 2.9 2.9 - N A Nitrous Oxides (NOx) 7.9 31.5 31.5 - NA Sulfur Dioxide (SO 2 ) 0.1 0.2 0.2 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.5 2.1 90% 0.2 1.9 446,128 Carbon Monoxide (CO) 8.2 32.4 90% 3.2 29.2 29,194 Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Cost Estimate per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 and adjusted for inflation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-7: CO/VOC Control - Thermal Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 318,276

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 31,828 MN Sales Taxes 6.5% of control device cost (A) 20,688 Freight 5% of control device cost (A) 15,914 Purchased Equipment Total (B) 22% 386,706

Installation

Foundations & supports 8% of purchased equip cost (B) 30,936 Handling & erection 14% of purchased equip cost (B) 54,139 Electrical 4% of purchased equip cost (B) 15,468 Piping 2% of purchased equip cost (B) 7,734 Insulation 1% of purchased equip cost (B) 3,867 Painting 1% of purchased equip cost (B) 3,867 Installation Subtotal Standard Expenses 30% 116,012

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 116,012 Total Direct Capital Cost, DC 502,718

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 38,671 Construction & field expenses 5% of purchased equip cost (B) 19,335 Contractor fees 10% of purchased equip cost (B) 38,671 Start-up 2% of purchased equip cost (B) 7,734 Performance test 1% of purchased equip cost (B) 3,867 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 11,601 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 119,879

Total Capital Investment (TCI) = DC + IC 622,596

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 622,596

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 139 kW-hr, 7946 hr/yr, 100% utilization 55,954 Natural Gas 6.85 $/mscf, 193 scfm, 7946 hr/yr, 100% utilization 631,844
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 737,858

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 12,452 Property tax (1% total capital costs) 1% of total capital costs (TCI) 6,226 Insurance (1% total capital costs) 1% of total capital costs (TCI) 6,226 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 58,769 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 113,708

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 851,566

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-7: CO/VOC Control - Thermal Oxidizer

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years
CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 650 $/ft 3 Amount Required 39 ft 3
Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 37,543 19 0.6 139.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 37,543 23 0.6 168.4 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 139.1

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 100.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 139.1 kW-hr 1,105,267 55,954 $/kwh, 139 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 193 scfm 92,240 631,844 $/mscf, 193 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment C - Emission Control Cost Analysis Table C-7: CO/VOC Control - Thermal Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 356 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 947 Deg F - Temperature of waste gas out of heat recovery

T fo 609 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.2550 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 24,282 scfm - Flow of waste gas

Q af 193 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 24,475 scfm Flue Gas Cost in 1989 $'s $266,941 Current Cost Using CHE Plant Cost Index $318,276
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerator s (EPA 453/B-96-001)

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Operating Unit: DRI Package Boiler

Emission Unit Number E U 065 & 082 Stack/Vent Number SV 028 & 065 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 22,626 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 356 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 37,543 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 24,282 scfm @ 68o F Dry Std Flow Rate 18,160 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 390,706 Purchased Equipment Total (B) 22% of control device cost (A) 474,707

Installation - Standard Costs 30% of purchased equip cost (B) 142,412 Installation - Site Specific Costs NA
Installation Total 142,412 Total Direct Capital Cost, DC 617,120 Total Indirect Capital Costs, IC 31% of purchased equip cost (B ) 147,159 Total Capital Investment (TCI) = DC + IC 764,279

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 355,817 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 123,933 Total Annual Cost (Annualized Capital Cost + Operating Cost) 479,750

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 2.9 2.9 - NA Total Particulates 0.7 2.9 2.9 - N A Nitrous Oxides (NOx) 7.9 31.5 31.5 - NA Sulfur Dioxide (SO 2 ) 0.1 0.2 0.2 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides 0.0E+00 0.0E+00 0.0E+00 - NA Volatile Organic Compounds (VOC) 0.5 2.1 90% 2.1E-01 1.9 251,337 Carbon Monoxide (CO) 8.2 32.4 90% 3.2 29.2 16,447 Lead (Pb) - - 0.0 - N A

Notes & Assumptions 1 A ug 28, 2005 Catalyst Cost Estimate from Englehard Catalyst & EPA Control Cost Manual Section 3.2 Chapter 2 and adjusted for in flation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 390,706

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 39,071 MN Sales Taxes 6.5% of control device cost (A) 25,396 Freight 5% of control device cost (A) 19,535 Purchased Equipment Total (B) 22% 474,707

Installation

Foundations & supports 8% of purchased equip cost (B) 37,977 Handling & erection 14% of purchased equip cost (B) 66,459 Electrical 4% of purchased equip cost (B) 18,988
Piping 2% of purchased equip cost (B) 9,494 Insulation 1% of purchased equip cost (B) 4,747 Painting 1% of purchased equip cost (B) 4,747 Installation Subtotal Standard Expenses 30% 142,412

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 142,412 Total Direct Capital Cost, DC 617,120

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,471 Construction & field expense s 5% of purchased equip cost (B) 23,735 Contractor fees 10% of purchased equip cost (B ) 47,471 Start-up 2% of purchased equip cost (B) 9,494 Performance test 1% of purchased equip cost (B) 4,747 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 14,241 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 147,159

Total Capital Investment (TCI) = DC + IC 764,279

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 670,87 4

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Cost s 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 168 kW-hr, 7946 hr/yr, 100% utilization 67,733 Natural Gas 6.85 $/mscf, 66 scfm, 7946 hr/yr, 100% utilization 215,244
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization 22,781
NA NA - Total Annual Direct Operating Costs 355,817

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 15,286 Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,643 Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,643 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 63,326 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 123,93 3

Total Annual Cost (Annualized Capital Cost + Operating Cost) 479,750

See Summary page for notes and assumptions

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Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years
CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 5 year s CRF 0.2439
Rep part cost per unit 3000 $/ft 3
Amount Required 24 ft 3
Catalyst Cost 81,222 Cost adjusted for freight & sales tax Installation Labor 12,183 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 93,405 Zero out if no replacement parts needed
Annualized Cost 22,781

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts needed
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 37,543 19 0.6 139.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 37,543 23 0.6 168.4 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type catalyti c (catalytic or thermal) 168.4

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0 %

Unit Unit of Use Unit of Annual A nnual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 168.4 kW-hr 1,337,955 67,733 $/kwh, 168 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 66 scfm 31,422 215,244 $/mscf, 66 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.30998 4 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 22,781 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 356 Deg F - Temperature of waste gas into heat recovery
T fi 600 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 527 Deg F - Temperature of waste gas out of heat recovery

T fo 429 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.2550 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 24,282 scfm - Flow of waste gas

Q af 66 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculation s 24,348 scfm Flue Gas Cost in 1989 $' s $266,59 3 Current Cost Using CHE Plant Cost Inde x $317,861
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.2 4 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.2 7

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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Operating Unit: DRI Package Boiler

Emission Unit Number EU 065 & 082 Stack/Vent Number SV 028 & 065 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 22,626 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 356 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 37,543 acfm Inflation Adj NA Expected Equipment Lif e 20 yr s Standardized Flow Rat e 24,282 scfm @ 68o F Dry Std Flow Rate 18,160 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment ( A ) 3 409,982 Purchased Equipment Total (B) 22% of control device cost (A) 498,128

Installation - Standard Costs 30% of purchased equip cost (B) 149,439 Installation - Site Specific Costs NA
Installation Total 149,439 Total Direct Capital Cost, DC 647,567 Total Indirect Capital Costs, IC 31% of purchased equip cost (B ) 154,420 Total Capital Investment (TCI) = DC + I C 801,987

Operating Cost s Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 457,831 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 137,817 Total Annual Cost (Annualized Capital Cost + Operating Cos t 595,648

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/Hr T/Y r % Conc. Unit s T/yr T/yr $/Ton Rem

PM10 0.7 2.9 2.9 - NA Total Particulate s 0.7 2.9 2.9 - NA Nitrous Oxides (NOx) 7.9 31.5 31.5 - NA Sulfur Dioxide (SO 2 ) 0.1 0.2 0.2 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.5 2.1 90% 0.2 1.9 312,055 Carbon Monoxide (CO) 8.2 32.4 90% 3.2 29.2 20,420 Lead (Pb )

- - 0.0 - NA

Notes & Assumption s 1 Cost Estimate per L & E America (TANN Corp), Aug 1, 2006 emai
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Cost Estimate per Tann Corporation, July 2006
4 Used 0.6 power law factor to adjust price from bid basis of 100,000 scfm

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CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 409,982

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 40,998 MN Sales Taxes 6.5% of control device cost (A) 26,649 Freight 5% of control device cost (A) 20,499 Purchased Equipment Total (B ) 22% 498,128

Installation

Foundations & supports 8% of purchased equip cost (B) 39,850 Handling & erection 14% of purchased equip cost (B) 69,738 Electrical 4% of purchased equip cost (B) 19,925
Piping 2% of purchased equip cost (B) 9,963 Insulation 1% of purchased equip cost (B) 4,981 Painting 1% of purchased equip cost (B) 4,981 Installation Subtotal Standard Expenses 30% 149,439

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Tota l 149,439 Total Direct Capital Cost, DC 647,567

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 49,813 Construction & field expense s 5% of purchased equip cost (B) 24,906 Contractor fee s 10% of purchased equip cost (B ) 49,813 Start-up 2% of purchased equip cost (B) 9,963 Performance tes t 1% of purchased equip cost (B) 4,981 Model Studie s of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 14,944 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 154,420

Total Capital Investment (TCI) = DC + I C 801,987

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Co s 801,987

OPERATING COSTS

Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Superviso r 15% 15% of Operator Cost s 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 168 kW-hr, 7946 hr/yr, 100% utilizatio n 67,733 Natural Gas 6.85 $/mscf, 104 scfm, 7946 hr/yr, 100% utilization 340,038
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 457,831

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 16,040 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,020 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,020 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 75,702 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery co s 137,817

Total Annual Cost (Annualized Capital Cost + Operating Cos t 595,648

See Summary page for notes and assumption s

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Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years
CRF 0.0944

Replacement Catalyst : Catalys t Equipment Lif e 2 year s CRF 0.0000
Rep part cost per unit 650 $/ft 3
Amount Required 0 ft 3
Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h OAQPS list replacement times from 5 - 20 min per bag Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Therma l 37,543 19 0.6 139.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2. Blower, Catalytic 37,543 23 0.6 168.4 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Typ e catalyti c (catalytic or thermal ) 168.4

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation 7,946 Utilization Rate: 100.0 %

Unit Unit o f Use Unit o f Annua l A nnua l Comments Item Cost $ Measur e Rate Measur e Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 168.4 kW-hr 1,337,955 67,733 $/kwh, 168 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 104 scfm 49,641 340,038 $/mscf, 104 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilizatio n Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.30998 4 $/ton 0.0 lb/h r 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilizatio n Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilizatio n Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost fact o See Summary page for notes and assumption s

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Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 90% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 356 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 1,116 Deg F - Temperature of waste gas out of heat recovery

T fo 440 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 24,282 scfm - Flow of waste gas

Q af 104 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculation s 24,282 scfm Flue Ga s

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerato r (EPA 453/B-96-001 )

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# Attachment D

DRI Process Heater BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment D - Emission Control Cost AnalysisTable D-1: Cost Summary - DRI Process HeatersPM/PM10 Control Cost Summary *Control TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber0.01gr/dscf17.4 17.4 $1,551,775 $777,333 $44,695 $44,695 None High Waste-WaterBaghouse0.01gr/dscf17.4 17.4 $6,913,747 $1,393,567 $80,128 $80,128 None Low Solid WasteUncontrolled0.02gr/dscf34.8* Based on highest emission rate if PM not equal to PM10NOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?LoTOx70%57.8 134.8 $3,946,254 $1,807,751 $13,415 NANone Medium Waste-WaterSelective Catalytic Reduction(SCR)70% 57.8 134.8 $9,445,459 $1,946,130 $14,442 $45,385 NH3 Slip Low Catalyst WasteUltra-Low NOx Burners50%96.3 96.3 $883,202 $198,792 $2,065 NANone Low NoneSelective Non-CatalyticReduction (SNCR)25% 144.4 48.1 $1,854,845 $493,536 $10,255NA InferiorControlNH3 Slip Low NoneBase CaseNA192.5P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach D - HYL DRI Heater Sept 2006 RevisionCost Summary3/6/2007 Page 1 of 34Minnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment D - Emission Control Cost AnalysisTable D-1: Cost Summary - DRI Process HeatersCO Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Thermal OxidizerRecuperative90% 19.8 178.5 $945,280 $3,892,175 $21,811 NA None High NoneThermal OxidizerRegenerative90% 19.8 178.5 $2,184,749 $2,555,426 $14,320 NA None High Solid WasteCatalytic Oxidizer90%19.8 178.5 $1,701,213 $1,917,871 $10,747 NANone Medium Catalyst WasteUncontrolled0%198.3VOC Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Thermal OxidizerRecuperative90% 1.30 11.7 $945,280 $3,892,175 $333,309 NA None High NoneThermal OxidizerRegenerative90% 1.30 11.7 $2,184,749 $2,555,426 $218,835 NA None High Solid WasteCatalytic Oxidizer90%1.30 11.7 $1,701,213 $1,917,871 $164,238 NANone Low Catalyst WasteUncontrolled0%13.0Fluoride Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber95%8.7E-05 1.7E-03 $1,551,775 $777,333 $470,077,600 NANone High Waste-WaterBaghouse95%8.7E-05 1.7E-03 $6,913,747 $1,393,567 $842,733,202 NANone Low Solid WasteUncontrolled0%1.7E-03Lead Control Cost SummaryControl TechnologyControlEff %UncontrolledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber95%6.2E-05 1.2E-03 $1,551,775 $777,333 $655,036,285 NANone High Waste-waterBaghouse95%6.2E-05 1.2E-03 $6,913,747 $1,393,567 $1,174,318,507 NANone Low Solid WasteUncontrolled0%1.2E-03The 100% control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual control efficiencies.P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach D - HYL DRI Heater Sept 2006 RevisionCost Summary3/6/2007 Page 2 of 34

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: DRI Process Heater Study Year 2006 Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Reference Item Unit Cos t Units Cos t Y ear Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.052 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.81 $/mgal 0.76 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation

Cooling Water 0.28 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.32 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.69 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.28 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 28.14 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3% inflation

Hazardous Waste Disposal 281.38 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3% inflation

Waste Transport 0.56 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycle 1.19 $/ton 1.00 2000 Corus Study for MN Iron and Steel Project Study use $1/ton to cover cost of materials movement

Chemicals & Supplie s Lime 26.07 $/ton 24.57 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation Caustic 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.49 Mscf 1.40 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation EPA Urea 179.1 $/ton A mmonia 0.101 $/lb Reagent #8 $/ton

Catalyst & Replacement Parts SCR Catalyst 140 $/ft 3 Cormetech, Inc., 1/2006 bid CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 Catalyst #4 Catalyst #5

Filter Bags 37.94 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Other Sales Tax 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Informatio n A nnual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 100% 2004 Kaar Consulting MSI Cost Model Equipment Life 20 yrs Engineering Estimate Design Capacity 605.7 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Temperature 347 Deg F Moisture Content 20.7% Actual Flow Rate 197,289 acfm Standardized Flow Rate 129,023 scfm @ 68o F 204,258 Dry Std Flow Rate 102,315 dscfm @ 68o F

Max Emis Uncontrolled Conc from Reformer Pollutan t Lb/H r prior to eductor PM10 8.76 0.010 gr/dscf Total Particulates 8.76 0.010 gr/dscf NOx Control Efficiency Calculation s Nitrous Oxides (NOx) 48.5 52 ppmw 24.23 lb/hr NOx at 0.040 lb NOx/MMBtu Sulfur Dioxide (SO 2 ) 0.76 1 ppmw 48.45 lb/hr NOx at 0.08 lb NOx/MMBtu Sulfuric Acid Mist 3.13E-04 0.000 ppmw 50.0% Control efficiency for LNB/FGR or UNLB @0.040 lb NOx/MMBtu Fluorides 4.38E-04 5.0E-07 gr/dscf 70.0% SCR & LoTOX control efficiency Volatile Organic Compounds (VOC) 3.27 10.1 ppmw 20 ppm NOx dry at SCR/LoTOx control efficiency Carbon Monoxide (CO) 49.91 89 ppmw 25.0% SNCR control efficiency Lead (Pb) 3.14E-04 3.6E-07 gr/dscf 50 ppm NOx dry at SNCR control efficiency 33 ULNB ppm NOx dry Enter this data for each emission uni t 66 Base Case ppm NOx dry Enter data for this study (applies to all units ) 192.5 T/yr NOx Base Case 90.0% Oxidizer 9 ppm CO dry at oxidizer control efficiency

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-3: PM Control - Wet Scrubber

Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Expected Utilization Rate 100% Temperature 347 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 20.7% A nnual Interest Rate 7.0% A ctual Flow Rate 197,289 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 129,023 scfm @ 68o F Dry Std Flow Rate 102,315 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 668,681 Purchased Equipment Total (B) 22% of control device cost (A) 812,448

Installation - Standard Costs 56% of purchased equip cost (B) 454,971 Installation - Site Specific Costs NA Installation Total 454,971 Total Direct Capital Cost, DC 1,267,419 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 284,357 Total Capital Investment (TCI) = DC + IC 1,551,775

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 486,783 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 290,550 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 777,333

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 8.8 34.8 0.005 gr/dscf 17.4 17.4 44,695 Total Particulates 8.8 34.8 0.005 gr/dscf 17.4 17.4 44,695 Nitrous Oxides (NOx) 48.5 192.5 192.5 - NA Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA
Sulfuric Acid Mist 0.0 0.0 0.0 - NA Fluorides 4.4E-04 1.7E-03 95% 8.7E-05 1.7E-03 470,077,600 Volatile Organic Compounds (VOC) 3.3 13.0 13.0 - NA Carbon Monoxide (CO) 49.9 198.3 198.3 - NA Lead (Pb) 0.0003 0.0012 95% 0.0001 0.0012 655,036,285

Notes & Assumption s 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 2
2 Scrubber Cost per Barr Engineering 2004 Scrubber Project. Adjusted prices per Chemical Engineering Magazine CPI Index 2004 = 44 4, 2005 =465
3 Used 0.6 power law factor to adjust price to calculated acfm from bid basis of 500,000 acfm 4 The 100% control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actu al control efficiencies. 5 Scrubber/WESP evaporative water loss per adiabatic energy balance; H2O heat of vaporization = sensible heat loss in stack gas.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-3: PM Control - Wet Scrubber

CAPITAL COSTS Direct Capital Cost s

Purchased Equipment (A) (1 ) 668,681

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 66,868 MN Sales Taxes 6.5% of control device cost (A) 43,464 Freight 5% of control device cost (A) 33,434 Purchased Equipment Total (B) 22% 812,448

Installation

Foundations & supports 6% of purchased equip cost (B) 48,747 Handling & erection 40% of purchased equip cost (B) 324,979 Electrical 1% of purchased equip cost (B) 8,124 Piping 5% of purchased equip cost (B) 40,622 Insulation 3% of purchased equip cost (B) 24,373 Painting 1% of purchased equip cost (B) 8,124 Installation Subtotal Standard Expense s 56% 454,971

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 454,971 Total Direct Capital Cost, DC 1,267,419

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 81,245 Construction & field expenses 10% of purchased equip cost (B) 81,245 Contractor fees 10% of purchased equip cost (B) 81,245 Start-up 1% of purchased equip cost (B) 8,124 Performance test 1% of purchased equip cost (B) 8,124 Model Studies N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 24,373 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 284,357

Total Capital Investment (TCI) = DC + IC 1,551,775

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,551,775

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535 Maintenanc e

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100.00 % of Maintenance Labor 31,784 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 613 kW-hr, 7946 hr/yr, 100% utilization 253,898
NA NA - Water 0.81 $/mgal, 172 gpm, 7946 hr/yr, 100% utilization 66,219
NA NA - NA NA - WW Treat Neutralization 1.69 $/mgal, 37 gpm, 7946 hr/yr, 100% utilization 29,995
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 486,783

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 31,036 Property tax (1% total capital costs) 1% of total capital costs (TCI) 15,518 Insurance (1% total capital costs) 1% of total capital costs (TCI) 15,518 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 146,477 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 290,550

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 777,333

See summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-3: PM Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 140 $/ft 3 Amount Required 0 ft 3
Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.940902 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 197,289 15 0.6 776.0 578.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.40
L/G ratio* Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 10 1.125 40 0.5 44.9 33.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41 H2O WW Disch Pump 37 gpm 1.125 40 0.5 0.8 0.6 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41
Other Other
Other Total 612.8 * L/G = Gal/1,000 acf

Reagent Use & Other Operating Cost s Caustic Use 0.76 lb/hr SO2 2.50 lb NaOH/lb SO2 1.90 lb/hr Caustic Lime Use 0.76 lb/hr SO2 1.53 lb Lime/lb SO2 1.17 lb/hr Lime Circulating Water Rate 1,491 gpm Water Makeup Rate/WW Disch = 2.5% of circulating water rate = 37 gpm

Scrubber Outlet Flow 149,061 acfm Scrubber Outlet Temp 150 °F Evap H2O Loss 135 gpm Water Makeup Rate 172 gpm

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 100.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 612.8 kW-hr 4,869,235 253,898 $/kwh, 613 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 172.3 gpm 82,129 66,219 $/mgal, 172 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 37.3 gpm 17,767 29,995 $/mgal, 37 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.0692835 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Urea 405 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-4: PM Control -Baghouse

Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Expected Utilization Rate 100% Temperature 347 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 20.7% Annual Interest Rate 7.0% Actual Flow Rate 197,289 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 129,023 scfm @ 68o F Dry Std Flow Rate 102,315 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 2,598,323 Purchased Equipment Total (B) 22% of control device cost (A) 3,156,962

Installation - Standard Costs 74% of purchased equip cost (B) 2,336,152 Installation - Site Specific Costs NA Installation Total 2,336,152 Total Direct Capital Cost, DC 5,493,114 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 1,420,633 Total Capital Investment (TCI) = DC + IC 6,913,747

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 406,501 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 987,066 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,393,567

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 8.8 34.8 0.005 gr/dscf 17.4 17.4 80,128 Total Particulates 8.8 34.8 0.005 gr/dscf 17.4 17.4 80,128 Nitrous Oxides (NOx) 48.5 192.5 192.5 - NA Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA

Sulfuric Acid Mist 0.0 0.0 0.0 - NA Fluorides 4.4E-04 1.7E-03 95% 8.7E-05 1.7E-03 842,733,202 Volatile Organic Compounds (VOC) 3.3 13.0 13.0 - NA Carbon Monoxide (CO) 49.9 198.3 198.3 - NA Lead (Pb) 0.0003 0.0 95% 0.0001 0.0012 1,174,318,507

Notes & Assumptions
1 Sept 2, 2005 Cost Estimate Enviromental Elements
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1
3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapt er 1.5.1.8
4 Bag replacement at 10 min/bag EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min pe r bag. 5 Used 0.6 power law factor to adjust price to calculated dscfm from bid basis of 210,000 dscfm 6 $250,000 bag replacement cost from vendor adjusted for flow rate as noted above
7 The 100% control efficiencies for fluorides and lead are for example calculations and do not represent actual control efficienc ies

.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-4: PM Control -Baghouse

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 2,598,323

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 259,832 MN Sales Taxes 6.5% of control device cost (A) 168,891 Freight 5% of control device cost (A) 129,916 Purchased Equipment Total (B) 22% 3,156,962

Installation

Foundations & supports 4% of purchased equip cost (B) 126,278 Handling & erection 50% of purchased equip cost (B) 1,578,481 Electrical 8% of purchased equip cost (B) 252,557 Piping 1% of purchased equip cost (B) 31,570 Insulation 7% of purchased equip cost (B) 220,987 Painting 4% of purchased equip cost (B) 126,278 Installation Subtotal Standard Expenses 74% 2,336,152

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 2,336,152 Total Direct Capital Cost, DC 5,493,11 4

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 315,696 Construction & field expenses 20% of purchased equip cost (B) 631,392 Contractor fees 10% of purchased equip cost (B) 315,696 Start-up 1% of purchased equip cost (B) 31,570 Performance test 1% of purchased equip cost (B) 31,570 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 94,709 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 1,420,633

Total Capital Investment (TCI) = DC + IC 6,913,747

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 6,658,476

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535
Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100% of maintenance labor costs 31,784 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 357 kW-hr, 7946 hr/yr, 100% utilization 147,954
NA NA - NA NA - NA NA - Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 100% utilization 59,576 N A N A - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.19 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization 42
NA NA - NA NA - NA NA - NA NA - Filter Bags 33.71 $/bag, 795 bags, 7946 hr/yr, 100% utilization 62,258 Total Annual Direct Operating Costs 406,501

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 138,275 Property tax (1% total capital costs) 1% of total capital costs (TCI) 69,137 Insurance (1% total capital costs) 1% of total capital costs (TCI) 69,137 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 628,513 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 987,066

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,393,567

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-4: PM Control -Baghouse

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 140 $/ft 3
Amount Required 0 ft 3 Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages Equipment Life 5 years CRF 0.2439 Rep part cost per unit 33.711 $/bag Amount Required 795 Total Rep Parts Cost 248,148 Cost adjusted for freight & sales tax Installation Labo r 7,123 10 min per bag, Labor + Overhead (68% = $29.65/hr ) EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1. 4 Total Installed Cos t 255,271 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag

. Annualized Cost 62,258

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Baghouse 197,289 10 357.1 Baghouse Shaker 0.0 Gross fabric area ft 2 0 EPA Cont Cost Manual 6th ed Section 6 Chapter 1 Eq 1.14 Other Other Other
Other
Other Total 357.1

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Gross BH Filter Area 10,661 ft 2

Cages 10 ft long 5 in dia 13.42 area/cage ft 2 795 Cages 11.036 $/cage Bags 1.69 $/ft2 of fabric 22.68 $/bag
Total 33.711

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 357.1 kW-hr 2,837,461 147,954 $/kwh, 357 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 2 scfm/kacfm 188,119 59,576 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 35 42 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.0692835 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalyst 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 33.71 $/bag 795 bags NA 62,258 $/bag, 795 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Chemical Engineering Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 347 Deg F 1998/199 9 390 Expected Annual Hours of Operation 7,946 Hour s Moisture Conten t 20.7% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 197,289 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 129,023 scfm @ 68o F Dry Std Flow Rate 102,31 5 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 451,500 Purchased Equipment Total (B) 22% of control device cost (A) 548,57 3

Installation - Standard Costs 30% of purchased equip cost (B) 164,572 Installation - Site Specific Costs NA Installation Total 164,572 Total Direct Capital Cost, DC 713,144 Total Indirect Capital Costs, IC 31% of purchased equip cost (B ) 170,057 Total Capital Investment (TCI) = DC + IC 883,202

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 50,060 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 148,732 Total Annual Cost (Annualized Capital Cost + Operating Cost) 198,792

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 8.8 34.8 34.8 - NA Total Particulates 8.8 34.8 34.8 - N A Nitrous Oxides (NOx) 48.5 192.5 50% 96.3 96.3 2,065 Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA
Sulfuric Acid Mist 0.0 0.0 0.0 - NA Fluorides 0.0 0.0 0.0 - NA Volatile Organic Compounds (VOC) 3.3 13.0 13.0 - NA Carbon Monoxide (CO) 49.9 198.3 198.3 - NA Lead (Pb) 0.0003 0.0 0.0 - N A

Notes & Assumptions 1 Cost Estimate per John Zink burner company email dated 08/03/200 6
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 451,500

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 45,150 MN Sales Taxes 6.5% of control device cost (A) 29,348 Freight 5% of control device cost (A) 22,575 Purchased Equipment Total (B) 22% 548,57 3

Installation

Foundations & supports 8% of purchased equip cost (B) 43,886 Handling & erection 14% of purchased equip cost (B) 76,800 Electrical 4% of purchased equip cost (B ) 21,943 Piping 2% of purchased equip cost (B) 10,971 Insulation 1% of purchased equip cost (B ) 5,486 Painting 1% of purchased equip cost (B ) 5,486 Installation Subtotal Standard Expenses 30% 164,572

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 164,572 Total Direct Capital Cost, DC 713,14 4

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 54,857 Construction & field expense s 5% of purchased equip cost (B) 27,429 Contractor fees 10% of purchased equip cost (B ) 54,857 Start-up 2% of purchased equip cost (B) 10,971 Performance test 1% of purchased equip cost (B) 5,486 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,457 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 170,057

Total Capital Investment (TCI) = DC + IC 883,202

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 883,202

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Cost s 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

N A N A - NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 50,060

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,664 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,832 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,832 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 83,368 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 148,732

Total Annual Cost (Annualized Capital Cost + Operating Cost) 198,792

See Summary page for notes and assumptions

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Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 2 year s CRF 0.5531 Rep part cost per unit 650 $/ft 3
Amount Required 39 ft 3 Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labo r 4,240 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement )
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cos t 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts needed
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 0 19 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 0.0

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculations A nnual hours of operation: 7,946 Utilization Rate: 100.0 %

Unit Unit of Use Unit of A nnual A nnual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.069283 5 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-6: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Expected Utilization Rate 100% Temperature 140 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 20.7% Annual Interest Rate 7.0% Actual Flow Rate 146,664 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 129,023 scfm @ 68o F Dry Std Flow Rate 102,315 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,202,262 Purchased Equipment Total (B) 22% of control device cost (A) 1,460,748

Installation - Standard Costs 85% of purchased equip cost (B) 1,241,636 Installation - Site Specific Costs NA Installation Total 1,241,636 Total Direct Capital Cost, DC 2,702,384 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 511,262 Total Capital Investment (TCI) = DC + IC 3,946,25 4

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247,367 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 560,384 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,807,751

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 8.8 34.8 34.8 - NA Total Particulates 8.8 34.8 34.8 - NA Nitrous Oxides (NOx) 48.5 192.5 70% 57.8 134.8 13,415 Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA
Sulfuric Acid Mist 0.0 0.0 0.0 - NA Fluorides 0.0 0.0 0.0 - NA Volatile Organic Compounds (VOC) 3.3 13.0 13.0 - NA Carbon Monoxide (CO) 49.9 198.3 198.3 - NA Lead (Pb) 0.0003 0.0 0.0 - NA

Notes & Assumptions
1 Sept 2005 Cost Estimate Procedure from BOC Gases

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Wastewater Treatment Costs provided by Nalco 6/8/06 email for reverse osmosis system, evaporator and crystallizer 6 Scrubber/WESP evaporative water loss per adiabatic energy balance; H2O heat of vaporization = sensible heat loss in stack gas.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-6: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 1,202,262

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 120,226 MN Sales Taxes 6.5% of control device cost (A) 78,147 Freight 5% of control device cost (A) 60,113 Purchased Equipment Total (B) 22% 1,460,748

Installation

Foundations & supports 12% of purchased equip cost (B) 175,290 Handling & erection 40% of purchased equip cost (B) 584,299 Electrical 1% of purchased equip cost (B) 14,607 Piping 30% of purchased equip cost (B) 438,225 Insulation 1% of purchased equip cost (B) 14,607 Painting 1% of purchased equip cost (B) 14,607 Installation Subtotal Standard Expenses 85% 1,241,636

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 1,241,636 Total Direct Capital Cost, DC 2,702,38 4

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 146,075 Construction & field expenses 10% of purchased equip cost (B) 146,075 Contractor fees 10% of purchased equip cost (B) 146,075 Start-up 1% of purchased equip cost (B) 14,607 Performance test 1% of purchased equip cost (B) 14,607 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 43,822 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 511,262 Ozone Generator, Installed Cost 732,607 Total Capital Investment (TCI) = DC + IC 3,946,25 4

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 3,946,25 4

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 662 kW-hr, 7946 hr/yr, 100% utilization 274,380
NA NA - Water 0.81 $/mgal, 172 gpm, 7946 hr/yr, 100% utilization 66,219 Cooling Water 0.28 $/mgal, 218 gpm, 7946 hr/yr, 100% utilization 28,766
NA NA - NA NA - WW Treat R/O 40.10 $/mgal, 37 gpm, 7946 hr/yr, 100% utilization 712,467
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Oxygen 1.49 Mscf, 10 Mscf/hr, 7946 hr/yr, 100% utilization 115,475
NA NA - NA NA - Total Annual Direct Operating Costs 1,247,367

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 78,925 Property tax (1% total capital costs) 1% of total capital costs (TCI) 39,463 Insurance (1% total capital costs) 1% of total capital costs (TCI) 39,463 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 372,498 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 560,384

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,807,751

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-6: NOx Control - LoTOx - (Low Temperature Oxidation) Wastewater Treating Costs for LoTOx 6
Capital Recovery Factors 76 gpm, R/O System Design Rate Primary Installation 3,740,000 Installed Capital Cost Interest Rate 7.00% 353,030 Capital Recovery Cost Equipment Life 20 years 1,100,000 Operating & Maintenance Cost CRF 0.0944 1,453,030 Annual Operating Cost 40.10 Wastewater Treatment Cost $/kgal Replacement Parts & Equipment: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 140 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 146,664 10 0.7 - 245.1 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 1,491 gpm 1 60 0.7 - 24.0 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 37 gpm 1 60 0.7 - 0.6 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
LTO Electric Use 4.5 kW/lb O 3 392

Total 662.2

Reagent Use & Other Operating Costs
Ozone Needed 1.8 lb O3/lb NOx 87.2 lb/hr O3 Oxygen Needed 10% wt O2 to O3 conversion 872.151668 lb/hr O2 9,784 scfh O2 LTO Cooling Water 150 gal/lb O3 218 gpm Ozone Generator $350 lb O3/day $732,607 Installed Installed cost factor per BOC. Scrubber Cost 10 $/scfm Gas $1,202,262 Incremental cost per BOC. Need to increase vessel size over standard absorber. Scrubber Outlet Flow 149,061 acfm Scrubber Outlet Temp 150 °F Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf Circulating Water Rate 1,491 gpm Waste WaterDisch = 2.5% of circulating water rate = 37 gpm Evap H2O Loss 135 gpm Water Makeup Rate 172 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 662.2 kW-hr 5,262,047 274,380 $/kwh, 662 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 172.3 gpm 82,129 66,219 $/mgal, 172 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 218.0 gpm 103,952 28,766 $/mgal, 218 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization WW Treat R/O 40.10 $/mgal 37.3 gpm 17,767 712,467 $/mgal, 37 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.0692835 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 9.8 Mscf/hr 77,747 115,475 Mscf, 10 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalyst 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization
*annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-7: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Expected Utilization Rate 100% Temperature 347 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 20.7% Annual Interest Rate 7.0% Actual Flow Rate 197,289 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 129,023 scfm @ 68o F Dry Std Flow Rate 102,315 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) N A Purchased Equipment Total (B) 22% of control device cost (A) NA

Installation - Standard Costs 30% of purchased equip cost (B) NA Installation - Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA Total Capital Investment (TCI) = DC + IC 1 9,445,459

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 663,314 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,282,816 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,946,130

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 8.8 34.8 34.8 - NA Total Particulates 8.8 34.8 34.8 - NA Nitrous Oxides (NOx) 4 48.5 192.5 70% 57.8 134.8 14,442 Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA

Sulfuric Acid Mist 0.0 0.0 0.0 - NA Fluorides 0.0 0.0 0.0 - NA Volatile Organic Compounds (VOC) 3.3 13.0 13.0 - NA Carbon Monoxide (CO) 49.9 198.3 198.3 - NA Lead (Pb) 0.0003 0.0 0.0 - NA

Notes & Assumptions

Basis for SCR control cost:
1 The SCR installed cost estimate is from Midrex (DRI Vendor) via telephone call from T Mauer 05/15/2006
2 SCR catalyst quote based on information obtained from Cormetech, Inc. It is used for catalyst replacement costs.
3 The total direct and indirect operating costs are based on operation and maintenance costs in the

"Pwr Plt SCR $" tab per EPA correlation of SCR costs for power plants.
4 SCR efficiency per Midrex (DRI Vendor) 03/20/2006 email 5 SCR catalyst volume and catalyst life per Midrex (DRI Vendor) 05/15/2006 telephone call from T Maue r 6 SCR catalyst cost $/ft3 per 1/16/2006 Cormetech proposal

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-7: Selective Catalytic Reduction - Basis Power Plant Installed Cost

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) NA

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (B) 22% NA

Installation

Foundations & supports 8% of purchased equip cost (B) NA Handling & erection 14% of purchased equip cost (B) NA Electrical 4% of purchased equip cost (B) NA Piping 2% of purchased equip cost (B) NA Insulation 1% of purchased equip cost (B) NA Painting 1% of purchased equip cost (B) NA Installation Subtotal Standard Expenses 30% NA

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) NA Construction & field expenses 5% of purchased equip cost (B) NA Contractor fees 10% of purchased equip cost (B) NA Start-up 2% of purchased equip cost (B) NA Performance test 1% of purchased equip cost (B) NA Model Studies of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC 9,445,459

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 9,191,298

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator NA - Supervisor NA - Maintenance

Maintenance Labor NA - Maintenance Materials 100% of maintenance labor costs - Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 154 kW-hr, 7946 hr/yr, 100% utilization 63,759
NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - SCR Catalyst 140.00 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization 96,849
NA NA - Total Annual Direct Operating Costs 663,314

Indirect Operating Costs Overhead 60% of total labor and material costs 37,404 Administration (2% total capital costs) 2% of total capital costs (TCI) 188,909 Property tax (1% total capital costs) 1% of total capital costs (TCI) 94,455 Insurance (1% total capital costs) 1% of total capital costs (TCI) 94,455 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 867,593 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,282,816

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,946,130

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-7: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: 5,6 Catalyst Estimate amount of catalyst required Equipment Life 3 years Vol. #1 NA ft3 CRF 0.3811 Flow #1 NA acfm Basis SCR Bids for proposed 2001 Taconite Plant Rep part cost per unit 145 $/ft 3 Flow #2 NA acfm Amount Required 1367.0 ft 3 Vol #2 NA ft3 Catalyst Cost 221,010 Cost adjusted for freight & sales tax Installation Labor 33,151 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 254,161 Zero out if no replacement parts needed Annualized Cost 96,849

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.94 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 197,289 0 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 197,289 4 0.6 153.9 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type Catalytic (catalytic or thermal) 153.9

Reagent Use & Other Operating Costs Ammonia Use
NOx in 0.00 lb/MMBtu 0 lb/hr Neat Efficiency 70% 29% solution 56.0 lb/ft 3 Density Duty 0 MMBtu/hr 0 lb/hr 0.0 gal/hr

NOx Emissions lb/hr 48.5 Volume 14 day inventory 0 gal $0 Inventory Cost

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 0 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 153.9 kW-hr 1,222,773 63,759 $/kwh, 154 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 14676 scfm 0 0 $/mscf, 14,676 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Ammonia 0.101 $/lb 0.0 lb/hr 0 0 $/lb, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalyst 140 $/ft3 0 ft 3 0 96,849 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-7: Selective Catalytic Reduction - Basis Power Plant Installed Cost

EPA SCR Cost Worksheet for Coal Fired Power Plants

Determine Comparable Boiler Size Based on Flue Gas Exhaust Rate stack exhaust flow scfm 129,023 Moisture Content 21% Stack exhaust flow dcfm 102,315 Coal F Factor dscf/MMBtu 10,000 Equivalent Duty MMBtu/hr 614 Est. Power Plant Efficiency 35% Watt per Btu/hr 0.29307 Equivalent Power Plant kW 62,970 Uncontrolled NOx t/yr 940 Annual Operating Hours 8,000
Uncontrolled NOx lb/MMBtu 0.383

Plant Capacity kW A 62,970
Uncontrolled NOx lb/MMBtu B 0.383 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Total Capital Cost $9,445,459

D= 75*(300,000((B/1.5)^0.05*(C/100)^0.04/A)^0.35

Plant Capacity kW A 62,970 Capital Cost $/kW D $150.00 Fixed O&M Cost, $/yr E $62,340

E = D*A*0.0066

Plant Capacity kW A 62,970
Uncontrolled NOx lb/MMBtu B 0.38 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Annual Capacity Factor G 0.82 Heat Input MMBtu/hr H 614 Variable O&M Cost $/yr F $663,314

F = G*(225(0.37*B*H*C/100*8760/2000)*1.005+0.075*D*A*((B/1.5)^0.05*(c/100)^.4)+1.45*A) Note: used worst case factor for catalyst replacement Note: Capital Cost kW is estimate from Tom Robinson @ Babcock Power Inc.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-8: Selective Non-Catalytic Reduction SNCR

Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Chemical Engineering Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 347 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 20.7% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 197,289 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 129,023 scfm @ 68o F Dry Std Flow Rate 102,315 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year Direct Capital Costs EPRI Correlation, 1998 $'s 606 25% 0.08 1998 1,104,409 Purchased Equipment (A) 2005 1,316,796 Purchased Equipment Total (B) 0% of control device cost (A) 1,316,796

Installation - Standard Costs 15% of purchased equip cost (B) 237,023 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC 1,854,845

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 318,452 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 175,084 Total Annual Cost (Annualized Capital Cost + Operating Cost) 493,536

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 8.8 34.8 34.8 - NA Total Particulates 8.8 34.8 34.8 - NA Nitrous Oxides (NOx) 10 48.5 192.5 25% 144.4 48.1 10,255 Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA

Sulfuric Acid Mist 0.0 0.0 0.0 - NA
Fluorides 0.0 0.0 0.0 - NA Volatile Organic Compounds (VOC) 3.3 13.0 13.0 - NA Carbon Monoxide (CO) 49.9 198.3 198.3 - NA Lead (Pb) 0.0003 0.0 0.0 - NA

Notes & Assumptions
1 Cost Estimate from EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 and adjusted for inflation
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 5 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25
6 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29
7 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 8 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
9 No coal ash disposal cost; fuel is natural gas 10 SNCR efficiency per Midrex (DRI Vendor) 03/20/2006 email

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-8: Selective Non-Catalytic Reduction SNCR

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 1,316,796 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,316,796

Indirect Installation

General Facilities 5% of purchased equip cost (A) 65,840 Engineering & Home Office 10% of purchased equip cost (A) 131,680 Process Contingency 5% of purchased equip cost (A) 65,840

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 263,359

Project Contingency ( C) 15% of (A + B) 237,023

Total Plant Cost D A + B + C 1,817,178

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 36,344

Inventory Capital Reagent Vol * $/gal 1,323

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,854,845

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,854,845

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator NA - Supervisor NA - Maintenance

Maintenance Total 15.00 % of Total Capital Investment 278,227 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 1 kW-hr, 7946 hr/yr, 100% utilization 464 Natural Gas 6.85 $/mscf, 0 scfh, 7946 hr/yr, 100% utilization 8,407 Water 0.81 $/mgal, 9 gph, 7946 hr/yr, 100% utilization 60
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Urea 405.00 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization 31,295
NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 318,452

Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 175,084 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 175,084

Total Annual Cost (Annualized Capital Cost + Operating Cost) 493,536

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-8: Selective Non-Catalytic Reduction SNCR

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get Cost Equipment Life 5 years CRF 0.2439 Rep part cost per unit 140 $/ft 3
Amount Required 12 ft 3 Packing Cost 1,873 Cost adjusted for freight & sales tax Installation Labor 281 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cos t Equipment Life 2 years CRF 0.0000 Rep part cost per unit 38 $/ft 3 Amount Required 0 Cages Total Rep Parts Cost 0 Cost adjusted for freight & sales tax See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr) Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag. Annualized Cost 0

Electrical Use NOx in 0.08 lb/MMBtu kW NSR 0.47
Power 1.1

Total 1.1

Reagent Use & Other Operating Costs Urea Use

NOx in 0.08 lb/MMBtu 10 lb/hr Neat Efficiency 25% 50% solution 71.0 lb/ft 3 Density 50% Solution Duty 606 MMBtu/hr 19 lb/hr 2.0 gal/hr Volume 14 day inventory 689 gal $1,323 Inventory Cost

Water Use 9 gal/hr Inject at 10% solution

Fuel Use 0.2 MMBtu/hr 0.2 mscfh natural gas

Ash Generation 1.2 lb/hr

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 278,227 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 1.1 kW-hr 8,903 464 $/kwh, 1 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0.2 scfh 1,227 8,407 $/mscf, 0 scfh, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 9.3 gph 74 60 $/mgal, 9 gph, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 0.0 scfm/kacfm* * 0 0 $/mscf, 0 scfm/kacfm**, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.0692835 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Urea 405 $/ton 0.0097 ton/hr 77 31,295 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalyst 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

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Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Chemical Engineering Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 347 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 20.7% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 197,289 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 129,023 scfm @ 68o F Dry Std Flow Rate 102,315 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 483,235 Purchased Equipment Total (B) 22% of control device cost (A) 587,131

Installation - Standard Costs 30% of purchased equip cost (B) 176,139 Installation - Site Specific Costs NA
Installation Total 176,139 Total Direct Capital Cost, DC 763,270 Total Indirect Capital Costs, IC 31% of purchased equip cost (B ) 182,010 Total Capital Investment (TCI) = DC + IC 945,280

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,735,100 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 157,075 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,892,17 5

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 8.8 34.8 34.8 - NA Total Particulates 8.8 34.8 34.8 - N A Nitrous Oxides (NOx) 48.5 192.5 192.5 - NA Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA
Sulfuric Acid Mist 0.0 0.0 0.0 - NA Fluorides 0.0 0.0 0.0 - NA Volatile Organic Compounds (VOC) 3.3 13.0 90% 1.3 11.7 333,309 Carbon Monoxide (CO) 49.9 198.3 90% 19.8 178.5 21,811 Lead (Pb) 0.0003 0.0 0.0 - N A

Notes & Assumptions 1 Cost Estimate per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 and adjusted for inflation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 483,235

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 48,324 MN Sales Taxes 6.5% of control device cost (A) 31,410 Freight 5% of control device cost (A) 24,162 Purchased Equipment Total (B) 22% 587,131

Installation

Foundations & supports 8% of purchased equip cost (B) 46,970 Handling & erection 14% of purchased equip cost (B) 82,198 Electrical 4% of purchased equip cost (B) 23,485
Piping 2% of purchased equip cost (B) 11,743 Insulation 1% of purchased equip cost (B) 5,871 Painting 1% of purchased equip cost (B) 5,871 Installation Subtotal Standard Expenses 30% 176,139

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 176,139 Total Direct Capital Cost, DC 763,270

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 58,713 Construction & field expense s 5% of purchased equip cost (B) 29,357 Contractor fees 10% of purchased equip cost (B ) 58,713 Start-up 2% of purchased equip cost (B) 11,743 Performance test 1% of purchased equip cost (B) 5,871 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 17,614 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 182,010

Total Capital Investment (TCI) = DC + IC 945,280

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 945,280

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Cost s 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 731 kW-hr, 7946 hr/yr, 100% utilization 302,857 Natural Gas 6.85 $/mscf, 1,036 scfm, 7946 hr/yr, 100% utilization 3,382,183
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 3,735,100

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 18,906 Property tax (1% total capital costs) 1% of total capital costs (TCI) 9,453 Insurance (1% total capital costs) 1% of total capital costs (TCI) 9,453 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 89,228 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 157,07 5

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,892,17 5

See Summary page for notes and assumptions

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Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years
CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 2 year s CRF 0.5531
Rep part cost per unit 650 $/ft 3
Amount Required 39 ft 3
Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts needed
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 197,289 19 0.6 731.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 197,289 23 0.6 884.8 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 731.0

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculations A nnual hours of operation: 7,946 Utilization Rate: 100.0 %

Unit Unit of Use Unit of A nnual A nnual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 731.0 kW-hr 5,808,173 302,857 $/kwh, 731 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 1,036 scfm 493,749 3,382,183 $/mscf, 1,036 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.069283 5 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 347 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 944 Deg F - Temperature of waste gas out of heat recovery

T fo 603 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 129,023 scfm - Flow of waste gas

Q af 1,036 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculation s 130,059 scfm Flue Gas Cost in 1989 $' s $405,29 4 Current Cost Using CHE Plant Cost Inde x $483,23 5 Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.2 4 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.2 7

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-10: CO/VOC Control - Catalytic Oxidizer

Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Chemical Engineering Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 347 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 20.7% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 197,289 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 129,023 scfm @ 68o F Dry Std Flow Rate 102,315 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 869,674 Purchased Equipment Total (B) 22% of control device cost (A) 1,056,654

Installation - Standard Costs 30% of purchased equip cost (B) 316,996 Installation - Site Specific Costs NA
Installation Total 316,996 Total Direct Capital Cost, DC 1,373,650 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 327,563 Total Capital Investment (TCI) = DC + I C 1,701,213

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,706,053 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 211,818 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 1,917,871

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Unit s T/yr T/yr $/Ton Rem
PM10 8.8 34.8 34.8 - NA Total Particulates 8.8 34.8 34.8 - NA Nitrous Oxides (NOx) 48.5 192.5 192.5 - NA Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA
Sulfuric Acid Mist 0.0 0.0 0.0 - NA Fluorides 4.4E-04 1.7E-03 1.7E-03 - NA Volatile Organic Compounds (VOC) 3.3 13.0 90% 1.3E+00 11.7 164,238 Carbon Monoxide (CO) 49.9 198.3 90% 19.8 178.5 10,747 Lead (Pb) 0.0 0.0 0.0 - NA

Notes & Assumptions
1 Aug 28, 2005 Catalyst Cost Estimate from Englehard Catalyst & EPA Control Cost Manual Section 3.2 Chapter 2 and adjusted for in flation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-10: CO/VOC Control - Catalytic Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 869,674

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 86,967 MN Sales Taxes 6.5% of control device cost (A) 56,529 Freight 5% of control device cost (A) 43,484 Purchased Equipment Total (B) 22% 1,056,654

Installation

Foundations & supports 8% of purchased equip cost (B) 84,532 Handling & erection 14% of purchased equip cost (B) 147,932 Electrical 4% of purchased equip cost (B) 42,266
Piping 2% of purchased equip cost (B) 21,133 Insulation 1% of purchased equip cost (B) 10,567 Painting 1% of purchased equip cost (B) 10,567 Installation Subtotal Standard Expenses 30% 316,996

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Tota l 316,996 Total Direct Capital Cost, DC 1,373,650

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 105,665 Construction & field expenses 5% of purchased equip cost (B) 52,833 Contractor fees 10% of purchased equip cost (B) 105,665 Start-up 2% of purchased equip cost (B) 21,133 Performance test 1% of purchased equip cost (B) 10,567 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 31,700 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 327,563

Total Capital Investment (TCI) = DC + I C 1,701,213

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 1,204,892

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 885 kW-hr, 7946 hr/yr, 100% utilization 366,616 Natural Gas 6.85 $/mscf, 358 scfm, 7946 hr/yr, 100% utilization 1,168,329
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization 121,048
NA NA - Total Annual Direct Operating Cost s 1,706,053

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 34,024 Property tax (1% total capital costs) 1% of total capital costs (TCI) 17,012 Insurance (1% total capital costs) 1% of total capital costs (TCI) 17,012 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 113,733 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 211,818

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 1,917,871

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-10: CO/VOC Control - Catalytic Oxidizer

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 5 years
CRF 0.2439
Rep part cost per unit 3000 $/ft 3
Amount Required 129 ft 3
Catalyst Cost 431,583 Cost adjusted for freight & sales tax Installation Labor 64,737 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 496,320 Zero out if no replacement parts needed

Annualized Cost 121,048

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 197,289 19 0.6 731.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 197,289 23 0.6 884.8 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type catalytic (catalytic or thermal) 884.8

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cos t Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 884.8 kW-hr 7,030,946 366,616 $/kwh, 885 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 358 scfm 170,559 1,168,329 $/mscf, 358 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization WW Treat Neutralization 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreatemen t 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.0692835 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalyst 650 $/ft3 0 ft 3 0 121,048 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-10: CO/VOC Control - Catalytic Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 347 Deg F - Temperature of waste gas into heat recovery
T fi 600 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 524 Deg F - Temperature of waste gas out of heat recovery

T fo 423 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 129,023 scfm - Flow of waste gas

Q af 358 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 129,381 scfm Flue Gas Cost in 1989 $'s $404,765 Current Cost Using CHE Plant Cost Index $482,604
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-11: CO/VOC Control - Regenerative Thermal Oxidizer

Operating Unit: DRI Process Heater

Emission Unit Number EU 066 & 083 Stack/Vent Number SV 030 &066 Chemical Engineering Design Capacity 606 MMBtu/hr Standardized Flow Rate 120,226 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 347 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 20.7% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 197,289 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 129,023 scfm @ 68o F Dry Std Flow Rate 102,315 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 3 1,116,862 Purchased Equipment Total (B) 22% of control device cost (A) 1,356,987

Installation - Standard Costs 30% of purchased equip cost (B) 407,096 Installation - Site Specific Costs NA
Installation Total 407,096 Total Direct Capital Cost, DC 1,764,083 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 420,666 Total Capital Investment (TCI) = DC + I C 2,184,749

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,231,775 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 323,651 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 2,555,426

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Unit s T/yr T/yr $/Ton Rem
PM10 8.8 34.8 34.8 - NA Total Particulates 8.8 34.8 34.8 - NA Nitrous Oxides (NOx) 48.5 192.5 192.5 - NA Sulfur Dioxide (SO 2 ) 0.8 3.0 3.0 - NA
Sulfuric Acid Mist 0.0 0.0 0.0 - NA Fluorides 0.0 0.0 0.0 - NA Volatile Organic Compounds (VOC) 3.3 13.0 90% 1.3 11.7 218,835 Carbon Monoxide (CO) 49.9 198.3 90% 19.8 178.5 14,320 Lead (Pb) 0.0003 0.0 0.0 - NA

Notes & Assumptions
1 Cost Estimate per L & E America (TANN Corp), Aug 1, 2006 email
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Cost Estimate per Tann Corporation, July 2006
4 Used 0.6 power law factor to adjust price from bid basis of 100,000 scfm

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-11: CO/VOC Control - Regenerative Thermal Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 1,116,862

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 111,686 MN Sales Taxes 6.5% of control device cost (A) 72,596 Freight 5% of control device cost (A) 55,843 Purchased Equipment Total (B) 22% 1,356,987

Installation

Foundations & supports 8% of purchased equip cost (B) 108,559 Handling & erection 14% of purchased equip cost (B) 189,978 Electrical 4% of purchased equip cost (B) 54,279
Piping 2% of purchased equip cost (B) 27,140 Insulation 1% of purchased equip cost (B) 13,570 Painting 1% of purchased equip cost (B) 13,570 Installation Subtotal Standard Expenses 30% 407,096

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Tota l 407,096 Total Direct Capital Cost, DC 1,764,083

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 135,699 Construction & field expenses 5% of purchased equip cost (B) 67,849 Contractor fees 10% of purchased equip cost (B) 135,699 Start-up 2% of purchased equip cost (B) 27,140 Performance test 1% of purchased equip cost (B) 13,570 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 40,710 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 420,666

Total Capital Investment (TCI) = DC + I C 2,184,749

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 2,184,749

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 885 kW-hr, 7946 hr/yr, 100% utilization 366,616 Natural Gas 6.85 $/mscf, 556 scfm, 7946 hr/yr, 100% utilization 1,815,099
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 2,231,775

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 43,695 Property tax (1% total capital costs) 1% of total capital costs (TCI) 21,847 Insurance (1% total capital costs) 1% of total capital costs (TCI) 21,847 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 206,225 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 323,651

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 2,555,426

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-11: CO/VOC Control - Regenerative Thermal Oxidizer

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years
CRF 0.0000
Rep part cost per unit 650 $/ft 3
Amount Required 0 ft 3
Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 197,289 19 0.6 731.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 197,289 23 0.6 884.8 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type catalytic (catalytic or thermal) 884.8

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cos t Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 884.8 kW-hr 7,030,946 366,616 $/kwh, 885 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 556 scfm 264,978 1,815,099 $/mscf, 556 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization WW Treat Neutralization 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreatemen t 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.0692835 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalyst 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment D - Emission Control Cost Analysis Table D-11: CO/VOC Control - Regenerative Thermal Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 90% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 347 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 1,115 Deg F - Temperature of waste gas out of heat recovery

T fo 432 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 129,023 scfm - Flow of waste gas

Q af 556 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 129,023 scfm Flue Gas

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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# Attachment E

DRI Tail Gas Purification System BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment E - Emission Control Cost AnalysisTable E-1: Cost Summary - DRI Top Gas PurificationH2S Control Cost SummaryDRI Top Gas PurificationControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?LoCAT92.3% 2.5 30.1 $7,373,349 $1,355,047 $45,010 NA None LowSolid Waste(sulfur)Zinc Oxide92.3% 2.5 30.1 $7,920,532$2,096,023$69,622 NANone Low Solid WasteRegenerative ThermalOxidizer + Absorber - Caustic92.3% 2.5 30.1 $3,011,277 $1,137,575 $37,786 NACollateralNOxemissionsHigh NoneRegenerative ThermalOxidizer92.3% 2.5 30.1 $1,956,150 $883,916 $29,360 NACollateral SO2and NOxemissionsMedium NoneRecuperantive ThermalOxidizer92.3% 2.5 30.1 $1,467,113 $1,441,107 $47,868 NACollateral SO2and NOxemissionsHigh Solid WasteUncontrolled0% 32.6P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach E - HYL Top Gas Purification Mar 2007RevisionCost Summary3/6/2007 Page 1 of 19

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: DRI Top Gas Purification Study Year 2006 Emission Unit Number EU 067 & 084 Stack/Vent Number SV 078 & 79 Reference
Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.052 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig
Water 0.81 $/mgal 0.76 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation

Cooling Water 0.28 $/mgal 0.23 1999 EPA Ai r P o ll u ti on C on t ro l C os t M anua l

, 6th ed. Section 3.1 Ch 1 Ch 1 C ar b on Ab sor b ers, 1999 $0

. 15 - $0

. 30 A vg o f 22

. 5 an d 7 yrs an d 3% inflation

Compressed Air 0.32 $/mscf 0.25 1998 EPA Ai r P o ll u ti on C on t ro l C os t M anua l 6th Ed 2002, Section 6 Chapter 1 E xamp l e pro bl em; D r i e d & Filt ere d

, Ch 1

. 6 '98 cos t a dj us t e d f or 3% inflation

Wastewater Disposal Neutralization 1.69 $/mgal 1.50 2002 EPA Ai r P o ll u ti on C on t ro l C os t M anua l 6th Ed 2002, Section 2 Chapter 2.5.5.5 S ec ti on 2 li s t s $1 - $2/1000 ga l

. C os t a dj us t e d f or 3% i n fl a ti on S ec 6 Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.28 $/mgal 3.80 2002 EPA Ai r P o ll u ti on C on t ro l C os t M anua l 6th Ed 2002, Section 5.2 Chapter 1 Ch 1li s t s $1

. 00 - $6

. 00 f or mun i c i pa l t rea t men t

, $3

. 80 i s average. C os t adjusted for 3% inflation

Solid Waste Disposal 28.14 $/ton 25.00 2002 EPA Ai r P o ll u ti on C on t ro l C os t M anua l 6th Ed 2002, Section 2 Chapter 2.5.5.5 S ec ti on 2 li s t s $20 - $30/t on U se d $25/t on. C os t a dj us t e d f or 3% inflation

Hazardous Waste Disposal 281.38 $/ton 250.00 2002 EPA Ai r P o ll u ti on C on t ro l C os t M anua l 6th Ed 2002, Section 2 Chapter 2.5.5.5 S ec ti on 2 li s t s $200 - $300/t on U se d $250/t on. C os t a dj us t e d f or 3% inflation

Waste Transport 0.56 $/ton-mi 0.50 2002 EPA Ai r P o ll u ti on C on t ro l C os t M anua l 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycle 1.19 $/ton 1.00 2000 Corus Study for MN Iron and Steel Project Study use $1/ton to cover cost of materials movement

Chemicals & Supplies
Lime 26.07 $/ton 24.57 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation
Caustic 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.49 Mscf 1.40 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation EPA Urea 179.1 $/ton A mmonia 0.101 $/lb Reagent #8 $/ton

Catalyst & Replacement Parts SCR Catalyst 140 $/ft 3 Cormetech, Inc., 1/2006 bid CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 Catalyst #4 Catalyst #5

Filter Bags 37.94 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Other Sales Tax 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Informatio n A nnual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 100% 2004 Kaar Consulting MSI Cost Model Equipment Life 20 yrs Engineering Estimate Design Capacity NA MMBtu/hr Standardized Flow Rate 21,316 scfm @ 32o F Temperature 120 Deg F Moisture Content 10.47% Actual Flow Rate 25,136 acfm Standardized Flow Rate 22,875 scfm @ 68o F 36,214 NCMH Dry Std Flow Rate 20,481 dscfm @ 68o F

Max Emis Uncontrolled Conc from Reformer Pollutan t Lb/H r prior to eductor PM10 0.000 gr/dscf Total Particulates 0.000 gr/dscf Control Device Outlet Concentratio n Nitrous Oxides (NOx) 0 ppmw 0 PPM NOx @ 70% control Sulfur Dioxide (SO 2 ) 0 ppmw Sulfuric Acid Mist 0.000 ppmw Fluorides 0.0E+00 gr/dscf 0.0 ppb Volatile Organic Compounds (VOC) 0.0 ppmw Carbon Monoxide (CO) 0 ppmw Lead (Pb) 0.0E+00 gr/dscf 0.0 ppb Hydrogen Sulfide (H2S) 8.21 68 ppmw 92.6% control efficiency at 5 ppm in exhaust Enter this data for each emission uni t Enter data for this study (applies to all units )

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-3: H2S Control - LoCAT

Operating Unit: DRI Top Gas Purification

Emission Unit Number EU 067 & 084 Stack/Vent Number SV 078 & 79 Design Capacity NA MMBtu/hr Standardized Flow Rate 21,316 scfm @ 32o F Expected Utilization Rat e 100% Temperature 120 Deg F Expected Annual Hours of Operatio n 7,94 6 Hours Moisture Conten t 10.5% Annual Interest Rate 7.0% Actual Flow Rate 26,834 acfm Expected Equipment Life 20 yrs Standardized Flow Rat e 22,87 5 scfm @ 68o F Dry Std Flow Rat e 20,47 3 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A ) 3,800,00 0 Purchased Equipment Total (B ) 22% of control device cost (A ) 4,617,00 0

Installation - Standard Costs 25% of purchased equip cost (B) 1,140,399 Installation - Site Specific Costs NA Installation Total 1,140,399 Total Direct Capital Cost, DC 5,757,399 Total Indirect Capital Costs, IC 35 % of purchased equip cost (B ) 1,615,95 0 Total Capital Investment (TCI) = DC + IC 7,373,34 9

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 243,978 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,111,069 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 1,355,04 7

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 - - - NA Total Particulate s

- - - N A Nitrous Oxides (NOx) - - - NA Sulfur Dioxide (SO 2 )

- - - NA

Sulfuric Acid Mist - - - NA
Fluorides - - - NA Volatile Organic Compounds (VOC) - - - NA Carbon Monoxide (CO) - - - NA Lead (Pb) - - - NA Hydrogen Sulfide (H 2 S) 8.2 32.6 92.3% 2.5 30.1 45,010

Notes & Assumptions 1 A ug 3, 2006 Cost Estimate Gas Technology Product s 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1
3 Estimated installation costs per Aug 21, 2006 email from Gas Technology Products
4 Purchased equipment price, electricity use of 67 bhp, and LoCAT chemical costs of $67/day from Gas Technology Products, August 2006 5 Assume 2 operating hours per day for the LoCAT control technology as estimated operating time was provided by the vendor as 3 h ours or less per day. 6 7
8 9

Notes to User

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-3: H2S Control - LoCAT

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 3,800,000

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A ) 380,00 0 MN Sales Taxes 6.5% of control device cost (A ) 247,00 0 Freight 5% of control device cost (A) 190,000 Purchased Equipment Total (B) 22% 4,617,00 0

Installation

Foundations & supports NA of purchased equip cost (B) NA Handling & erection NA of purchased equip cost (B) NA Electrical N A of purchased equip cost (B ) N A Piping NA of purchased equip cost (B) NA Insulation N A of purchased equip cost (B ) N A Painting N A of purchased equip cost (B ) N A Installation Subtotal Standard Expenses (3 ) 25% 1,140,39 9

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 1,140,39 9 Total Direct Capital Cost, DC 5,757,39 9

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 461,700 Construction & field expense s 10% of purchased equip cost (B) 461,700 Contractor fee s 10% of purchased equip cost (B ) 461,70 0 Start-up 1% of purchased equip cost (B) 46,170 Performance tes t 1% of purchased equip cost (B) 46,170 Model Studie s N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 138,510 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 1,615,950

Total Capital Investment (TCI) = DC + IC 7,373,34 9

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 7,373,34 9

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Labor 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Maintenance Materials 100% of maintenance labor costs 63,568 Utilities, Supplies, Replacements & Waste Managemen t

Electricity (4) 0.05 $/kwh, 50 kW-hr, 7946 hr/yr, 100% utilizatio n 20,70 9
NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - SW Disposal 28.14 $/ton, 30 ton/yr, 7946 hr/yr, 100% utilization 847
NA NA - NA NA - NA NA - LoCAT Chemicals (4) 67.00 $/day, 331 days, 7946 hr/yr, 100% utilization 22,183
NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 243,97 8

Indirect Operating Costs

Overhead 60% of total labor and material costs 120,144 Administration (2% total capital costs) 2% of total capital costs (TCI) 147,467 Property tax (1% total capital costs) 1% of total capital costs (TCI) 73,733 Insurance (1% total capital costs) 1% of total capital costs (TCI) 73,733 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 695,992 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 1,111,06 9

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 1,355,04 7

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-3: H2S Control - LoCAT

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.094 4

Replacement Catalyst: Equipment Life 5 years CRF 0.000 0 Rep part cost per unit 140 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement )
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cos t 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Reagent Use & Other Operating Costs

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor (5) 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 63,568 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity (4) 0.052 $/kwh 50.0 kW-hr 397,157 20,709 $/kwh, 50 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilizatio n Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 30.1 ton/yr 30.1 847 $/ton, 30 ton/yr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization LoCAT Chemicals (4) 67 $/da y 331.1 day s 331.1 22,18 3 $/day, 331 days, 7946 hr/yr, 100% utilizatio n Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilizatio n Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-4: H2S Control - Zinc Oxide

Operating Unit: DRI Top Gas Purification

Emission Unit Number EU 067 & 084 Stack/Vent Number SV 078 & 79 Chemical Engineering Design Capacity NA MMBtu/hr Standardized Flow Rate 21,316 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rat e 100% Temperature 120 Deg F 1998/199 9 390 Expected Annual Hours of Operatio n 7,94 6 Hours Moisture Conten t 10.5% 200 5 465 Annual Interest Rate 7.0% Actual Flow Rate 26,834 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 22,87 5 scfm @ 68o F Dry Std Flow Rat e 20,47 3 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A ) 4,049,041 Purchased Equipment Total (B ) 22% of control device cost (A ) 4,919,58 5

Installation - Standard Costs 30% of purchased equip cost (B) 1,475,876 Installation - Site Specific Costs NA Installation Total 1,475,876 Total Direct Capital Cost, DC 6,395,461 Total Indirect Capital Costs, IC 31 % of purchased equip cost (B ) 1,525,071 Total Capital Investment (TCI) = DC + IC 7,920,53 2

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,025,552 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,070,471 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 2,096,02 3

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 - - - NA Total Particulate s

- - - N A Nitrous Oxides (NOx) - - - NA Sulfur Dioxide (SO 2 )

- - - NA
Sulfuric Acid Mist - - - NA Fluorides - - - NA Volatile Organic Compounds (VOC) - - - NA Carbon Monoxide (CO) - - - NA Lead (Pb) - - - NA Hydrogen Sulfide (H 2 S) 8.2 32.6 92.3% 2.5 30.1 69,622

Notes & Assumptions 1 Estimated capital cost equals four times zinc oxide cost; operating costs typically 20% - 25% of capital cos
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Operating cost based on estimate from Johnson Matthey Catalysts, August 2006. Based on a product brochure, 23.2 lb sulfur are picked up by the zinc

Zinc oxide catalyst, Katalco 32-4. The price of $360 /ft3 of Katalco 32-4 was provided by Tina Moss at Johnson Matthey Catalys ts. 4 Capital cost estimated as four times the operating cost of the zinc oxide

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-4: H2S Control - Zinc Oxide

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 4,049,041

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A ) 404,90 4 MN Sales Taxes 6.5% of control device cost (A ) 263,18 8 Freight 5% of control device cost (A) 202,452 Purchased Equipment Total (B) 22% 4,919,58 5

Installation

Foundations & supports 8% of purchased equip cost (B) 393,567 Handling & erection 14% of purchased equip cost (B) 688,742 Electrical 4% of purchased equip cost (B ) 196,78 3 Piping 2% of purchased equip cost (B) 98,392 Insulation 1% of purchased equip cost (B ) 49,19 6 Painting 1% of purchased equip cost (B ) 49,19 6 Installation Subtotal Standard Expense s 30% 1,475,87 6

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 1,475,87 6 Total Direct Capital Cost, DC 6,395,461

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 491,959 Construction & field expense s 5% of purchased equip cost (B) 245,979 Contractor fee s 10% of purchased equip cost (B ) 491,95 9 Start-up 2% of purchased equip cost (B) 98,392 Performance tes t 1% of purchased equip cost (B) 49,196 Model Studie s of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 147,588 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 1,525,071

Total Capital Investment (TCI) = DC + IC 7,920,53 2

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 7,920,53 2

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.1 hr/8 hr shift, 7946 hr/yr 3,178 Supervisor 15% 15% of Operator Costs 477
Maintenance

Maintenance Labor 32.00 $/Hr, 0.1 hr/8 hr shift, 7946 hr/yr 3,178 Maintenance Materials 100% of maintenance labor costs 3,178 Utilities, Supplies, Replacements & Waste Managemen t

N A N A - NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - SW Disposal 28.14 $/ton, 26 lb/hr, 7946 hr/yr, 100% utilization 2,888
NA NA - NA NA - NA NA - Zinc Oxide 360.00 $/ft3, 0 $/ft3, 7946 hr/yr, 100% utilization 1,012,260 Caustic 280.00 $/ton, 0 $/ft3, 7946 hr/yr, 100% utilization 392

NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 1,025,55 2

Indirect Operating Costs

Overhead 60% of total labor and material costs 6,007 Administration (2% total capital costs) 2% of total capital costs (TCI) 158,411 Property tax (1% total capital costs) 1% of total capital costs (TCI) 79,205 Insurance (1% total capital costs) 1% of total capital costs (TCI) 79,205 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 747,642 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 1,070,471

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 2,096,02 3

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-4: H2S Control - Zinc Oxide

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.094 4

Replacement Catalyst: Catalyst Equipment Life 2 years CRF 0.000 0 Rep part cost per unit 650 $/ft 3
Amount Required 0 ft 3 Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement )
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cos t 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.1 hr/8 hr shift 99 3,178 $/Hr, 0.1 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 477 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.1 hr/8 hr shift 99 3,178 $/Hr, 0.1 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 3,178 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilizatio n Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 25.8 lb/hr 103 2,888 $/ton, 26 lb/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Zinc Oxide 360.0 0 $/ft3 0.4 $/ft3 2,812 1,012,26 0 $/ft3, 0 $/ft3, 7946 hr/yr, 100% utilizatio n Caustic 280 $/ton 0.4 $/ft3 1 392 $/ton, 0 $/ft3, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilizatio n Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-5: SO2 Control - Wet Scrubber

Operating Unit: DRI Top Gas Purification

Emission Unit Number EU 067 & 084 Stack/Vent Number SV 078 & 79 Design Capacity NA MMBtu/hr Standardized Flow Rate 21,316 scfm @ 32o F Expected Utilization Rat e 100% Temperature 120 Deg F Expected Annual Hours of Operatio n 7,94 6 Hours Moisture Conten t 10.5% Annual Interest Rate 7.0% Actual Flow Rate 25,136 acfm Expected Equipment Life 20 yrs Standardized Flow Rat e 22,87 5 scfm @ 68o F Dry Std Flow Rat e 20,481 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A ) 394,73 5 Purchased Equipment Total (B ) 22% of control device cost (A ) 479,60 3

Installation - Standard Costs 85% of purchased equip cost (B) 407,663 Installation - Site Specific Costs NA Installation Total 407,663 Total Direct Capital Cost, DC 887,266 Total Indirect Capital Costs, IC 35 % of purchased equip cost (B ) 167,861 Total Capital Investment (TCI) = DC + IC 1,055,12 7

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 81,822 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 171,838 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 253,65 9

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 - - - NA Total Particulate s

- - - N A Nitrous Oxides (NOx) - - - NA Sulfur Dioxide (SO 2 )

- - - - NA
Sulfuric Acid Mist - - - NA Fluorides - - - NA Volatile Organic Compounds (VOC) - - - NA Carbon Monoxide (CO) - - - NA Lead (Pb) - - - NA Hydrogen Sulfide (H 2 S) 8.2 32.6 92.3% 2.5 30.1 8,426

Notes & Assumptions 1 Nov 16, 2004 Cost Estimate Turbosonic.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Used 0.6 power law factor to adjust price to calculated dscfm from bid basis of 23,488 acfm 6 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies. 7 Scrubber/WESP evaporative water loss per Turbosonic proposal

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-5: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 394,735

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A ) 39,47 4 MN Sales Taxes 6.5% of control device cost (A ) 25,65 8 Freight 5% of control device cost (A) 19,737 Purchased Equipment Total (B) 22% 479,60 3

Installation

Foundations & supports 12% of purchased equip cost (B) 57,552 Handling & erection 40% of purchased equip cost (B) 191,841 Electrical 1% of purchased equip cost (B ) 4,79 6 Piping 30% of purchased equip cost (B) 143,881 Insulation 1% of purchased equip cost (B ) 4,79 6 Painting 1% of purchased equip cost (B ) 4,79 6 Installation Subtotal Standard Expense s 85% 407,66 3

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 407,66 3 Total Direct Capital Cost, DC 887,26 6

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,960 Construction & field expense s 10% of purchased equip cost (B) 47,960 Contractor fee s 10% of purchased equip cost (B ) 47,96 0 Start-up 1% of purchased equip cost (B) 4,796 Performance tes t 1% of purchased equip cost (B) 4,796 Model Studie s N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 14,388 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 167,861

Total Capital Investment (TCI) = DC + IC 1,055,12 7

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 1,055,12 7

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 40 kW-hr, 7946 hr/yr, 100% utilizatio n 16,60 3
NA NA - Water 0.81 $/mgal, 26 gpm, 7946 hr/yr, 100% utilization 10,103
NA NA - NA NA - WW Treat Neutralization 1.69 $/mgal, 6 gpm, 7946 hr/yr, 100% utilizatio n 5,05 6
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 81,82 2

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 21,103 Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,551 Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,551 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 99,597 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 171,83 8

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 253,65 9

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-5: SO2 Control - Wet Scrubber

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.094 4

Replacement Catalyst: Equipment Life 5 years CRF 0.000 0 Rep part cost per unit 140 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement )
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cos t 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 25,13 6 8.55 0.7 - 35.9 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.4 8
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 251 gpm 1 60 0.7 - 4.0 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 6 gpm 1 60 0.7 - 0.1 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other
Other
Other Total 40.1

Reagent Use & Other Operating Costs
Caustic Use 0.00 lb/hr SO2 2.50 lb NaOH/lb SO2 0.00 lb/hr Caustic
Lime Use 0.00 lb/hr SO2 1.56 lb Lime/lb SO2 0 lb/hr Lime

Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf Circulating Water Rate 251 gpm Water Makeup Rate/WW Disch = 2.5% of circulating water rate = 6 gpm Scrubber Outlet Flow 25,128 acfm Scrubber Outlet Temp 120 °F Evap H2O Loss 20 gpm, basis Turbosonic proposal Water Makeup Rate 26 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 40.1 kW-hr 318,404 16,603 $/kwh, 40 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 26.3 gpm 12,530 10,103 $/mgal, 26 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilizatio n Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 6.3 gpm 2,995 5,056 $/mgal, 6 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.069283 5 $/ton lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilizatio n Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilizatio n Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-6: CO/VOC Control - Thermal Oxidizer

Operating Unit: DRI Top Gas Purification

Emission Unit Number EU 067 & 084 Stack/Vent Number SV 078 & 79 Chemical Engineering Design Capacity NA MMBtu/hr Standardized Flow Rate 21,316 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 120 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,136 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 22,87 5 scfm @ 68o F Dry Std Flow Rate 20,481 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 750,000 Purchased Equipment Total (B) 22% of control device cost (A) 911,250

Installation - Standard Costs 30% of purchased equip cost (B) 273,375 Installation - Site Specific Costs NA
Installation Total 273,375 Total Direct Capital Cost, DC 1,184,625 Total Indirect Capital Costs, IC 31 % of purchased equip cost (B ) 282,48 8 Total Capital Investment (TCI) = DC + IC 1,467,11 3

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,213,902 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 227,205 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 1,441,10 7

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 0.2 0.6 0.6 - NA Total Particulate s 2.2 8.7 8.7 - N A Nitrous Oxides (NOx) 2.5 10.1 10.1 - NA Sulfur Dioxide (SO 2 )

- - - - NA
Sulfuric Acid Mist - - - - NA Fluorides - - - - NA Volatile Organic Compounds (VOC) - - - - NA Carbon Monoxide (CO) - - - - NA Lead (Pb) - - - - NA Hydrogen Sulfide (H 2 S) 8.2 32.6 92.3% 2.5 30.1 47,868

Notes & Assumptions 1 Capital Cost Estimate per HYL
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Waste gas flow to oxidizer adjusted to add flow for combustion air and 5% O2 in exhaust.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-6: CO/VOC Control - Thermal Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 750,000

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 75,000 MN Sales Taxes 6.5% of control device cost (A) 48,750 Freight 5% of control device cost (A) 37,500 Purchased Equipment Total (B) 22% 911,25 0

Installation

Foundations & supports 8% of purchased equip cost (B) 72,900 Handling & erection 14% of purchased equip cost (B) 127,575 Electrical 4% of purchased equip cost (B) 36,450
Piping 2% of purchased equip cost (B) 18,225 Insulation 1% of purchased equip cost (B) 9,113 Painting 1% of purchased equip cost (B) 9,113 Installation Subtotal Standard Expenses 30% 273,375

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 273,37 5 Total Direct Capital Cost, DC 1,184,62 5

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 91,125 Construction & field expense s 5% of purchased equip cost (B) 45,563 Contractor fee s 10% of purchased equip cost (B ) 91,12 5 Start-up 2% of purchased equip cost (B) 18,225 Performance tes t 1% of purchased equip cost (B) 9,113 Model Studie s of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 27,338 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 282,488

Total Capital Investment (TCI) = DC + IC 1,467,11 3

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 1,467,11 3

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 93 kW-hr, 7946 hr/yr, 100% utilizatio n 38,58 6 Natural Gas 6.85 $/mscf, 345 scfm, 7946 hr/yr, 100% utilization 1,125,256
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 1,213,90 2

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 29,342 Property tax (1% total capital costs) 1% of total capital costs (TCI) 14,671 Insurance (1% total capital costs) 1% of total capital costs (TCI) 14,671 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 138,485 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 227,20 5

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 1,441,10 7

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-6: CO/VOC Control - Thermal Oxidizer

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 650 $/ft 3
Amount Required 39 ft 3
Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 25,13 6 19 0.6 93.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2. 1 Blower, Catalytic 25,136 23 0.6 112.7 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Typ e thermal (catalytic or thermal) 93.1

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 93.1 kW-hr 739,992 38,586 $/kwh, 93 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 345 scfm 164,271 1,125,256 $/mscf, 345 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilizatio n Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.069283 5 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilizatio n Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilizatio n Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-6: CO/VOC Control - Thermal Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 120 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 876 Deg F - Temperature of waste gas out of heat recovery

T fo 444 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas - flue gas

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 34,391 scfm - Flow of waste gas

Q af 345 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculation s 34,73 5 scfm Flue Gas Cost in 1989 $' s $291,35 8 Current Cost Using CHE Plant Cost Inde x $347,38 9
Heat Rec % A B 0 10,29 4 0.235 5 Exponents per equation 3.2 4 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,34 2 0.250 0 Exponents per equation 3.2 7

Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528 18 mw H2O 10 v % 50 6.0% 0.46 0.027 6
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368 Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-7: CO/VOC Control - Regenerative Thermal Oxidizer

Operating Unit: DRI Top Gas Purification

Emission Unit Number EU 067 & 084 Stack/Vent Number SV 078 & 79 Chemical Engineering Design Capacity NA MMBtu/hr Standardized Flow Rate 21,316 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 120 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 26,834 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 22,87 5 scfm @ 68o F Dry Std Flow Rate 20,473 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 3 1,000,000 Purchased Equipment Total (B) 22% of control device cost (A) 1,215,000

Installation - Standard Costs 30% of purchased equip cost (B) 364,500 Installation - Site Specific Costs NA
Installation Total 364,500 Total Direct Capital Cost, DC 1,579,500 Total Indirect Capital Costs, IC 31 % of purchased equip cost (B ) 376,65 0 Total Capital Investment (TCI) = DC + IC 1,956,15 0

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 590,987 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 292,929 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 883,91 6

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 0.1 0.3 0.3 - NA Total Particulate s 0.1 0.3 0.3 - N A Nitrous Oxides (NOx) 1.1 4.4 4.4 - NA Sulfur Dioxide (SO 2 )

- - - - NA
Sulfuric Acid Mist - - - - NA Fluorides - - - - NA Volatile Organic Compounds (VOC) - - - - NA Carbon Monoxide (CO) - - - - NA Lead (Pb) - - - - NA Hydrogen Sulfide (H 2 S) 8.2 32.6 92.3% 2.5 30.1 29,360 Notes & Assumptions
1 Cost Estimate per L & E America (TANN Corp), Aug 1, 2006 email
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Waste gas flow to oxidizer adjusted to add flow for combustion air and 5% O2 in exhaust

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-7: CO/VOC Control - Regenerative Thermal Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 1,000,000

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 100,000 MN Sales Taxes 6.5% of control device cost (A) 65,000 Freight 5% of control device cost (A) 50,000 Purchased Equipment Total (B) 22% 1,215,00 0

Installation

Foundations & supports 8% of purchased equip cost (B) 97,200 Handling & erection 14% of purchased equip cost (B) 170,100 Electrical 4% of purchased equip cost (B) 48,600
Piping 2% of purchased equip cost (B) 24,300 Insulation 1% of purchased equip cost (B) 12,150 Painting 1% of purchased equip cost (B) 12,150 Installation Subtotal Standard Expenses 30% 364,500

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 364,50 0 Total Direct Capital Cost, DC 1,579,50 0

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 121,500 Construction & field expense s 5% of purchased equip cost (B) 60,750 Contractor fee s 10% of purchased equip cost (B ) 121,50 0 Start-up 2% of purchased equip cost (B) 24,300 Performance tes t 1% of purchased equip cost (B) 12,150 Model Studie s of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 36,450 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 376,650

Total Capital Investment (TCI) = DC + IC 1,956,15 0

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 1,956,15 0

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 120 kW-hr, 7946 hr/yr, 100% utilizatio n 49,86 6 Natural Gas 6.85 $/mscf, 150 scfm, 7946 hr/yr, 100% utilization 491,062
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 590,98 7

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 39,123 Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,562 Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,562 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 184,647 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 292,92 9

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 883,91 6

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-7: CO/VOC Control - Regenerative Thermal Oxidizer

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years
CRF 0.0000
Rep part cost per unit 650 $/ft 3
Amount Required 0 ft 3
Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 26,83 4 19 0.6 99.4 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2. 1 Blower, Catalytic 26,834 23 0.6 120.4 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Typ e catalyti c (catalytic or thermal) 120.4 (Assumed catalytic to account for pres drop in heat rec bed )

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 120.4 kW-hr 956,322 49,866 $/kwh, 120 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 150 scfm 71,688 491,062 $/mscf, 150 scfm, 7946 hr/yr, 100% utilization Water 0.81 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilizatio n Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization
WW Treat Biotreateme n 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 28.14 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 26.069283 5 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilizatio n Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilizatio n Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment E - Emission Control Cost Analysis Table E-7: CO/VOC Control - Regenerative Thermal Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 90% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 120 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 1,092 Deg F - Temperature of waste gas out of heat recovery

T fo 228 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.2501 Btu/lb - Deg F Heat Capacity of waste gas - flue gas

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 31,935 scfm - Flow of waste gas

Q af 150 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculation s 31,93 5 scfm Flue Gas

Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0
44 mw CO2 89.5 v % 1097 95.4% 0.24 0.229009 18 mw H2O 10.5 v % 53 4.6% 0.46 0.02106 6
28 mw N2 0 v % 0 0.0% 0.27 0
32 mw O2 0 v % 0 0.0% 0.23 0 Cp Flue Gas 100 v % 1150 100.0% 0.250075

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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# Attachment F

Pneumatic Transport System Gas Heater BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment F - Emission Control Cost AnalysisTable F-1: Cost Summary - Pneumatic Transport System (PTS) Gas HeaterNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?LoTOx70%1.0 2.4 $73,206 $137,201 $57,562 $255,713 None Medium Waste-WaterSelective Catalytic Reduction(SCR)70% 1.0 2.4 $179,922 $160,163 $67,195 $304,757 NH3 Slip Low Catalyst WasteULNB / LNB - FGR56%1.5 1.9 $118,124 $17,477 $9,125 NANone Low NoneSelective Non-CatalyticReduction (SNCR)25% 2.6 0.9 $346,842 $85,477 $100,412NA SNCR is inferiorcontrolNH3 Slip Low NoneBase CaseNA3.4CO Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Thermal OxidizerRecuperative90% 0.4 3.2 $348,272 $183,888 $58,257 NA None High NoneThermal OxidizerRegenerative90% 0.4 3.2 $199,027 $142,871 $45,263 NA None High Solid WasteCatalytic Oxidizer90%0.4 3.2 $361,783 $150,410 $47,651 NANone Medium Catalyst WasteUncontrolled0%3.5VOC Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Thermal OxidizerRecuperative90% 0.02 0.2 $348,272 $183,888 $890,254 NA None High NoneThermal OxidizerRegenerative90% 0.02 0.2 $199,027 $142,871 $691,680 NA None High Solid WasteCatalytic Oxidizer90%0.02 0.2 $361,783 $150,410 $728,179 NANone Low Catalyst WasteUncontrolled0%0.2P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach F - Pneumatic Gas Transport Heater Sept2006 RevisionCost Summary3/6/2007Page 1 of 27

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: PTS Gas Heater Study Year 2005
Emission Unit Number EU 069 & 086 Stack/Vent Number SV 062 & 068 Reference Item Unit Cos t Units Cos t Year Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.051 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.78 $/mgal 0.76 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation

Cooling Water 0.27 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.31 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.64 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.15 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 27.32 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3%
inflation

Hazardous Waste Disposal 273.18 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3%
inflation

Waste Transport 0.55 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycle 1.16 $/ton 1.00 2000 Corus Study for MN Iron and Steel Project Study use $1/ton to cover cost of materials movement

Chemicals & Supplies Lime 25.31 $/ton 24.57 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation Caustic 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.44 Mscf 1.40 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation EPA Urea 179.1 $/ton
A mmonia 0.101 $/lb Reagent #8 $/ton

Catalyst & Replacement Parts SCR Catalyst 140 $/ft 3 Cormetech, Inc., 1/2006 bid CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 Catalyst #4 Catalyst #5

Filter Bags 36.84 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Othe r Sales Tax 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Information A nnual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 93% 2004 Kaar Consulting MSI Cost Model Equipment Life 20 yrs Engineering Estimate Design Capacity 11.52 MMBtu/hr Standardized Flow Rate 2,217 scfm @ 32o F Temperature 495 Deg F Moisture Content 18.1% Actual Flow Rate 4,306 acfm Standardized Flow Rate 2,380 scfm @ 68o F Dry Std Flow Rate 1,949 dscfm @ 68o F

Max Emis Pollutan t Lb/Hr Uncontrolled Conc from Heate r PM10 0.09 0.005 gr/dscf Total Particulates 0.09 0.005 gr/dscf NOx Control Efficiency Calculations Nitrous Oxides (NOx) 0.92 54 ppm 0.40 lb/hr NOx at 0.035 lb NOx/MMBtu Sulfur Dioxide (SO 2 ) 0.024 1 ppm 0.92 lb/hr NOx at 0.08 lb NOx/MMBtu Sulfuric Acid Mist 0.0 ppm 56.3% Control efficiency for LNB/FGR or UNLB @0.035 lb NOx/MMBtu Fluorides 0.0E+00 gr/dscf 70.0% SCR & LoTOX control efficiency Volatile Organic Compounds (VOC) 0.062 10 ppm 20 ppm NOx dry at SCR/LoTOx control efficiency Carbon Monoxide (CO) 0.95 91 ppm 25.0% SNCR control efficiency Lead (Pb) 0.0E+00 gr/dscf 49 ppm NOx dry at SNCR control efficiency 29 ULNB ppm NOx dry Enter this data for each emission uni t 66 Base Case ppm NOx dry Enter data for this study (applies to all units ) 3.4 T/yr NOx Base Case

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Operating Unit: PTS Gas Heater

Emission Unit Number E U 069 & 086 Stack/Vent Number SV 062 & 068 Chemical Engineering Design Capacity 12 MMBtu/hr Standardized Flow Rate 2,217 scfm @ 32o F Chemical Plant Cost Inde x Expected Utilization Rate 93% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 4,306 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 2,380 scfm @ 68o F Dry Std Flow Rate 1,949 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 60,386 Purchased Equipment Total (B) 22% of control device cost (A) 73,369

Installation - Standard Costs 30% of purchased equip cost (B) 22,011 Installation - Site Specific Costs NA Installation Total 22,011 Total Direct Capital Cost, DC 95,380 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 22,744 Total Capital Investment (TCI) = DC + IC 118,124

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,001 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 16,476 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 17,477

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.1 0.3 0.3 - NA Total Particulates 0.1 0.3 0.3 - N A Nitrous Oxides (NOx) 0.9 3.4 56% 1.5 1.9 9,125 Sulfur Dioxide (SO 2 ) 0.0 0.1 0.1 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.1 0.2 0.2 - NA Carbon Monoxide (CO) 0.9 3.5 3.5 - NA Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Coen Burner, January, 2006 cost estimate
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Thermal Oxidizer factor used for low NOx burners because it has the lowest multipiler for installation cost
4 Used 0.6 power law factor to adjust price from bid basis of 50 MMBtu/hr

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 60,386

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 6,039 MN Sales Taxes 6.5% of control device cost (A) 3,925 Freight 5% of control device cost (A) 3,019 Purchased Equipment Total (B) 22% 73,369

Installation

Foundations & supports 8% of purchased equip cost (B) 5,870 Handling & erection 14% of purchased equip cost (B) 10,272 Electrical 4% of purchased equip cost (B) 2,935 Piping 2% of purchased equip cost (B) 1,467 Insulation 1% of purchased equip cost (B) 734 Painting 1% of purchased equip cost (B) 734 Installation Subtotal Standard Expense s 30% 22,011

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 22,011 Total Direct Capital Cost, DC 95,380

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 7,337 Construction & field expenses 5% of purchased equip cost (B) 3,668 Contractor fees 10% of purchased equip cost (B) 7,337 Start-up 2% of purchased equip cost (B) 1,467 Performance test 1% of purchased equip cost (B) 734 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 2,201 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 22,744

Total Capital Investment (TCI) = DC + IC 118,124

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 118,124

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr 318 Supervisor 15% 15% of Operator Costs 48
Maintenance

Maintenance Labor 32.00 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr 318 Maintenance Materials 100% of maintenance labor costs 318 Utilities, Supplies, Replacements & Waste Managemen t

N A N A - NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 1,001

Indirect Operating Costs Overhead 60% of total labor and material costs 601 Administration (2% total capital costs) 2% of total capital costs (TCI) 2,362 Property tax (1% total capital costs) 1% of total capital costs (TCI) 1,181 Insurance (1% total capital costs) 1% of total capital costs (TCI) 1,181 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 11,150 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 16,476

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 17,477

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysi s Table F-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 2 years CRF 0.5531 Rep part cost per unit 650 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 0 19 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 0.0

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 93.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.01 hr/8 hr shift 10 318 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 48 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.01 hr/8 hr shift 10 318 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 318 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-4: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: PTS Gas Heater

Emission Unit Number E U 069 & 086 Stack/Vent Number SV 062 & 068 Design Capacity 12 MMBtu/hr Standardized Flow Rate 2,217 scfm @ 32o F Expected Utilization Rate 93% Temperature 495 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% Annual Interest Rate 7.0% Actual Flow Rate 4,306 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 2,380 scfm @ 68o F Dry Std Flow Rate 1,949 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 22,174 Purchased Equipment Total (B) 22% of control device cost (A) 26,942

Installation - Standard Costs 85% of purchased equip cost (B) 22,901 Installation - Site Specific Costs NA Installation Total 22,901 Total Direct Capital Cost, DC 49,842 Total Indirect Capital Costs, IC 3 5 % of purchased equip cost (B) 9,430 Total Capital Investment (TCI) = DC + IC 73,206

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 97,327 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 39,874 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 137,201

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.1 0.3 0.3 - NA Total Particulates 0.1 0.3 0.3 - N A Nitrous Oxides (NOx) 0.9 3.4 70% 1.0 2.4 57,562 Sulfur Dioxide (SO 2 ) 0.0 0.1 0.1 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.1 0.2 0.2 - NA Carbon Monoxide (CO) 0.9 3.5 3.5 - NA Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Sept 2005 Cost Estimate Procedure from BOC Gases
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Wastewater Treatment Costs provided by Nalco 6/8/06 email for reverse osmosis system, evaporator and crystallizer 6 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-4: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 22,174

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 2,217 MN Sales Taxes 6.5% of control device cost (A) 1,441 Freight 5% of control device cost (A) 1,109 Purchased Equipment Total (B) 22% 26,942

Installation

Foundations & supports 12% of purchased equip cost (B) 3,233 Handling & erection 40% of purchased equip cost (B) 10,777 Electrical 1% of purchased equip cost (B) 269 Piping 30% of purchased equip cost (B) 8,083 Insulation 1% of purchased equip cost (B) 269 Painting 1% of purchased equip cost (B) 269 Installation Subtotal Standard Expense s 85% 22,901

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 22,901 Total Direct Capital Cost, DC 49,842

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 2,694 Construction & field expenses 10% of purchased equip cost (B) 2,694 Contractor fees 10% of purchased equip cost (B) 2,694 Start-up 1% of purchased equip cost (B) 269 Performance test 1% of purchased equip cost (B) 269 Model Studies N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 808 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 9,430 Ozone Generator, Installed Cost 13,934 Total Capital Investment (TCI) = DC + IC 73,206

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 73,206

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 15 kW-hr, 7946 hr/yr, 93% utilization 5,758
NA NA - Water 0.78 $/mgal, 2 gpm, 7946 hr/yr, 93% utilization 747 Cooling Water 0.27 $/mgal, 4 gpm, 7946 hr/yr, 93% utilization 494
NA NA - N A N A - WW Treat R/O 40.10 $/mgal, 2 gpm, 7946 hr/yr, 93% utilization 38,285
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Oxygen 1.44 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization 1,983
NA NA - NA NA - Total Annual Direct Operating Cost s 97,327

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 1,464 Property tax (1% total capital costs) 1% of total capital costs (TCI) 732 Insurance (1% total capital costs) 1% of total capital costs (TCI) 732 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 6,910 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 39,874

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 137,201

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysi s Table F-4: NOx Control - LoTOx - (Low Temperature Oxidation) Wastewater Treating Costs for LoTOx 5
Capital Recovery Factors 76 gpm, R/O System Design Rate Primary Installation 3,740,000 Installed Capital Cost Interest Rate 7.00% 353,030 Capital Recovery Cost Equipment Life 20 years 1,100,000 Operating & Maintenance Cost CRF 0.0944 1,453,030 A nnual Operating Cost 40.10 Wastewater Treatment Cost $/kgal Replacement Parts & Equipment: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 140 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficienc y Hp kW Blower, Scrubber 4,306 10 0.7 - 7.2 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 043 gpm 1 60 0.7 - 0.7 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 2 gpm 1 60 0.7 - 0.0 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
LTO Electric Use 4.5 kW/lb O 3 7

Total 15.4

Reagent Use & Other Operating Costs Ozone Needed 1.8 lb O3/lb NOx 1.7 lb/hr O3 Oxygen Needed 10% wt O2 to O3 conversion 16.5880445 lb/hr O2 186 scfh O2 LTO Cooling Water 150 gal/lb O3 4 gpm Ozone Generator $350 lb O3/day $13,934 Installed Installed cost factor per BOC. Scrubber Cost 10 $/scfm Gas $22,174 Incremental cost per BOC. Need to increase vessel size over standard absorber. Scrubber Outlet Flow 2,614 acfm Scrubber Outlet Temp 120 °F Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf Circulating Water Rate 43 gpm Waste WaterDisch = 5% of circulating water rate = 2 gpm Evap H2O Loss 0 gpm Water Makeup Rate 2 gpm

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 93.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 15.4 kW-hr 113,736 5,758 $/kwh, 15 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 2.2 gpm 955 747 $/mgal, 2 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 4.1 gpm 1,839 494 $/mgal, 4 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization WW Treat R/O 40.10 $/mgal 2.2 gpm 955 38,285 $/mgal, 2 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.2 Mscf/hr 1,375 1,983 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Operating Unit: PTS Gas Heater

Emission Unit Number E U 069 & 086 Stack/Vent Number SV 062 & 068 Design Capacity 12 MMBtu/hr Standardized Flow Rate 2,217 scfm @ 32o F Expected Utilization Rate 93% Temperature 495 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% Annual Interest Rate 7.0% Actual Flow Rate 4,306 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 2,380 scfm @ 68o F Dry Std Flow Rate 1,949 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) N A Purchased Equipment Total (B) 22% of control device cost (A) N A

Installation - Standard Costs 30% of purchased equip cost (B) NA Installation - Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA Total Capital Investment (TCI) = DC + IC 179,922

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 135,739 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 24,423 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 160,163

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.1 0.3 0.3 - NA Total Particulates 0.1 0.3 0.3 - N A Nitrous Oxides (NOx) 0.9 3.4 70% 1.0 2.4 67,195 Sulfur Dioxide (SO 2 ) 0.0 0.1 0.1 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.1 0.2 0.2 - NA Carbon Monoxide (CO) 0.9 3.5 3.5 - NA Lead (Pb) - - 0.0 - N A

Notes & Assumption s

Basis for SCR control cost:
1 The SCR capital investment is from vendor estimates (Babcok Power Inc, 2005).
2 SCR catalyst quote based on information obtained from Cormetech, Inc. It is used for catalyst replacement costs. 3 The total direct and indirect operating costs are based on operation and maintenance costs in the

"Pwr Plt SCR $" tab per EPA correlation of SCR costs for power plants.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) NA

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) N A MN Sales Taxes 6.5% of control device cost (A) N A Freight 5% of control device cost (A) NA Purchased Equipment Total (B) 22% NA

Installation

Foundations & supports 8% of purchased equip cost (B) NA Handling & erection 14% of purchased equip cost (B) NA Electrical 4% of purchased equip cost (B) N A Piping 2% of purchased equip cost (B) NA Insulation 1% of purchased equip cost (B) N A Painting 1% of purchased equip cost (B) N A Installation Subtotal Standard Expense s 30% NA

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) NA Construction & field expenses 5% of purchased equip cost (B) NA Contractor fees 10% of purchased equip cost (B) N A Start-up 2% of purchased equip cost (B) NA Performance test 1% of purchased equip cost (B) NA Model Studies of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC 179,922

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 174,949

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator NA - Supervisor N A - Maintenance

Maintenance Labor NA - Maintenance Materials 100% of maintenance labor costs - Utilities, Supplies, Replacements & Waste Managemen t

N A N A - NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization 1,895
NA NA - Total Annual Direct Operating Cost s 135,739

Indirect Operating Costs Overhead 60% of total labor and material costs 712 Administration (2% total capital costs) 2% of total capital costs (TCI) 3,598 Property tax (1% total capital costs) 1% of total capital costs (TCI) 1,799 Insurance (1% total capital costs) 1% of total capital costs (TCI) 1,799 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 16,514 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 24,423

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 160,163

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysi s Table F-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalys t Estimate amount of catalyst required Equipment Life 3 years Vol. #1 5000 ft3 CRF 0.3811 Flow #1 359,256 acfm Basis SCR Bids for proposed 2001 Taconite Plant Rep part cost per unit 65 $/ft 3 Flow #2 4,306 acfm Amount Required 59.9 ft 3 Vol #2 59.9 ft3 Catalyst Cost 4,324 Cost adjusted for freight & sales tax Installation Labor 649 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 4,973 Zero out if no replacement parts needed A nnualized Cost 1,895

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 4,306 19 0.6 16.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 4,306 23 0.6 19.3 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type Catalyti c (catalytic or thermal) 19.3

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 93.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 0 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 19.3 kW-hr 0 0 $/kwh, 19 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 14676 scfm 0 0 $/mscf, 14,676 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization CO Catalys t 650 $/ft3 0 ft 3 0 1,895 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

EPA SCR Cost Worksheet for Coal Fired Power Plants

Determine Comparable Boiler Size Based on Flue Gas Exhaust Rate stack exhaust flow scfm 2,380 Moisture Content 10% Stack exhaust flow dcfm 1,949 Coal F Factor dscf/MMBtu 10,000 Equivalent Duty MMBtu/hr 12 Est. Power Plant Efficiency 35% Watt per Btu/hr 0.29307 Equivalent Power Plant kW 1,199 Uncontrolled NOx t/yr 3 A nnual Operating Hours 7,946
Uncontrolled NOx lb/MMBtu 0.07

Plant Capacity kW A 1,199 Uncontrolled NOx lb/MMBtu B 0.073 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Total Capital Cost $179,922

D= 75*(300,000((B/1.5)^0.05*(C/100)^0.04/A)^0.35

Plant Capacity kW A 1,199 Capital Cost $/kW D $150.00 Fixed O&M Cost, $/yr E $1,187

E = D*A*0.0066

Plant Capacity kW A 1,199
Uncontrolled NOx lb/MMBtu B 0.073 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Annual Capacity Factor G 0.82 Heat Input MMBtu/hr H 6000 Variable O&M Cost $/yr F $135,739

F = G*(225(0.37*B*H*C/100*8760/2000)*1.005+0.075*D*A*((B/1.5)^0.05*(c/100)^.4)+1.45*A) Note: used worst case factor for catalyst replacement Note: Capital Cost kW is estimate from Tom Robinson @ Babcock Power Inc.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-6: Selective Non-Catalytic Reduction SNCR

Operating Unit: PTS Gas Heater

Emission Unit Number E U 069 & 086 Stack/Vent Number SV 062 & 068 Chemical Engineering Design Capacity 12 MMBtu/hr Standardized Flow Rate 2,217 scfm @ 32o F Chemical Plant Cost Inde x Expected Utilization Rate 93% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 4,306 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 2,380 scfm @ 68o F Dry Std Flow Rate 1,949 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year Direct Capital Costs EPRI Correlation, 1998 $'s 12 25% 0.08 1998 206,649 Purchased Equipment (A) 2005 246,389 Purchased Equipment Total (B) 0% of control device cost (A) 246,389

Installation - Standard Costs 15% of purchased equip cost (B) 44,350 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC 346,842

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 52,738 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 32,739 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 85,477

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.1 0.3 0.3 - NA Total Particulates 0.1 0.3 0.3 - N A Nitrous Oxides (NOx) 0.9 3.4 25% 2.6 0.9 100,412 Sulfur Dioxide (SO 2 ) 0.0 0.1 0.1 - NA
Sulfuric Acid Mist - - 0.0 - NA
Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.1 0.2 0.2 - NA Carbon Monoxide (CO) 0.9 3.5 3.5 - NA Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Cost Estimate from EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 and adjusted for inflation 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 5 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25 6 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29
7 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 8 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
9 No coal ash disposal cost; fuel is natural gas

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-6: Selective Non-Catalytic Reduction SNCR

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 246,389 Instrumentation 10% of control device cost (A) N A MN Sales Taxes 6.5% of control device cost (A) N A Freight 5% of control device cost (A) NA Purchased Equipment Total (A ) 246,389

Indirect Installation

General Facilities 5% of purchased equip cost (A) 12,319 Engineering & Home Office 10% of purchased equip cost (A) 24,639 Process Contingency 5% of purchased equip cost (A) 12,319

Total Indirect Installation Costs (B ) 20% of purchased equip cost (A) 49,278

Project Contingency ( C ) 15% of (A + B) 44,350

Total Plant Cost D A + B + C 340,017

Allowance for Funds During Construction (E ) 0 for SNCR 0

Royalty Allowance (F ) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 6,800

Inventor y Ca p ital Reagent Vol * $/gal 25

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 346,842

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 346,842

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labo r

Operator N A - Supervisor NA - Maintenanc e

Maintenance Total 15.00 % of Total Capital Investment 52,026 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 0 kW-hr, 7946 hr/yr, 93% utilization 8 Natural Gas 6.85 $/mscf, 0 scfh, 7946 hr/yr, 93% utilization 149 Water 0.78 $/mgal, 0 gph, 7946 hr/yr, 93% utilization 1
NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Urea 405.00 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization 554
NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 52,738

Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 32,739 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 32,739

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 85,477

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysi s Table F-6: Selective Non-Catalytic Reduction SNCR

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalys t <- Enter Equipment Name to Get Cost Equipment Life 5 years CRF 0.2439 Rep part cost per unit 140 $/ft 3 Amount Required 12 ft 3 Packing Cost 1,873 Cost adjusted for freight & sales tax Installation Labor 281 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost Equipment Life 2 years CRF 0.0000 Rep part cost per unit 37 $/ft 3 Amount Required 0 Cages Total Rep Parts Cost 0 Cost adjusted for freight & sales tax See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr) Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag. A nnualized Cost 0

Electrical Use NOx in 0.08 lb/MMBtu kW NS R 0.47
Power 0.0

Total 0.0

Reagent Use & Other Operating Costs Urea Use
NOx in 0.08 lb/MMBtu 0 lb/hr Neat Efficiency 25% 50% solution 71.0 lb/ft 3 Density 50% Solution Duty 12 MMBtu/hr 0 lb/hr 0.0 gal/hr Volume 14 day inventory 13 gal $25 Inventory Cost

Water Use 0 gal/hr Inject at 10% solution

Fuel Use 0.0 MMBtu/hr 0.0 mscfh natural gas

A sh Generation 0.0 lb/hr

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 93.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenanc e Maintenance Total 15 % of Total Capital Investment 52,026 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 0.0 kW-hr 157 8 $/kwh, 0 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 0.0 scfh 22 149 $/mscf, 0 scfh, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.2 gph 1 1 $/mgal, 0 gph, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0.0 scfm/kacfm* * 0 0 $/mscf, 0 scfm/kacfm**, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Urea 405 $/ton 0.0002 ton/hr 1 554 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-7: CO/VOC Control - Thermal Oxidizer

Operating Unit: PTS Gas Heater

Emission Unit Number E U 069 & 086 Stack/Vent Number SV 062 & 068 Chemical Engineering Design Capacity 12 MMBtu/hr Standardized Flow Rate 2,217 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 4,306 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 2,380 scfm @ 68o F Dry Std Flow Rate 1,949 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 178,040 Purchased Equipment Total (B) 22% of control device cost (A) 216,318

Installation - Standard Costs 30% of purchased equip cost (B) 64,895 Installation - Site Specific Costs NA
Installation Total 64,895 Total Direct Capital Cost, DC 281,214 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 67,059 Total Capital Investment (TCI) = DC + IC 348,272

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 107,047 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 76,841 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 183,888

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.1 0.3 0.3 - NA Total Particulates 0.1 0.3 0.3 - N A Nitrous Oxides (NOx) 0.9 3.4 3.4 - NA Sulfur Dioxide (SO 2 ) 0.0 0.1 0.1 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.1 0.2 90% 0.0 0.2 890,254 Carbon Monoxide (CO) 0.9 3.5 90% 0.4 3.2 58,257 Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Cost Estimate per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 and adjusted for inflation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-7: CO/VOC Control - Thermal Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 178,040

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 17,804 MN Sales Taxes 6.5% of control device cost (A) 11,573 Freight 5% of control device cost (A) 8,902 Purchased Equipment Total (B) 22% 216,318

Installation

Foundations & supports 8% of purchased equip cost (B) 17,305 Handling & erection 14% of purchased equip cost (B) 30,285 Electrical 4% of purchased equip cost (B) 8,653 Piping 2% of purchased equip cost (B) 4,326 Insulation 1% of purchased equip cost (B) 2,163 Painting 1% of purchased equip cost (B) 2,163 Installation Subtotal Standard Expenses 30% 64,895

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 64,895 Total Direct Capital Cost, DC 281,214

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 21,632 Construction & field expenses 5% of purchased equip cost (B) 10,816 Contractor fees 10% of purchased equip cost (B) 21,632 Start-up 2% of purchased equip cost (B) 4,326 Performance test 1% of purchased equip cost (B) 2,163 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 6,490 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 67,059

Total Capital Investment (TCI) = DC + IC 348,272

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 348,272

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 16 kW-hr, 7946 hr/yr, 93% utilization 5,969 Natural Gas 6.85 $/mscf, 17 scfm, 7946 hr/yr, 93% utilization 51,018
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 107,047

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 6,965 Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,483 Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,483 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 32,874 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 76,841

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 183,888

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysi s Table F-7: CO/VOC Control - Thermal Oxidizer

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years
CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 650 $/ft 3 Amount Required 39 ft 3
Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 4,306 19 0.6 16.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 4,306 23 0.6 19.3 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 16.0

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 93.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 16.0 kW-hr 117,904 5,969 $/kwh, 16 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 17 scfm 7,448 51,018 $/mscf, 17 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-7: CO/VOC Control - Thermal Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 495 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 989 Deg F - Temperature of waste gas out of heat recovery

T fo 707 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 2,380 scfm - Flow of waste gas

Q af 17 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 2,396 scfm Flue Gas Cost in 1989 $'s $149,324 Current Cost Using CHE Plant Cost Index $178,040
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerator s (EPA 453/B-96-001)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-8: CO/VOC Control - Catalytic Oxidizer

Operating Unit: PTS Gas Heater

Emission Unit Number E U 069 & 086 Stack/Vent Number SV 062 & 068 Chemical Engineering Design Capacity 12 MMBtu/hr Standardized Flow Rate 2,217 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 4,306 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 2,380 scfm @ 68o F Dry Std Flow Rate 1,949 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 184,946 Purchased Equipment Total (B) 22% of control device cost (A) 224,710

Installation - Standard Costs 30% of purchased equip cost (B) 67,413 Installation - Site Specific Costs NA
Installation Total 67,413 Total Direct Capital Cost, DC 292,123 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 69,660 Total Capital Investment (TCI) = DC + IC 361,783

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 72,617 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 77,793 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 150,410

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.1 0.3 0.3 - NA Total Particulates 0.1 0.3 0.3 - N A Nitrous Oxides (NOx) 0.9 3.4 3.4 - NA Sulfur Dioxide (SO 2 ) 0.0 0.1 0.1 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides 0.0E+00 0.0E+00 0.0E+00 - NA Volatile Organic Compounds (VOC) 0.1 0.2 90% 2.3E-02 0.2 728,179 Carbon Monoxide (CO) 0.9 3.5 90% 0.4 3.2 47,651 Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 A ug 28, 2005 Catalyst Cost Estimate from Englehard Catalyst & EPA Control Cost Manual Section 3.2 Chapter 2 and adjusted for in flation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-8: CO/VOC Control - Catalytic Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 184,946

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 18,495 MN Sales Taxes 6.5% of control device cost (A) 12,022 Freight 5% of control device cost (A) 9,247 Purchased Equipment Total (B) 22% 224,710

Installation

Foundations & supports 8% of purchased equip cost (B) 17,977 Handling & erection 14% of purchased equip cost (B) 31,459 Electrical 4% of purchased equip cost (B) 8,988 Piping 2% of purchased equip cost (B) 4,494 Insulation 1% of purchased equip cost (B) 2,247 Painting 1% of purchased equip cost (B) 2,247 Installation Subtotal Standard Expenses 30% 67,413

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 67,413 Total Direct Capital Cost, DC 292,123

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 22,471 Construction & field expenses 5% of purchased equip cost (B) 11,235 Contractor fees 10% of purchased equip cost (B) 22,471 Start-up 2% of purchased equip cost (B) 4,494 Performance test 1% of purchased equip cost (B) 2,247 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 6,741 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 69,660

Total Capital Investment (TCI) = DC + IC 361,783

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 352,629

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 19 kW-hr, 7946 hr/yr, 93% utilization 7,225 Natural Gas 6.85 $/mscf, 4 scfm, 7946 hr/yr, 93% utilization 13,100
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization 2,233
NA NA - Total Annual Direct Operating Cost s 72,617

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 7,236 Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,618 Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,618 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 33,286 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 77,793

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 150,410

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysi s Table F-8: CO/VOC Control - Catalytic Oxidizer

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years
CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 5 years
CRF 0.2439
Rep part cost per unit 3000 $/ft 3 Amount Required 2 ft 3
Catalyst Cost 7,960 Cost adjusted for freight & sales tax Installation Labor 1,194 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 9,154 Zero out if no replacement parts needed
Annualized Cost 2,233

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 4,306 19 0.6 16.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 4,306 23 0.6 19.3 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type catalytic (catalytic or thermal) 19.3

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 93.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 19.3 kW-hr 142,726 7,225 $/kwh, 19 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 4 scfm 1,912 13,100 $/mscf, 4 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization CO Catalys t 650 $/ft3 0 ft 3 0 2,233 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysi s Table F-8: CO/VOC Control - Catalytic Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 495 Deg F - Temperature of waste gas into heat recovery
T fi 600 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 569 Deg F - Temperature of waste gas out of heat recovery

T fo 527 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 2,380 scfm - Flow of waste gas

Q af 4 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 2,384 scfm Flue Gas Cost in 1989 $'s $149,129 Current Cost Using CHE Plant Cost Index $177,807
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerator s (EPA 453/B-96-001)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-9: CO/VOC Control - Regenerative Thermal Oxidizer

Operating Unit: PTS Gas Heater

Emission Unit Number EU 069 & 086 Stack/Vent Number SV 062 & 068 Chemical Engineering Design Capacity 12 MMBtu/hr Standardized Flow Rate 2,217 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.1% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 4,306 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 2,380 scfm @ 68o F Dry Std Flow Rate 1,949 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 3 101,744 Purchased Equipment Total (B) 22% of control device cost (A) 123,619

Installation - Standard Costs 30% of purchased equip cost (B) 37,086 Installation - Site Specific Costs NA
Installation Total 37,086 Total Direct Capital Cost, DC 160,705 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 38,322 Total Capital Investment (TCI) = DC + IC 199,027

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 86,087 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 56,784 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 142,871

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.1 0.3 0.3 - NA Total Particulates 0.1 0.3 0.3 - N A Nitrous Oxides (NOx) 0.9 3.4 3.4 - NA Sulfur Dioxide (SO 2 ) 0.0 0.1 0.1 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides - - 0.0 - NA Volatile Organic Compounds (VOC) 0.1 0.2 90% 0.0 0.2 691,680 Carbon Monoxide (CO) 0.9 3.5 90% 0.4 3.2 45,263 Lead (Pb) - - 0.0 - N A

Notes & Assumption s 1 Cost Estimate per L & E America (TANN Corp), Aug 1, 2006 email
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Cost Estimate per Tann Corporation, July 2006
4 Used 0.6 power law factor to adjust price from bid basis of 100,000 scfm

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-9: CO/VOC Control - Regenerative Thermal Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 101,744

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 10,174 MN Sales Taxes 6.5% of control device cost (A) 6,613 Freight 5% of control device cost (A) 5,087 Purchased Equipment Total (B) 22% 123,619

Installation

Foundations & supports 8% of purchased equip cost (B) 9,890 Handling & erection 14% of purchased equip cost (B) 17,307 Electrical 4% of purchased equip cost (B) 4,945 Piping 2% of purchased equip cost (B) 2,472 Insulation 1% of purchased equip cost (B) 1,236 Painting 1% of purchased equip cost (B) 1,236 Installation Subtotal Standard Expenses 30% 37,086

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 37,086 Total Direct Capital Cost, DC 160,705

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 12,362 Construction & field expenses 5% of purchased equip cost (B) 6,181 Contractor fees 10% of purchased equip cost (B) 12,362 Start-up 2% of purchased equip cost (B) 2,472 Performance test 1% of purchased equip cost (B) 1,236 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 3,709 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 38,322

Total Capital Investment (TCI) = DC + IC 199,027

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 199,027

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 19 kW-hr, 7946 hr/yr, 93% utilization 7,225 Natural Gas 6.85 $/mscf, 9 scfm, 7946 hr/yr, 93% utilization 28,802
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 86,087

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 3,981 Property tax (1% total capital costs) 1% of total capital costs (TCI) 1,990 Insurance (1% total capital costs) 1% of total capital costs (TCI) 1,990 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 18,787 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 56,784

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 142,871

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysi s Table F-9: CO/VOC Control - Regenerative Thermal Oxidizer

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years
CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 2 years
CRF 0.0000
Rep part cost per unit 650 $/ft 3 Amount Required 0 ft 3
Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 4,306 19 0.6 16.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 4,306 23 0.6 19.3 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type catalytic (catalytic or thermal) 19.3

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 93.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 19.3 kW-hr 142,726 7,225 $/kwh, 19 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 6.85 $/mscf 9 scfm 4,205 28,802 $/mscf, 9 scfm, 7946 hr/yr, 93% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 93% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 93% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 93% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 93% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 93% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment F - Emission Control Cost Analysis Table F-9: CO/VOC Control - Regenerative Thermal Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 90% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 495 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 1,130 Deg F - Temperature of waste gas out of heat recovery

T fo 566 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 2,380 scfm - Flow of waste gas

Q af 9 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 2,380 scfm Flue Gas

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerator s (EPA 453/B-96-001)

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# Attachment G

Degasser Boiler BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment G - Emission Control Cost AnalysisTable G-1: Cost Summary - Degasser BoilerNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?LoTOx70%2.6 6.2 $673,564 $302,396 $49,032 $216,675 None Medium Waste-WaterSelective Catalytic Reduction(SCR)70% 2.6 6.2 $1,683,175 $356,433 $57,793 $261,280 NH3 Slip Low Catalyst WasteULNB / LNB-FGR56%3.9 5.0 $285,011 $39,905 $8,052 NANone Low NoneSelective Non-CatalyticReduction (SNCR)25% 6.6 2.2 $861,742 $212,444 $96,450NA SNCR is inferiorcontrolNH3 Slip Low NoneBase CaseNA8.8CO Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Thermal OxidizerRecuperative90% 0.9 8.2 $608,902 $322,239 $39,455 NA None High NoneThermal OxidizerRegenerative90% 0.9 8.2 $760,713 $283,680 $34,733 NA None Medium Solid WasteCatalytic Oxidizer90%0.9 8.2 $738,592 $249,321 $30,526 NANone Medium Catalyst WasteUncontrolled0%9.1VOC Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Thermal OxidizerRecuperative90% 0.06 0.5 $608,902 $322,239 $602,923 NA None High NoneThermal OxidizerRegenerative90% 0.06 0.5 $760,713 $283,680 $530,777 NA None Medium Solid WasteCatalytic Oxidizer90%0.06 0.5 $738,592 $249,321 $466,489 NANone Medium Catalyst WasteUncontrolled0%0.6P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach G - Degasser Boiler Mar 2007 RevisionCost Summary3/6/2007Page 1 of 27

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Degasser Boiler Study Year 2005
Emission Unit Number EU 137 Stack/Vent Number SV 050 Reference Item Unit Cos t Units Cos t Year Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.051 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.78 $/mgal 0.76 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation

Cooling Water 0.27 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.31 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.64 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.15 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 27.32 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3%
inflation

Hazardous Waste Disposal 273.18 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3%
inflation

Waste Transport 0.55 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycle 1.16 $/ton 1.00 2000 Corus Study for MN Iron and Steel Project Study use $1/ton to cover cost of materials movement

Chemicals & Supplies Lime 25.31 $/ton 24.57 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation Caustic 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.44 Mscf 1.40 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation EPA Urea 179.1 $/ton
A mmonia 0.101 $/lb Reagent #8 $/ton

Catalyst & Replacement Parts SCR Catalyst 140 $/ft 3 Cormetech, Inc., 1/2006 bid CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 Catalyst #4 Catalyst #5

Filter Bags 36.84 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Othe r Sales Tax 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Information A nnual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 28% 2004 Kaar Consulting MSI Cost Model Equipment Life 20 yrs Engineering Estimate Design Capacity 99.0 MMBtu/hr Standardized Flow Rate 20,719 scfm @ 32o F Temperature 495 Deg F Moisture Content 18.0% Actual Flow Rate 40,237 acfm Standardized Flow Rate 22,235 scfm @ 68o F Dry Std Flow Rate 18,233 dscfm @ 68o F

Max Emis Uncontrolled Conc from Reformer Pollutan t Lb/Hr prior to eductor PM10 0.74 0.005 gr/dscf Total Particulates 0.74 0.005 gr/dscf NOx Control Efficiency Calculations Nitrous Oxides (NOx) 7.92 61 ppmd 3.47 lb/hr NOx at 0.035 lb NOx/MMBtu Sulfur Dioxide (SO 2 ) 0.058 0 ppmd 7.92 lb/hr NOx at 0.08 lb NOx/MMBtu Sulfuric Acid Mist 0.0 ppm 56.3% Control efficiency for LNB/FGR or UNLB @0.035 lb NOx/MMBtu Fluorides 0.0E+00 gr/dscf 70.0% SCR & LoTOX control efficiency Volatile Organic Compounds (VOC) 0.53 12 ppmd 18 ppm NOx dry at SCR/LoTOx control efficiency Carbon Monoxide (CO) 8.16 84 ppmw 25.0% SNCR control efficiency Lead (Pb) 0.0E+00 gr/dscf 45 ppm NOx dry at SNCR control efficiency 27 ULNB ppm NOx dry Enter this data for each emission uni t 61 Base Case ppm NOx dry Enter data for this study (applies to all units ) 8.8 T/yr NOx Base Case

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Operating Unit: Degasser Boiler

Emission Unit Number EU 137 Stack/Vent Number SV 050 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 20,719 scfm @ 32o F Chemical Plant Cost Inde x Expected Utilization Rate 28% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 40,237 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 22,235 scfm @ 68o F Dry Std Flow Rate 18,233 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 145,700 Purchased Equipment Total (B) 22% of control device cost (A) 177,026

Installation - Standard Costs 30% of purchased equip cost (B) 53,108 Installation - Site Specific Costs NA Installation Total 53,108 Total Direct Capital Cost, DC 230,133 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 54,878 Total Capital Investment (TCI) = DC + IC 285,011

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,001 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 38,904 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 39,905

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 0.8 0.8 - NA Total Particulates 0.7 0.8 0.8 - N A Nitrous Oxides (NOx) 7.9 8.8 56% 3.9 5.0 8,052 Sulfur Dioxide (SO 2 ) 0.1 0.1 0.1 - NA
Sulfuric Acid Mist - - - - NA Fluorides - - - - NA Volatile Organic Compounds (VOC) 0.5 0.6 0.6 - NA Carbon Monoxide (CO) 8.2 9.1 9.1 - NA Lead (Pb) - - - - N A

Notes & Assumption s 1 Coen Burner, January, 2006 cost estimate
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Thermal Oxidizer factor used for low NOx burners because it has the lowest multipiler for installation cost

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 145,700

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 14,570 MN Sales Taxes 6.5% of control device cost (A) 9,471 Freight 5% of control device cost (A) 7,285 Purchased Equipment Total (B) 22% 177,026

Installation

Foundations & supports 8% of purchased equip cost (B) 14,162 Handling & erection 14% of purchased equip cost (B) 24,784 Electrical 4% of purchased equip cost (B) 7,081 Piping 2% of purchased equip cost (B) 3,541 Insulation 1% of purchased equip cost (B) 1,770 Painting 1% of purchased equip cost (B) 1,770 Installation Subtotal Standard Expense s 30% 53,108

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 53,108 Total Direct Capital Cost, DC 230,133

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 17,703 Construction & field expenses 5% of purchased equip cost (B) 8,851 Contractor fees 10% of purchased equip cost (B) 17,703 Start-up 2% of purchased equip cost (B) 3,541 Performance test 1% of purchased equip cost (B) 1,770 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 5,311 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 54,878

Total Capital Investment (TCI) = DC + IC 285,011

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 285,011

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr 318 Supervisor 15% 15% of Operator Costs 48
Maintenance

Maintenance Labor 32.00 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr 318 Maintenance Materials 100% of maintenance labor costs 318 Utilities, Supplies, Replacements & Waste Managemen t

N A N A - NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 1,001

Indirect Operating Costs Overhead 60% of total labor and material costs 601 Administration (2% total capital costs) 2% of total capital costs (TCI) 5,700 Property tax (1% total capital costs) 1% of total capital costs (TCI) 2,850 Insurance (1% total capital costs) 1% of total capital costs (TCI) 2,850 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 26,903 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 38,904

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 39,905

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-3: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 2 years CRF 0.5531 Rep part cost per unit 650 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 0 19 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 0.0

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 28.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.01 hr/8 hr shift 10 318 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 48 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.01 hr/8 hr shift 10 318 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 318 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 7946 hr/yr, 28% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 28% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 28% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 28% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 28% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 28% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-4: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Degasser Boiler

Emission Unit Number EU 137 Stack/Vent Number SV 050 Design Capacity 99 MMBtu/hr Standardized Flow Rate 20,719 scfm @ 32o F Expected Utilization Rate 28% Temperature 495 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.0% Annual Interest Rate 7.0% Actual Flow Rate 40,237 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 22,235 scfm @ 68o F Dry Std Flow Rate 18,233 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 207,188 Purchased Equipment Total (B) 22% of control device cost (A) 251,733

Installation - Standard Costs 85% of purchased equip cost (B) 213,973 Installation - Site Specific Costs NA Installation Total 213,973 Total Direct Capital Cost, DC 465,707 Total Indirect Capital Costs, IC 3 5 % of purchased equip cost (B) 88,107 Total Capital Investment (TCI) = DC + IC 673,564

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 181,838 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 120,558 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 302,396

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 0.8 0.8 - NA Total Particulates 0.7 0.8 0.8 - N A Nitrous Oxides (NOx) 7.9 8.8 70% 2.6 6.2 49,032 Sulfur Dioxide (SO 2 ) 0.1 0.1 0.1 - NA
Sulfuric Acid Mist - - - - NA Fluorides - - - - NA Volatile Organic Compounds (VOC) 0.5 0.6 0.6 - NA Carbon Monoxide (CO) 8.2 9.1 9.1 - NA Lead (Pb) - - - - N A

Notes & Assumption s 1 Sept 2005 Cost Estimate Procedure from BOC Gases
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
3 Liquid/Gas ratio = 10 L/G = Gal/1,000 acf
4 Water Makeup Rate/Wastewater Discharge = 20% of circulating water rate 5 Wastewater Treatment Costs provided by Nalco 6/8/06 email for reverse osmosis system, evaporator and crystallizer 6 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-4: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 207,188

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 20,719 MN Sales Taxes 6.5% of control device cost (A) 13,467 Freight 5% of control device cost (A) 10,359 Purchased Equipment Total (B) 22% 251,733

Installation

Foundations & supports 12% of purchased equip cost (B) 30,208 Handling & erection 40% of purchased equip cost (B) 100,693 Electrical 1% of purchased equip cost (B) 2,517 Piping 30% of purchased equip cost (B) 75,520 Insulation 1% of purchased equip cost (B) 2,517 Painting 1% of purchased equip cost (B) 2,517 Installation Subtotal Standard Expense s 85% 213,973

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 213,973 Total Direct Capital Cost, DC 465,707

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 25,173 Construction & field expenses 10% of purchased equip cost (B) 25,173 Contractor fees 10% of purchased equip cost (B) 25,173 Start-up 1% of purchased equip cost (B) 2,517 Performance test 1% of purchased equip cost (B) 2,517 Model Studies N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 7,552 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 88,107 Ozone Generator, Installed Cost 119,750 Total Capital Investment (TCI) = DC + IC 673,564

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 673,564

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 138 kW-hr, 7946 hr/yr, 28% utilization 15,567
NA NA - Water 0.78 $/mgal, 20 gpm, 7946 hr/yr, 28% utilization 2,102 Cooling Water 0.27 $/mgal, 36 gpm, 7946 hr/yr, 28% utilization 1,278
NA NA - N A N A - WW Treat R/O 40.10 $/mgal, 20 gpm, 7946 hr/yr, 28% utilization 107,699
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Oxygen 1.44 Mscf, 2 Mscf/hr, 7946 hr/yr, 28% utilization 5,131
NA NA - NA NA - Total Annual Direct Operating Cost s 181,838

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 13,471 Property tax (1% total capital costs) 1% of total capital costs (TCI) 6,736 Insurance (1% total capital costs) 1% of total capital costs (TCI) 6,736 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 63,580 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 120,558

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 302,396

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-4: NOx Control - LoTOx - (Low Temperature Oxidation) Wastewater Treating Costs for LoTOx 5
Capital Recovery Factors 76 gpm, R/O System Design Rate Primary Installation 3,740,000 Installed Capital Cost Interest Rate 7.00% 353,030 Capital Recovery Cost Equipment Life 20 years 1,100,000 Operating & Maintenance Cost CRF 0.0944 1,453,030 A nnual Operating Cost 40.10 Wastewater Treatment Cost $/kgal Replacement Parts & Equipment: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 140 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficienc y Hp kW Blower, Scrubber 40,237 10 0.7 - 67.3 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 402 gpm 1 60 0.7 - 6.5 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 20 gpm 1 60 0.7 - 0.3 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
LTO Electric Use 4.5 kW/lb O 3 64

Total 138.2

Reagent Use & Other Operating Costs Ozone Needed 1.8 lb O3/lb NOx 14.3 lb/hr O3 Oxygen Needed 10% wt O2 to O3 conversion 142.56 lb/hr O2 1,599 scfh O2 LTO Cooling Water 150 gal/lb O3 36 gpm Ozone Generator $350 lb O3/day $119,750 Installed Installed cost factor per BOC. Scrubber Cost 10 $/scfm Gas $207,188 Incremental cost per BOC. Need to increase vessel size over standard absorber. Scrubber Outlet Flow 24,425 acfm Scrubber Outlet Temp 120 °F Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf Circulating Water Rate 402 gpm Waste WaterDisch = 5% of circulating water rate = 20 gpm Evap H2O Loss 0 gpm Water Makeup Rate 20 gpm

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 28.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 138.2 kW-hr 307,507 15,567 $/kwh, 138 kW-hr, 7946 hr/yr, 28% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 28% utilization Water 0.78 $/mgal 20.1 gpm 2,686 2,102 $/mgal, 20 gpm, 7946 hr/yr, 28% utilization Cooling Water 0.27 $/mgal 35.6 gpm 4,758 1,278 $/mgal, 36 gpm, 7946 hr/yr, 28% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 28% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization WW Treat R/O 40.10 $/mgal 20.1 gpm 2,686 107,699 $/mgal, 20 gpm, 7946 hr/yr, 28% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Oxygen 1.442 Mscf 1.6 Mscf/hr 3,558 5,131 Mscf, 2 Mscf/hr, 7946 hr/yr, 28% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 28% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 28% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Operating Unit: Degasser Boiler

Emission Unit Number EU 137 Stack/Vent Number SV 050 Design Capacity 99 MMBtu/hr Standardized Flow Rate 20,719 scfm @ 32o F Expected Utilization Rate 28% Temperature 495 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.0% Annual Interest Rate 7.0% Actual Flow Rate 40,237 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 22,235 scfm @ 68o F Dry Std Flow Rate 18,233 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) N A Purchased Equipment Total (B) 22% of control device cost (A) N A

Installation - Standard Costs 30% of purchased equip cost (B) NA Installation - Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA Total Capital Investment (TCI) = DC + IC 1,683,175

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 127,947 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 228,486 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 356,433

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 0.8 0.8 - NA Total Particulates 0.7 0.8 0.8 - N A Nitrous Oxides (NOx) 7.9 8.8 70% 2.6 6.2 57,793 Sulfur Dioxide (SO 2 ) 0.1 0.1 0.1 - NA
Sulfuric Acid Mist - - - - NA Fluorides - - - - NA Volatile Organic Compounds (VOC) 0.5 0.6 0.6 - NA Carbon Monoxide (CO) 8.2 9.1 9.1 - NA Lead (Pb) - - - - N A

Notes & Assumption s

Basis for SCR control cost:
1 The SCR capital investment is from vendor estimates (Babcok Power Inc, 2005).
2 SCR catalyst quote based on information obtained from Cormetech, Inc. It is used for catalyst replacement costs. 3 The total direct and indirect operating costs are based on operation and maintenance costs in the

"Pwr Plt SCR $" tab per EPA correlation of SCR costs for power plants.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) NA

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) N A MN Sales Taxes 6.5% of control device cost (A) N A Freight 5% of control device cost (A) NA Purchased Equipment Total (B) 22% NA

Installation

Foundations & supports 8% of purchased equip cost (B) NA Handling & erection 14% of purchased equip cost (B) NA Electrical 4% of purchased equip cost (B) N A Piping 2% of purchased equip cost (B) NA Insulation 1% of purchased equip cost (B) N A Painting 1% of purchased equip cost (B) N A Installation Subtotal Standard Expense s 30% NA

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) NA Construction & field expenses 5% of purchased equip cost (B) NA Contractor fees 10% of purchased equip cost (B) N A Start-up 2% of purchased equip cost (B) NA Performance test 1% of purchased equip cost (B) NA Model Studies of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC 1,683,175

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 1,636,709

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator NA - Supervisor N A - Maintenance

Maintenance Labor NA - Maintenance Materials 100% of maintenance labor costs - Utilities, Supplies, Replacements & Waste Managemen t

N A N A - NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 28% utilization 17,706
NA NA - Total Annual Direct Operating Cost s 127,947

Indirect Operating Costs Overhead 60% of total labor and material costs 6,665 Administration (2% total capital costs) 2% of total capital costs (TCI) 33,663 Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,832 Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,832 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 154,494 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 228,486

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 356,433

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalys t Estimate amount of catalyst required Equipment Life 3 years Vol. #1 5000 ft3 CRF 0.3811 Flow #1 359,256 acfm Basis SCR Bids for proposed 2001 Taconite Plant Rep part cost per unit 65 $/ft 3 Flow #2 40,237 acfm Amount Required 560.0 ft 3 Vol #2 560.0 ft3 Catalyst Cost 40,405 Cost adjusted for freight & sales tax Installation Labor 6,061 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 46,466 Zero out if no replacement parts needed A nnualized Cost 17,706

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 40,237 19 0.6 149.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 40,237 23 0.6 180.5 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type Catalyti c (catalytic or thermal) 180.5

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 28.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 0 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 180.5 kW-hr 0 0 $/kwh, 180 kW-hr, 7946 hr/yr, 28% utilization Natural Gas 6.85 $/mscf 14676 scfm 0 0 $/mscf, 14,676 scfm, 7946 hr/yr, 28% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 28% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 28% utilization CO Catalys t 650 $/ft3 0 ft 3 0 17,706 $/ft3, 0 ft3, 7946 hr/yr, 28% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 28% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-5: Selective Catalytic Reduction - Basis Power Plant Installed Cost

EPA SCR Cost Worksheet for Coal Fired Power Plants

Determine Comparable Boiler Size Based on Flue Gas Exhaust Rate stack exhaust flow scfm 22,235 Moisture Content 10% Stack exhaust flow dcfm 18,233 Coal F Factor dscf/MMBtu 10,000 Equivalent Duty MMBtu/hr 109 Est. Power Plant Efficiency 35% Watt per Btu/hr 0.29307 Equivalent Power Plant kW 11,221 Uncontrolled NOx t/yr 9 A nnual Operating Hours 8,000
Uncontrolled NOx lb/MMBtu 0.020

Plant Capacity kW A 11,221 Uncontrolled NOx lb/MMBtu B 0.020 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Total Capital Cost $1,683,175

D= 75*(300,000((B/1.5)^0.05*(C/100)^0.04/A)^0.35

Plant Capacity kW A 11,221 Capital Cost $/kW D $150.00 Fixed O&M Cost, $/yr E $11,109

E = D*A*0.0066

Plant Capacity kW A 11,221
Uncontrolled NOx lb/MMBtu B 0.02 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Annual Capacity Factor G 0.82 Heat Input MMBtu/hr H 6000 Variable O&M Cost $/yr F $127,947

F = G*(225(0.37*B*H*C/100*8760/2000)*1.005+0.075*D*A*((B/1.5)^0.05*(c/100)^.4)+1.45*A) Note: used worst case factor for catalyst replacement Note: Capital Cost kW is estimate from Tom Robinson @ Babcock Power Inc.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-6: Selective Non-Catalytic Reduction SNCR

Operating Unit: Degasser Boiler

Emission Unit Number EU 137 Stack/Vent Number SV 050 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 20,719 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rat e 28% Temperature 495 Deg F 1998/199 9 390 Expected Annual Hours of Operatio n 7,94 6 Hours Moisture Conten t 18.0% 200 5 465 Annual Interest Rate 7.0% Actual Flow Rate 40,237 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 22,23 5 scfm @ 68o F Dry Std Flow Rat e 18,23 3 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year Direct Capital Costs EPRI Correlation, 1998 $' s 99 25% 0.08 1998 513,33 5 Purchased Equipment (A ) 200 5 612,05 3 Purchased Equipment Total (B ) 0% of control device cost (A ) 612,05 3

Installation - Standard Costs 15% of purchased equip cost (B) 110,170 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC 861,742

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 131,102 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 81,342 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 212,44 4

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 0.7 0.8 0.8 - NA Total Particulate s 0.7 0.8 0.8 - N A Nitrous Oxides (NOx) 7.9 8.8 25% 6.6 2.2 96,45 0 Sulfur Dioxide (SO 2 ) 0.1 0.1 0.1 - NA

Sulfuric Acid Mist - - - - NA
Fluorides - - - - NA Volatile Organic Compounds (VOC) 0.5 0.6 0.6 - NA Carbon Monoxide (CO) 8.2 9.1 9.1 - NA Lead (Pb) - - - - N A

Notes & Assumptions
1 Cost Estimate from EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 and adjusted for inflation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.1 9
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 5 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25
6 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29
7 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 8 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.2
9 No coal ash disposal cost; fuel is natural gas

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-6: Selective Non-Catalytic Reduction SNCR

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 612,053 Instrumentation 10% of control device cost (A ) N A MN Sales Taxes 6.5% of control device cost (A ) N A Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 612,05 3

Indirect Installation

General Facilities 5% of purchased equip cost (A) 30,603 Engineering & Home Office 10% of purchased equip cost (A) 61,205 Process Contingenc y 5% of purchased equip cost (A ) 30,60 3

Total Indirect Installation Costs (B ) 20% of purchased equip cost (A ) 122,411

Project Contingency ( C) 15% of (A + B) 110,17 0

Total Plant Cost D A + B + C 844,633

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 16,89 3

Inventory Capital Reagent Vol * $/gal 216

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 861,74 2

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 861,74 2

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operato r N A - Supervisor NA - Maintenance

Maintenance Total 15.00 % of Total Capital Investment 129,261 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 0 kW-hr, 7946 hr/yr, 28% utilizatio n 21 Natural Gas 6.85 $/mscf, 0 scfh, 7946 hr/yr, 28% utilization 385 Water 0.78 $/mgal, 2 gph, 7946 hr/yr, 28% utilization 3
NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Urea 405.00 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization 1,432
NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 131,10 2

Indirect Operating Costs

Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 81,342 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 81,34 2

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 212,44 4

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-6: Selective Non-Catalytic Reduction SNC R

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.094 4

Replacement Catalyst <- Enter Equipment Name to Get Cost Equipment Life 5 years CRF 0.243 9 Rep part cost per unit 140 $/ft 3
Amount Required 12 ft 3 Packing Cost 1,873 Cost adjusted for freight & sales tax Installation Labo r 281 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement )
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cos t 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cos t Equipment Life 2 years CRF 0.0000 Rep part cost per unit 37 $/ft 3 Amount Required 0 Cages Total Rep Parts Cost 0 Cost adjusted for freight & sales tax See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr) Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag. A nnualized Cos t 0

Electrical Use NOx in 0.08 lb/MMBtu kW NSR 0.47
Power 0.2

Total 0.2

Reagent Use & Other Operating Costs Urea Use

NOx in 0.08 lb/MMBtu 2 lb/hr Neat Efficiency 25% 50% solution 71.0 lb/ft 3 Density 50% Solution Duty 99 MMBtu/hr 3 lb/hr 0.3 gal/hr Volume 14 day inventory 113 gal $216 Inventory Cost

Water Use 2 gal/hr Inject at 10% solution

Fuel Use 0.0 MMBtu/hr 0.0 mscfh natural gas

A sh Generatio n 0.2 lb/hr

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 129,261 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 0.2 kW-hr 407 21 $/kwh, 0 kW-hr, 7946 hr/yr, 28% utilization Natural Gas 6.85 $/mscf 0.0 scfh 56 385 $/mscf, 0 scfh, 7946 hr/yr, 28% utilization Water 0.78 $/mgal 1.5 gph 3 3 $/mgal, 2 gph, 7946 hr/yr, 28% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilizatio n Comp Air 0.31 $/mscf 0.0 scfm/kacfm* * 0 0 $/mscf, 0 scfm/kacfm**, 7946 hr/yr, 28% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Lime 25.30998 4 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilizatio n Urea 405 $/ton 0.0016 ton/hr 4 1,432 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 28% utilization SCR Catalys t 140 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 28% utilizatio n Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost facto r

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-7: CO/VOC Control - Thermal Oxidizer

Operating Unit: Degasser Boiler

Emission Unit Number EU 137 Stack/Vent Number SV 050 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 20,719 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 28% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 40,237 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 22,23 5 scfm @ 68o F Dry Std Flow Rate 18,233 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 311,276 Purchased Equipment Total (B) 22% of control device cost (A) 378,200

Installation - Standard Costs 30% of purchased equip cost (B) 113,460 Installation - Site Specific Costs NA
Installation Total 113,460 Total Direct Capital Cost, DC 491,660 Total Indirect Capital Costs, IC 31 % of purchased equip cost (B ) 117,24 2 Total Capital Investment (TCI) = DC + IC 608,90 2

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 210,371 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 111,868 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 322,23 9

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 0.7 0.8 0.8 - NA Total Particulate s 0.7 0.8 0.8 - N A Nitrous Oxides (NOx) 7.9 8.8 8.8 - NA Sulfur Dioxide (SO 2 ) 0.1 0.1 0.1 - NA
Sulfuric Acid Mist - - - - NA Fluorides - - - - NA Volatile Organic Compounds (VOC) 0.5 0.6 90% 0.1 0.5 602,923 Carbon Monoxide (CO) 8.2 9.1 90% 0.9 8.2 39,455 Lead (Pb) - - - - N A

Notes & Assumptions 1 Cost Estimate per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 and adjusted for inflatio n 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-7: CO/VOC Control - Thermal Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 311,276

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 31,128 MN Sales Taxes 6.5% of control device cost (A) 20,233 Freight 5% of control device cost (A) 15,564 Purchased Equipment Total (B) 22% 378,20 0

Installation

Foundations & supports 8% of purchased equip cost (B) 30,256 Handling & erection 14% of purchased equip cost (B) 52,948 Electrical 4% of purchased equip cost (B) 15,128
Piping 2% of purchased equip cost (B) 7,564 Insulation 1% of purchased equip cost (B) 3,782 Painting 1% of purchased equip cost (B) 3,782 Installation Subtotal Standard Expenses 30% 113,460

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 113,46 0 Total Direct Capital Cost, DC 491,66 0

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 37,820 Construction & field expense s 5% of purchased equip cost (B) 18,910 Contractor fee s 10% of purchased equip cost (B ) 37,82 0 Start-up 2% of purchased equip cost (B) 7,564 Performance tes t 1% of purchased equip cost (B) 3,782 Model Studie s of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 11,346 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 117,242

Total Capital Investment (TCI) = DC + IC 608,90 2

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 608,90 2

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Cost s 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 149 kW-hr, 7946 hr/yr, 28% utilizatio n 16,791 Natural Gas 6.85 $/mscf, 157 scfm, 7946 hr/yr, 28% utilization 143,520
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 210,371

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 12,178 Property tax (1% total capital costs) 1% of total capital costs (TCI) 6,089 Insurance (1% total capital costs) 1% of total capital costs (TCI) 6,089 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 57,476 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 111,86 8

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 322,23 9

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-7: CO/VOC Control - Thermal Oxidizer

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 650 $/ft 3
Amount Required 39 ft 3
Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 40,23 7 19 0.6 149.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2. 1 Blower, Catalytic 40,237 23 0.6 180.5 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Typ e thermal (catalytic or thermal) 149.1

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 149.1 kW-hr 331,680 16,791 $/kwh, 149 kW-hr, 7946 hr/yr, 28% utilization Natural Gas 6.85 $/mscf 157 scfm 20,952 143,520 $/mscf, 157 scfm, 7946 hr/yr, 28% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilizatio n Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 28% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Lime 25.30998 4 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilizatio n Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 28% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 28% utilizatio n Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 28% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-7: CO/VOC Control - Thermal Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 495 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 989 Deg F - Temperature of waste gas out of heat recovery

T fo 707 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 22,235 scfm - Flow of waste gas

Q af 157 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculation s 22,39 2 scfm Flue Gas Cost in 1989 $' s $261,07 0 Current Cost Using CHE Plant Cost Inde x $311,27 6
Heat Rec % A B 0 10,29 4 0.235 5 Exponents per equation 3.2 4 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,34 2 0.250 0 Exponents per equation 3.2 7

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-8: CO/VOC Control - Catalytic Oxidizer

Operating Unit: Degasser Boiler

Emission Unit Number EU 137 Stack/Vent Number SV 050 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 20,719 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 28% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 40,237 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 22,235 scfm @ 68o F Dry Std Flow Rate 18,233 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 377,574 Purchased Equipment Total (B) 22% of control device cost (A) 458,753

Installation - Standard Costs 30% of purchased equip cost (B) 137,626 Installation - Site Specific Costs NA
Installation Total 137,626 Total Direct Capital Cost, DC 596,378 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 142,213 Total Capital Investment (TCI) = DC + IC 738,592

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 128,097 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 121,224 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 249,321

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutan t Lb/H r T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 0.7 0.8 0.8 - NA Total Particulates 0.7 0.8 0.8 - N A Nitrous Oxides (NOx) 7.9 8.8 8.8 - NA Sulfur Dioxide (SO 2 ) 0.1 0.1 0.1 - NA
Sulfuric Acid Mist - - - - NA Fluorides 0.0E+00 0.0E+00 - - NA Volatile Organic Compounds (VOC) 0.5 0.6 90% 0.1 0.5 466,489 Carbon Monoxide (CO) 8.2 9.1 90% 0.9 8.2 30,526 Lead (Pb) - - - - N A

Notes & Assumption s 1 A ug 28, 2005 Catalyst Cost Estimate from Englehard Catalyst & EPA Control Cost Manual Section 3.2 Chapter 2 and adjusted for in flation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-8: CO/VOC Control - Catalytic Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 377,574

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 37,757 MN Sales Taxes 6.5% of control device cost (A) 24,542 Freight 5% of control device cost (A) 18,879 Purchased Equipment Total (B) 22% 458,753

Installation

Foundations & supports 8% of purchased equip cost (B) 36,700 Handling & erection 14% of purchased equip cost (B) 64,225 Electrical 4% of purchased equip cost (B) 18,350 Piping 2% of purchased equip cost (B) 9,175 Insulation 1% of purchased equip cost (B) 4,588 Painting 1% of purchased equip cost (B) 4,588 Installation Subtotal Standard Expenses 30% 137,626

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 137,626 Total Direct Capital Cost, DC 596,378

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 45,875 Construction & field expenses 5% of purchased equip cost (B) 22,938 Contractor fees 10% of purchased equip cost (B) 45,875 Start-up 2% of purchased equip cost (B) 9,175 Performance test 1% of purchased equip cost (B) 4,588 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 13,763 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 142,213

Total Capital Investment (TCI) = DC + IC 738,592

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 653,060

OPERATING COSTS Direct Annual Operating Costs, D C

Operating Labo r

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Costs 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 180 kW-hr, 7946 hr/yr, 28% utilization 20,326 Natural Gas 6.85 $/mscf, 40 scfm, 7946 hr/yr, 28% utilization 36,851
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 28% utilization 20,860
NA NA - Total Annual Direct Operating Cost s 128,097

Indirect Operating Costs Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 14,772 Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,386 Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,386 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 61,644 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 121,224

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 249,321

See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-8: CO/VOC Control - Catalytic Oxidizer

Capital Recovery Factors Primary Installation
Interest Rate 7.00% Equipment Life 20 years
CRF 0.0944

Replacement Catalyst: Catalys t Equipment Life 5 years
CRF 0.2439
Rep part cost per unit 3000 $/ft 3 Amount Required 22 ft 3
Catalyst Cost 74,375 Cost adjusted for freight & sales tax Installation Labor 11,156 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 85,532 Zero out if no replacement parts needed
Annualized Cost 20,860

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.8358272 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 40,237 19 0.6 149.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 40,237 23 0.6 180.5 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type catalytic (catalytic or thermal) 180.5

Reagent Use & Other Operating Costs Oxidizers - N A

Operating Cost Calculation s Annual hours of operation : 7,946 Utilization Rate : 28.0%

Unit Unit o f Use Unit o f A nnua l A nnua l Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labo r Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenanc e Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 180.5 kW-hr 401,507 20,326 $/kwh, 180 kW-hr, 7946 hr/yr, 28% utilization Natural Gas 6.85 $/mscf 40 scfm 5,380 36,851 $/mscf, 40 scfm, 7946 hr/yr, 28% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 28% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 28% utilization CO Catalys t 650 $/ft3 0 ft 3 0 20,860 $/ft3, 0 ft3, 7946 hr/yr, 28% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 28% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumption s

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-8: CO/VOC Control - Catalytic Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 495 Deg F - Temperature of waste gas into heat recovery
T fi 600 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 569 Deg F - Temperature of waste gas out of heat recovery

T fo 527 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 22,235 scfm - Flow of waste gas

Q af 40 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 22,275 scfm Flue Gas Cost in 1989 $'s $260,729 Current Cost Using CHE Plant Cost Index $310,870
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerator s (EPA 453/B-96-001)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-9: CO/VOC Control - Regenerative Thermal Oxidizer

Operating Unit: Degasser Boiler

Emission Unit Number EU 137 Stack/Vent Number SV 050 Chemical Engineering Design Capacity 99 MMBtu/hr Standardized Flow Rate 20,719 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 28% Temperature 495 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 18.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 40,237 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rat e 22,23 5 scfm @ 68o F Dry Std Flow Rate 18,233 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 3 388,883 Purchased Equipment Total (B) 22% of control device cost (A) 472,493

Installation - Standard Costs 30% of purchased equip cost (B) 141,748 Installation - Site Specific Costs NA
Installation Total 141,748 Total Direct Capital Cost, DC 614,240 Total Indirect Capital Costs, IC 31 % of purchased equip cost (B ) 146,47 3 Total Capital Investment (TCI) = DC + IC 760,71 3

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 151,410 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 132,270 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 283,68 0

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Y r % Conc. Units T/y r T/y r $/Ton Rem
PM10 0.7 0.8 0.8 - NA Total Particulate s 0.7 0.8 0.8 - N A Nitrous Oxides (NOx) 7.9 8.8 8.8 - NA Sulfur Dioxide (SO 2 ) 0.1 0.1 0.1 - NA
Sulfuric Acid Mist - - - - NA Fluorides - - - - NA Volatile Organic Compounds (VOC) 0.5 0.6 90% 0.1 0.5 530,777 Carbon Monoxide (CO) 8.2 9.1 90% 0.9 8.2 34,733 Lead (Pb) - - - - N A

Notes & Assumptions 1 Cost Estimate per L & E America (TANN Corp), Aug 1, 2006 emai l
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
3 Cost Estimate per Tann Corporation, July 2006
4 Used 0.6 power law factor to adjust price from bid basis of 100,000 scfm

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-9: CO/VOC Control - Regenerative Thermal Oxidizer

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 388,883

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 38,888 MN Sales Taxes 6.5% of control device cost (A) 25,277 Freight 5% of control device cost (A) 19,444 Purchased Equipment Total (B) 22% 472,49 3

Installation

Foundations & supports 8% of purchased equip cost (B) 37,799 Handling & erection 14% of purchased equip cost (B) 66,149 Electrical 4% of purchased equip cost (B) 18,900
Piping 2% of purchased equip cost (B) 9,450 Insulation 1% of purchased equip cost (B) 4,725 Painting 1% of purchased equip cost (B) 4,725 Installation Subtotal Standard Expenses 30% 141,748

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 141,74 8 Total Direct Capital Cost, DC 614,24 0

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,249 Construction & field expense s 5% of purchased equip cost (B) 23,625 Contractor fee s 10% of purchased equip cost (B ) 47,24 9 Start-up 2% of purchased equip cost (B) 9,450 Performance tes t 1% of purchased equip cost (B) 4,725 Model Studie s of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 14,175 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 146,473

Total Capital Investment (TCI) = DC + IC 760,71 3

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 760,71 3

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Supervisor 15% 15% of Operator Cost s 2,384
Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892 Maintenance Materials 100% of maintenance labor costs 15,892 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 180 kW-hr, 7946 hr/yr, 28% utilizatio n 20,32 6 Natural Gas 6.85 $/mscf, 89 scfm, 7946 hr/yr, 28% utilization 81,024
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Cost s 151,41 0

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036 Administration (2% total capital costs) 2% of total capital costs (TCI) 15,214 Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,607 Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,607 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 71,806 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cos t 132,27 0

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 283,68 0

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-9: CO/VOC Control - Regenerative Thermal Oxidizer

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years
CRF 0.0000
Rep part cost per unit 650 $/ft 3
Amount Required 0 ft 3
Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3
CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cos t 0 Zero out if no replacement parts neede d
A nnualized Cos t 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 40,23 7 19 0.6 149.1 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2. 1 Blower, Catalytic 40,237 23 0.6 180.5 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Typ e catalyti c (catalytic or thermal) 180. 5

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 2,384 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 180.5 kW-hr 401,507 20,326 $/kwh, 180 kW-hr, 7946 hr/yr, 28% utilization Natural Gas 6.85 $/mscf 89 scfm 11,828 81,024 $/mscf, 89 scfm, 7946 hr/yr, 28% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilizatio n Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 28% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 28% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 28% utilization Lime 25.30998 4 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilizatio n Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 28% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 28% utilization CO Catalys t 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 28% utilizatio n Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 28% utilization *annual use rate is in same units of measurement as the unit cost facto r See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment G - Emission Control Cost Analysis Table G-9: CO/VOC Control - Regenerative Thermal Oxidizer

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 90% Heat Recovery

Auxiliary Fuel Use Equation 3.19
T wi 495 Deg F - Temperature of waste gas into heat recovery
T fi 1200 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 1,130 Deg F - Temperature of waste gas out of heat recovery

T fo 566 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas - flue gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Q wg 22,235 scfm - Flow of waste gas

Q af 89 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculation s 22,23 5 scfm Flue Gas

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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# Attachment H

Material Handling, Pellet Plant BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment H - Emission Control Cost AnalysisTable H-1: Cost Summary - Material Handling, Pelletizer - Hearth Layer BinPM/PM10 Control Cost Summary *Control TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Baghouse0.0025gr/dscf2 680 $6,113,901 $1,115,524 $1,640 NA None Low Solid WasteWet Scrubber0.005gr/dscf3 679 $974,410 $388,257 $572 NA None High Waste-waterDry ElectroStatic Precipitator(ESP)0.005gr/dscf3 679 $2,625,818 $466,071 $687 NANone Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)0.005gr/dscf3 679 $6,475,115 $1,034,437 $1,524 NA None Low Waste-waterUncontrolled0% 682* Based on highest emission rate if PM not equal to PM10Fluoride Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber99% 1.7E-04 1.7E-02 $974,410 $388,257 $22,998,559 NANone High Waste-waterDry ElectroStatic Precipitator(ESP)99% 1.7E-04 1.7E-02 $2,625,818 $466,071 $27,607,908 NANone Low Solid WasteBaghouse99% 1.7E-04 1.7E-02 $6,113,901 $1,115,524 $66,078,547 NANone Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)99% 1.7E-04 1.7E-02 $6,475,115 $1,034,437 $61,275,355 NA None Low Waste-waterUncontrolled0% 1.7E-02Lead Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber99% 6.8E-06 6.8E-04 $974,410 $388,257 $575,041,859 NANone High Waste-waterDry ElectroStatic Precipitator(ESP)99% 6.8E-06 6.8E-04 $2,625,818 $466,071 $690,291,177 NANone Low Solid WasteBaghouse99% 6.8E-06 6.8E-04 $6,113,901 $1,115,524 $1,652,187,436 NANone Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)99% 6.8E-06 6.8E-04 $6,475,115 $1,034,437 $1,532,091,371 NA None Low Waste-waterUncontrolled0% 6.8E-04The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual control efficiencies.P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach H - Material Handling Mar 2007 RevisionCost Summary3/6/2007Page 1 of 14

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Pelletizer - Hearth Layer Bin Study Year 2005 Emission Unit Number EU 036 Stack/Vent Number SV 016 Reference Item Unit Cos t Units Cos t Y ear Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.051 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.78 $/mgal 0.76 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation

Cooling Water 0.27 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.31 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.64 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.15 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 27.32 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3% inflation

Hazardous Waste Disposal 273.18 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3% inflation

Waste Transport 0.55 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycle 1.16 $/ton 1.00 2000 Corus Study for MN Iron and Steel Project Study use $1/ton to cover cost of materials movement

Chemicals & Supplie s Lime 25.31 $/ton 24.57 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation Caustic 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.44 Mscf 1.40 2004 Kaar Consulting MSI Cost Model cost adjusted for 3% inflation EPA Urea 179.1 $/ton A mmonia 0.101 $/lb Reagent #8 $/ton

Catalyst & Replacement Parts SCR Catalyst 500 $/ft 3 Cormetech, Inc. CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 Catalyst #4 Catalyst #5

Filter Bags 36.84 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Other Sales Tax 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Informatio n A nnual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 23.3% 2004 Kaar Consulting MSI Cost Model Equipment Life 20 yrs Engineering Estimate Design Capacity 368,649 Tons/yr Standardized Flow Rate 82,746 scfm @ 32o F Temperature 80 Deg F Moisture Content 3.0% Actual Flow Rate 90,843 acfm Standardized Flow Rate 88,801 scfm @ 68o F Dry Std Flow Rate 86,137 dscfm @ 68o F

Max Emis Pollutan t Lb/H r Uncontrolled Conc PM10 738.3 1.00 gr/dscf Total Particulates 738.3 1.00 gr/dscf Nitrous Oxides (NOx) - - ppm Sulfur Dioxide (SO 2 )

- - ppm Sulfuric Acid Mist - - ppm Fluorides 1.8E-02 2.5E-05 gr/dscf 36.2 ppb (Assumes 99% control as PM) Volatile Organic Compounds (VOC) - - ppm Carbon Monoxide (CO) - - ppm Lead (Pb) 7.4E-04 1.0E-06 gr/dscf 0.265 ppb (Assumes 99% control as PM) Enter this data for each emission uni t Enter data for this study (applies to all units )

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 200 7)\Attachments\Attach H - Material Handling Mar 2007 Revision Utility Chem$ Data 3/6/2007 Page 2 of 14

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-3: PM Control - Wet Wall ESP

Operating Unit: Pelletizer - Hearth Layer Bin

Emission Unit Number EU 036 Stack/Vent Number SV 016 Chemical Engineering Design Capacity 368,649 Tons/yr Standardized Flow Rate 82,746 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 23% Temperature 80 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 3.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 90,843 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 88,801 scfm @ 68o F Dry Std Flow Rate 86,137 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 2,337,418 Purchased Equipment Total (B) 22% of control device cost (A) 2,839,963

Installation - Standard Costs 71% of purchased equip cost (B) 2,016,374 Installation - Site Specific Costs NA Installation Total 2,016,374 Total Direct Capital Cost, DC 4,856,336 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,618,779 Total Capital Investment (TCI) = DC + I C 6,475,115

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 116,013 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 918,425 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,034,437

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem PM10 738 682 0.005 gr/dscf 3.4 679 1,524 Total Particulates 738 682 0.005 gr/dscf 3.4 679 1,524 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides 1.8E-02 1.7E-02 99% 1.7E-04 1.7E-02 61,275,355 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 7.4E-04 6.8E-04 99% 6.8E-06 0.0 1,532,091,371

Notes & Assumptions
1 Sept 8, 2005 Cost Estimate from Durr Environmental
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
3 Piping cost estimated to be 5% of purchase price; same as PM wet scrubber. Change to account for additional piping needed for w ater sprays in WESP.
4 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation 5 ESP maintenance materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
6 ESP blower electrical use Eq 3.46 EPA Cont Cost Manual Section 6 Chapter 3
7 ESP grid electrical use Eq 3.48 EPA Cont Cost Manual Section 6 Chapter 3 8 WESP pump electrical use Eq 3.48 EPA Cont Cost Manual Section 6 Chapter 3

9 Estimated ESP Grid Area at 219 ft 2 per 1000 acfm EPA example problem Manual Section 6 Chapter 3.4.5.1
10 Used 0.6 power law factor to adjust price to calculated acfm from bid basis of 291,000 acfm
11 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21
12 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies.

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 200 7)\Attachments\Attach H - Material Handling Mar 2007 Revision PM-Pb-SO2-SA-F- Wet ESP 3/6/2007 Page 3 of 14

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-3: PM Control - Wet Wall ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 2,337,418

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 233,742 MN Sales Taxes 6.5% of control device cost (A) 151,932 Freight 5% of control device cost (A) 116,871 Purchased Equipment Total (B) 22% 2,839,963

Installation

Foundations & supports 4% of purchased equip cost (B) 113,599 Handling & erection 50% of purchased equip cost (B) 1,419,981 Electrical 8% of purchased equip cost (B) 227,197 Piping (3) 5% of purchased equip cost (B) 141,998 Insulation 2% of purchased equip cost (B) 56,799 Painting 2% of purchased equip cost (B) 56,799 Installation Subtotal Standard Expenses 71% 2,016,374

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 2,016,374 Total Direct Capital Cost, DC 4,856,336

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 567,993 Construction & field expenses 20% of purchased equip cost (B) 567,993 Contractor fees 10% of purchased equip cost (B) 283,996 Start-up 1% of purchased equip cost (B) 28,400 Performance test 1% of purchased equip cost (B) 28,400 Model Studies 2% of purchased equip cost (B) 56,799 Contingencies 3% of purchased equip cost (B) 85,199 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,618,779

Total Capital Investment (TCI) = DC + IC 6,475,115

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 6,475,115

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Supervisor 48% % of Operator Costs. 15,256
Maintenance

Maintenance Labor 19,895 ft2 grid area, 1.0 $/ft2 of grid area 4,918 Maintenance Materials 1 1% of purchased equipment cost 28,400 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 120 kW-hr, 7946 hr/yr, 23.2505344980828% utilizatio n 11,267
NA NA - Water 0.78 $/mgal, 91 gpm, 7946 hr/yr, 23.2505344980828% utilization 7,883
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 91 gpm, 7946 hr/yr, 23.2505344980828% utilizatio n 16,505

NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 116,013

Indirect Operating Costs Overhead 60% of total labor and material costs 48,215 Administration (2% total capital costs) 2% of total capital costs (TCI) 129,502 Property tax (1% total capital costs) 1% of total capital costs (TCI) 64,751 Insurance (1% total capital costs) 1% of total capital costs (TCI) 64,751 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 611,205 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 918,425

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,034,437

See Summary page for notes and assumptions

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 200 7)\Attachments\Attach H - Material Handling Mar 2007 Revision PM-Pb-SO2-SA-F- Wet ESP 3/6/2007 Page 4 of 14

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-3: PM Control - Wet Wall ESP

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower Baghouse & ES P 90,843 4.48 73.7 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq. flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 454 gpm 1.000 40 0.5 6.8 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 91 gpm 1.000 40 0.5 1.4 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 19,895 ft 2 1.94E-03 kW/ft 2 38.6 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 120.5

Reagent Use & Other Operating Costs WESP Pump 90,843 acfm 5 gpm/kacfm 454 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disc h 20% of circulating water rate = 91 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 23.3%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labor Op Labor 32 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 15,256 % of Operator Costs. Maintenance Maint Labor 19,895 ft2 grid area 0.984 $/ft 2 of grid area 4,918 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 28,400 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 120.5 kW-hr 222,551 11,267 $/kwh, 120 kW-hr, 7946 hr/yr, 23.2505344980828% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 23.2505344980828% utilization Water 0.78 $/mgal 90.8 gpm 10,070 7,883 $/mgal, 91 gpm, 7946 hr/yr, 23.2505344980828% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 23.2505344980828% utilization
WW Treat Neutralizatio n 1.64 $/mgal 90.8 gpm 10,070 16,505 $/mgal, 91 gpm, 7946 hr/yr, 23.2505344980828% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 23.2505344980828% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 23.2505344980828% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 23.2505344980828% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 23.2505344980828% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 23.2505344980828% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 200 7)\Attachments\Attach H - Material Handling Mar 2007 Revision PM-Pb-SO2-SA-F- Wet ESP 3/6/2007 Page 5 of 14

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-4: PM Control - Dry ESP

Operating Unit: Pelletizer - Hearth Layer Bin

Emission Unit Number EU 036 Stack/Vent Number SV 016 Chemical Engineering Design Capacity 368,649 Tons/yr Standardized Flow Rate 82,746 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 23% Temperature 80 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 3.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 90,843 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 88,801 scfm @ 68o F Dry Std Flow Rate 86,137 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 964,807 Purchased Equipment Total (B) 22% of control device cost (A) 1,172,240

Installation - Standard Costs 67% of purchased equip cost (B) 785,401 Installation - Site Specific Costs NA Installation Total 785,401 Total Direct Capital Cost, DC 1,957,641 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 668,177 Total Capital Investment (TCI) = DC + I C 2,625,818

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 74,971 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 391,100 Total Annual Cost (Annualized Capital Cost + Operating Cost) 466,071

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 738 682 0.005 gr/dscf 3.4 679 687 Total Particulates 738 682 0.005 gr/dscf 3.4 679 687 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides 1.8E-02 1.7E-02 99% 1.7E-04 1.7E-02 27,607,908 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 7.4E-04 6.8E-04 99% 6.8E-06 0.0 690,291,177

Notes & Assumptions
1 Cost Estimate from 2001 Bids for Taconite Plant ESP and EPA Air Compliance Advisor Ver 7.7. Used aveage cost adusted for inflat ion.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
3 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation
4 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
5 Estimated ESP Grid Area at 219 ft 2 per 1000 acfm EPA example problem Manual Section 6 Chapter 3.4.5.1
6 Used 0.6 power law factor to adjust price to calculated acfm from estimated cost basis of 291,000 acfm
7 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21 8 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 200 7)\Attachments\Attach H - Material Handling Mar 2007 Revision PM-Pb Dry ESP 3/6/2007 Page 6 of 14

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-4: PM Control - Dry ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 964,807

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 96,481 MN Sales Taxes 6.5% of control device cost (A) 62,712 Freight 5% of control device cost (A) 48,240 Purchased Equipment Total (B) 22% 1,172,240

Installation

Foundations & supports 4% of purchased equip cost (B) 46,890 Handling & erection 50% of purchased equip cost (B) 586,120 Electrical 8% of purchased equip cost (B) 93,779 Piping 1% of purchased equip cost (B) 11,722 Insulation 2% of purchased equip cost (B) 23,445 Painting 2% of purchased equip cost (B) 23,445 Installation Subtotal Standard Expenses 67% 785,401

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 785,401 Total Direct Capital Cost, DC 1,957,641

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 234,448 Construction & field expenses 20% of purchased equip cost (B) 234,448 Contractor fees 10% of purchased equip cost (B) 117,224 Start-up 1% of purchased equip cost (B) 11,722 Performance test 1% of purchased equip cost (B) 11,722 Model Studies 2% of purchased equip cost (B) 23,445 Contingencies 3% of purchased equip cost (B) 35,167 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 668,177

Total Capital Investment (TCI) = DC + IC 2,625,818

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,625,818

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Supervisor 48% % of Operator Costs. 15,256
Maintenance

Maintenance Labor 19,895 ft2 grid area, 1.0 $/ft2 of grid area 4,918 Maintenance Materials 1 1% of purchased equipment cost 11,722 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 112 kW-hr, 7946 hr/yr, 23.2505344980828% utilizatio n 10,499
NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization 791
NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 74,971

Indirect Operating Costs Overhead 60% of total labor and material costs 38,209 Administration (2% total capital costs) 2% of total capital costs (TCI) 52,516 Property tax (1% total capital costs) 1% of total capital costs (TCI) 26,258 Insurance (1% total capital costs) 1% of total capital costs (TCI) 26,258 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 247,859 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 391,100

Total Annual Cost (Annualized Capital Cost + Operating Cost) 466,071

See Summary page for notes and assumptions

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 200 7)\Attachments\Attach H - Material Handling Mar 2007 Revision PM-Pb Dry ESP 3/6/2007 Page 7 of 14

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-4: PM Control - Dry ESP

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower Baghouse & ES P 90,843 4.48 73.7 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 19,895 ft 2 1.94E-03 kW/ft 2 38.6 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 112.3

Reagent Use & Other Operating Costs WESP Pump acfm 5 gpm/kacfm 0 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disc h 20% of circulating water rate = 0 gpm

Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 23.3%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labor Op Labor 32 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 15,256 % of Operator Costs. Maintenance Maint Labor 19,895 ft2 grid area 0.984 $/ft 2 of grid area 4,918 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 11,722 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 112.3 kW-hr 207,395 10,499 $/kwh, 112 kW-hr, 7946 hr/yr, 23.2505344980828% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 23.2505344980828% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 23.2505344980828% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Waste Transport 0.55 $/ton-mi 0.0 Mi 0 0 $/ton-mi, 0 Mi, 7946 hr/yr, 23.2505344980828% utilization Waste Recycle 1.16 $/ton 0.4 ton/hr 682 791 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 23.2505344980828% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 23.2505344980828% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 23.2505344980828% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 23.2505344980828% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 23.2505344980828% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-5: PM Control - Wet Scrubber

Operating Unit: Pelletizer - Hearth Layer Bin

Emission Unit Number EU 036 Stack/Vent Number SV 016 Design Capacity 368,649 Tons/yr Standardized Flow Rate 82,746 scfm @ 32o F Expected Utilization Rate 23% Temperature 80 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 3.0% Annual Interest Rate 7.0% Actual Flow Rate 90,843 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 88,801 scfm @ 68o F Dry Std Flow Rate 86,137 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 419,886 Purchased Equipment Total (B) 22% of control device cost (A) 510,162

Installation - Standard Costs 56% of purchased equip cost (B) 285,691 Installation - Site Specific Costs NA Installation Total 285,691 Total Direct Capital Cost, DC 795,853 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 178,557 Total Capital Investment (TCI) = DC + IC 974,410

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 175,300 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,956 Total Annual Cost (Annualized Capital Cost + Operating Cost) 388,257

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 738 682 0.005 gr/dscf 3.4 679 572 Total Particulates 738 682 0.005 gr/dscf 3.4 679 572 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides 1.8E-02 1.7E-02 99% 1.7E-04 1.7E-02 22,998,559 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 7.4E-04 6.8E-04 99% 6.8E-06 0.0 575,041,859

Notes & Assumptions
1 Scrubber Cost per Barr Engineering 2004 Scrubber Project. Adjusted prices per Chemical Engineering Magazine CPI Index 2004 = 44 4, 2005 =465 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 2
3 Used 0.6 power law factor to adjust price to calculated acfm from bid basis of 500,000 acfm
4 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21 adjusted for inflation 5 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies.

3.691585714

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-5: PM Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 419,886

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 41,989 MN Sales Taxes 6.5% of control device cost (A) 27,293 Freight 5% of control device cost (A) 20,994 Purchased Equipment Total (B) 22% 510,162

Installation

Foundations & supports 6% of purchased equip cost (B) 30,610 Handling & erection 40% of purchased equip cost (B) 204,065 Electrical 1% of purchased equip cost (B) 5,102 Piping 5% of purchased equip cost (B) 25,508 Insulation 3% of purchased equip cost (B) 15,305 Painting 1% of purchased equip cost (B) 5,102 Installation Subtotal Standard Expenses 56% 285,691

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 285,691 Total Direct Capital Cost, DC 795,853

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 51,016 Construction & field expenses 10% of purchased equip cost (B) 51,016 Contractor fees 10% of purchased equip cost (B) 51,016 Start-up 1% of purchased equip cost (B) 5,102 Performance test 1% of purchased equip cost (B) 5,102 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 15,305 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 178,557

Total Capital Investment (TCI) = DC + IC 974,410

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 974,410

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535 Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100.00 % of Maintenance Labor 31,784 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 283 kW-hr, 7946 hr/yr, 23.2505344980828% utilizatio n 26,435
NA NA - Water 0.78 $/mgal, 45 gpm, 7946 hr/yr, 23.2505344980828% utilization 3,941
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 45 gpm, 7946 hr/yr, 23.2505344980828% utilizatio n 8,253
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 175,300

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 19,488 Property tax (1% total capital costs) 1% of total capital costs (TCI) 9,744 Insurance (1% total capital costs) 1% of total capital costs (TCI) 9,744 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 91,977 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,956

Total Annual Cost (Annualized Capital Cost + Operating Cost) 388,257

See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-5: PM Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3
Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 90,843 15 0.6 357.3 266.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.40
L/G ratio* Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 10 1.125 40 0.5 20.7 15.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41 H2O WW Disch Pump 45 gpm 1.125 40 0.5 1.0 0.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41
Other Other
Other Total 282.6 * L/G = Gal/1,000 acf

Reagent Use & Other Operating Costs
Caustic Use 0.00 lb/hr SO2 2.50 lb NaOH/lb SO2 0.00 lb/hr Caustic
Lime Use 0.00 lb/hr SO2 1.53 lb Lime/lb SO2 0.00 lb/hr Lime Circulating Water Rate 908 gpm Water Makeup Rate/WW Disch = 5% of circulating water rate = 45 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 23.3%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 282.6 kW-hr 522,179 26,435 $/kwh, 283 kW-hr, 7946 hr/yr, 23.2505344980828% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 23.2505344980828% utilization Water 0.78 $/mgal 45.4 gpm 5,035 3,941 $/mgal, 45 gpm, 7946 hr/yr, 23.2505344980828% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 23.2505344980828% utilization
WW Treat Neutralizatio n 1.64 $/mgal 45.4 gpm 5,035 8,253 $/mgal, 45 gpm, 7946 hr/yr, 23.2505344980828% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 23.2505344980828% utilization Urea 405 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 23.2505344980828% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 23.2505344980828% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 23.2505344980828% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 23.2505344980828% utilization *annual use rate is in same units of measurement as the unit cost factor See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-6: PM Control -Baghouse

Operating Unit: Pelletizer - Hearth Layer Bin

Emission Unit Number EU 036 Stack/Vent Number SV 016 Design Capacity 368,649 Tons/yr Standardized Flow Rate 82,746 scfm @ 32o F Expected Utilization Rate 23% Temperature 80 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 3.0% Annual Interest Rate 7.0% Actual Flow Rate 90,843 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 88,801 scfm @ 68o F Dry Std Flow Rate 86,137 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 2,297,725 Purchased Equipment Total (B) 22% of control device cost (A) 2,791,736

Installation - Standard Costs 74% of purchased equip cost (B) 2,065,884 Installation - Site Specific Costs NA Installation Total 2,065,884 Total Direct Capital Cost, DC 4,857,620 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 1,256,281 Total Capital Investment (TCI) = DC + I C 6,113,901

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 245,209 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 870,315 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,115,524

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 738 682 0.0025 gr/dscf 1.7 680 1,640 Total Particulates 738 682 0.0025 gr/dscf 1.7 680 1,640 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA

Sulfuric Acid Mist - - 0.0 - NA Fluorides 1.8E-02 1.7E-02 99% 1.7E-04 1.7E-02 66,078,547 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 7.4E-04 6.8E-04 99% 6.8E-06 0.0 1,652,187,436

Notes & Assumptions
1 Sept 2, 2005 Cost Estimate Enviromental Elements
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1
3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapt er 1.5.1.8
4 Bag replacement at 10 min/bag EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min pe r bag. 5 Used 0.6 power law factor to adjust price to calculated dscfm from bid basis of 217,000 dscfm
6 $250,000 bag replacement cost from vendor adjusted for flow rate as noted above
7 Baghouse cloth area estimated using 9:1 air to cloth ratio for rock dust per Table 1.1, EPA Cont Cost Manual 6th ed Section 6 Chapter 1. 8 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-6: PM Control -Baghouse

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 2,297,725

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 229,772 MN Sales Taxes 6.5% of control device cost (A) 149,352 Freight 5% of control device cost (A) 114,886 Purchased Equipment Total (B) 22% 2,791,736

Installation

Foundations & supports 4% of purchased equip cost (B) 111,669 Handling & erection 50% of purchased equip cost (B) 1,395,868 Electrical 8% of purchased equip cost (B) 223,339 Piping 1% of purchased equip cost (B) 27,917 Insulation 7% of purchased equip cost (B) 195,421 Painting 4% of purchased equip cost (B) 111,669 Installation Subtotal Standard Expenses 74% 2,065,884

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 2,065,884 Total Direct Capital Cost, DC 4,857,620

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 279,174 Construction & field expenses 20% of purchased equip cost (B) 558,347 Contractor fees 10% of purchased equip cost (B) 279,174 Start-up 1% of purchased equip cost (B) 27,917 Performance test 1% of purchased equip cost (B) 27,917 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 83,752 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 1,256,281

Total Capital Investment (TCI) = DC + IC 6,113,901

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 5,760,560

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535
Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100% of maintenance labor costs 31,784 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 164 kW-hr, 7946 hr/yr, 23.2505344980828% utilizatio n 15,378
NA NA - NA NA - NA NA - Comp Air 0.31 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 23.2505344980828% utiliz a 6,192 N A N A - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization 791
NA NA - NA NA - NA NA - NA NA - Filter Bags 33.71 $/bag, 752 bags, 7946 hr/yr, 23.2505344980828% utilization 86,176 Total Annual Direct Operating Costs 245,209

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 122,278 Property tax (1% total capital costs) 1% of total capital costs (TCI) 61,139 Insurance (1% total capital costs) 1% of total capital costs (TCI) 61,139 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 543,756 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 870,315

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,115,524

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment H - Emission Control Cost Analysis Table H-6: PM Control -Baghouse

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages Equipment Life 5 years CRF 0.2439 Rep part cost per unit 33.711 $/bag - Calculated cost not used Amount Required 752 Total Rep Parts Cost 346,603 Cost adjusted for freight & sales tax Installation Labo r 6,738 10 min per bag, Labor + Overhead (68% = $29.65/hr ) EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 Total Installed Cos t 353,341 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag

. Annualized Cost 86,176

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Baghouse 90,843 10 164.4 Baghouse Shaker 0.0 Gross fabric area ft 2 0 EPA Cont Cost Manual 6th ed Section 6 Chapter 1 Eq 1.14 Other Other Other
Other
Other Total 164.4

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Gross BH Filter Area 10,094 ft 2

Cages 16 ft long 5 in dia 13.42 area/cage ft 2 752 Cages 11.036 $/cage Bags 1.69 $/ft2 of fabric 22.68 $/bag
Total 33.711

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 23.3%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cos t Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 164.4 kW-hr 303,774 15,378 $/kwh, 164 kW-hr, 7946 hr/yr, 23.2505344980828% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 23.2505344980828% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization Comp Air 0.31 $/mscf 2 scfm/kacfm 20,140 6,192 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 23.2505344980828% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization
WW Treat Biotreateme n 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Waste Recycle 1.16 $/ton 0.4 ton/hr 682 791 $/ton, 0 ton/hr, 7946 hr/yr, 23.2505344980828% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 23.2505344980828% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 23.2505344980828% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 23.2505344980828% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 23.2505344980828% utilization Filter Bags 33.71 $/bag 752 bags NA 86,176 $/bag, 752 bags, 7946 hr/yr, 23.2505344980828% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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# Attachment I

DRI, Material Handling BACT Cost TablesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment I - Emission Control Cost AnalysisTable I-1: Cost Summary - DRI Material Handling Depressurization VentPM/PM10 Control Cost Summary *Control TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalledCapital Cost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Dry ElectroStatic Precipitator(ESP)0.005gr/dscf3.2 61.7 $831,104 $211,610 $3,430 NA None Low Solid WasteWet Scrubber0.005gr/dscf3.2 61.7 $674,360 $353,525 $5,731 NA None High Waste-waterBaghouse0.0025gr/dscf1.6 63.3 $1,019,106 $387,266 $6,117 NA None Low Solid WasteUncontrolled0%64.9* Based on highest emission rate if PM not equal to PM10Fluoride Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalledCapital Cost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Dry ElectroStatic Precipitator(ESP)99% 1.6E-04 1.6E-02 $831,104 $211,610 $13,167,234 NA None Low Solid WasteWet Scrubber99%1.6E-04 1.6E-02 $674,360 $353,525 $21,997,770 NANone High Waste-waterBaghouse99%1.6E-04 1.6E-02 $1,019,106 $387,266 $24,097,245 NANone Low Solid WasteUncontrolled0%1.6E-02Lead Control Cost SummaryControl TechnologyControlEff %ControlledEmissionsT/yEmissionReduction T/yrInstalledCapital Cost $AnnualizedOperating Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Dry ElectroStatic Precipitator(ESP)99% 6.5E-06 6.4E-04 $831,104 $211,610 $329,180,860 NA None Low Solid WasteWet Scrubber99%6.5E-06 6.4E-04 $674,360 $353,525 $549,944,248 NANone High Waste-waterBaghouse99%6.5E-06 6.4E-04 $1,019,106 $387,266 $602,431,118 NANone Low Solid WasteUncontrolled0%6.5E-04The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual control efficiencies.P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach I - Material Handling Mar 2007 RevisionCost Summary3/6/2007Page 1 of 11

### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: DRI Mtl Handling - DePress Ve n Study Year 2005 Emission Unit Number EU 064, 081 Stack/Vent Number SV 029, 064 Reference Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.051 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.78 $/mgal 0.76 2004 Kaar Consulting MSI Cost Mode l cost adjusted for 3% inflation

Cooling Water 0.27 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.31 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.64 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 C h 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.15 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 27.32 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3 % inflation

Hazardous Waste Disposal 273.18 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3 % inflation

Waste Transport 0.55 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycl e 1.16 $/ton 1.00 2000 Corus Study for MN Iron and Steel Projec t Study use $1/ton to cover cost of materials movement

Chemicals & Supplies Lime 25.31 $/ton 24.57 2004 Kaar Consulting MSI Cost Mode l cost adjusted for 3% inflation Causti c 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.44 Mscf 1.40 2004 Kaar Consulting MSI Cost Mode l cost adjusted for 3% inflation EPA Urea 179.1 $/ton
A mmonia 0.101 $/lb Reagent # 8 $/ton

Catalyst & Replacement Parts SCR Catalyst 500 $/ft 3 Cormetech, Inc. CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst # 3 Catalyst # 4 Catalyst # 5

Filter Bags 36.84 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Other Sales Ta x 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Information A nnual Op. Hr s 7946 Hours Engineering Estimate Utilization Rat e 100% 2004 Kaar Consulting MSI Cost Mode l Equipment Life 20 yrs Engineering Estimate Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 19,307 scfm @ 32o F Temperature 104 Deg F Moisture Content 8.0% Actual Flow Rate 22,139 acfm Standardized Flow Rate 20,720 scfm @ 68o F Dry Std Flow Rate 19,062 dscfm @ 68o F

Max Emis Pollutant Lb/Hr Uncontrolled Conc PM PM10 16.3 0.10 gr/dscf Total Particulates 16.3 0.10 gr/dscf Nitrous Oxides (NOx) - - ppm Sulfur Dioxide (SO 2 )

- - ppm Sulfuric Acid Mist - - ppm Fluorides 4.1E-03 2.5E-05 gr/dscf 36 ppb (Assumes 99% control as PM) Volatile Organic Compounds (VOC) - - ppm Carbon Monoxide (CO) - - ppm Lead (Pb) 1.6E-04 1.0E-06 gr/dscf 0.27 ppb (Assumes 99% control as PM) Enter this data for each emission unit Enter data for this study (applies to all units)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-3: PM Control - Dry ESP

Operating Unit: DRI Mtl Handling - DePress Vent

Emission Unit Number EU 064, 081 Stack/Vent Number SV 029, 064 Chemical Engineering Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 19,307 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 104 Deg F 2003 402 Expected Annual Hours of Operation 7,946 Hours Moisture Content 8.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 22,139 acfm Inflation Adj 1.16 Expected Equipment Life 20 yrs Standardized Flow Rate 20,720 scfm @ 68o F Dry Std Flow Rate 19,062 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 305,373 Purchased Equipment Total (B) 22% of control device cost (A) 371,028

Installation - Standard Costs 67% of purchased equip cost (B) 248,589 Installation - Site Specific Costs NA Installation Total 248,589 Total Direct Capital Cost, DC 619,617 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 211,486 Total Capital Investment (TCI) = DC + IC 831,104

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 66,602 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 145,008 Total Annual Cost (Annualized Capital Cost + Operating Cost) 211,610

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 16.3 64.9 0.005 gr/dscf 3.2 61.7 3,430 Total Particulates 16.3 64.9 0.005 gr/dscf 3.2 61.7 3,430 Nitrous Oxides (NOx) - - 0.0 - N A Sulfur Dioxide (SO 2 )

- - 0.0 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides 4.1E-03 1.6E-02 99% 1.6E-04 1.6E-02 13,167,234 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 1.6E-04 6.5E-04 99% 6.5E-06 0.0 329,180,860

Notes & Assumptions
1 Cost Estimate from EPA Air Compliance Advisor Ver 7.7. Cost adjusted for inflation.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
3 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation
4 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
5 Estimated ESP Grid Area at 219 ft 2 per 1000 acfm EPA example problem Manual Section 6 Chapter 3.4.5.1
6 Used 0.6 power law factor to adjust price to 116,000 acfm from bid basis of 291,000 acfm
7 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21 8 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-3: PM Control - Dry ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 305,373

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 30,537 MN Sales Taxes 6.5% of control device cost (A) 19,849 Freight 5% of control device cost (A) 15,269 Purchased Equipment Total (B) 22% 371,028

Installation

Foundations & supports 4% of purchased equip cost (B) 14,841 Handling & erection 50% of purchased equip cost (B) 185,514 Electrical 8% of purchased equip cost (B) 29,682 Piping 1% of purchased equip cost (B) 3,710 Insulation 2% of purchased equip cost (B) 7,421 Painting 2% of purchased equip cost (B) 7,421 Installation Subtotal Standard Expenses 67% 248,589

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 248,589 Total Direct Capital Cost, DC 619,617

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 74,206 Construction & field expenses 20% of purchased equip cost (B) 74,206 Contractor fees 10% of purchased equip cost (B) 37,103 Start-up 1% of purchased equip cost (B) 3,710 Performance test 1% of purchased equip cost (B) 3,710 Model Studies 2% of purchased equip cost (B) 7,421 Contingencies 3% of purchased equip cost (B) 11,131 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 211,486

Total Capital Investment (TCI) = DC + IC 831,104

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 831,104

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Supervisor 48% % of Operator Costs. 15,256
Maintenance

Maintenance Labor 4,848 ft2 grid area, 1.0 $/ft2 of grid area 4,771 Maintenance Materials 1 1% of purchased equipment cost 3,710 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 27 kW-hr, 7946 hr/yr, 100% utilization 11,005
NA NA - NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization 75
NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 66,602

Indirect Operating Costs Overhead 60% of total labor and material costs 33,313 Administration (2% total capital costs) 2% of total capital costs (TCI) 16,622 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,311 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,311 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 78,450 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 145,008

Total Annual Cost (Annualized Capital Cost + Operating Cost) 211,610

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-3: PM Control - Dry ESP

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower Baghouse & ES P 22,139 4.48 18.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 4,848 ft 2 1.94E-03 kW/ft 2 9.4 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 27.4

Reagent Use & Other Operating Costs WESP Pump acfm 5 gpm/kacfm 0 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disc h 20% of circulating water rate = 0 gpm

Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 15,256 % of Operator Costs. Maintenance Maint Labor 4,848 ft2 grid area 0.954 $/ft 2 of grid area 4,771 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 3,710 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 27.4 kW-hr 217,387 11,005 $/kwh, 27 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization WW Treat Biotreatemen 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 Mi 0 0 $/ton-mi, 0 Mi, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 65 75 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-4: PM Control - Wet Scrubber

Operating Unit: DRI Mtl Handling - DePress Vent

Emission Unit Number EU 064, 081 Stack/Vent Number SV 029, 064 Chemical Engineering Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 19,307 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 100% Temperature 104 Deg F 2004 444.2 Expected Annual Hours of Operation 7,946 Hours Moisture Content 8.0% 2005 465 A nnual Interest Rate 7.0% A ctual Flow Rate 22,139 acfm Inflation Adj 1.05 Expected Equipment Life 20 yrs Standardized Flow Rate 20,720 scfm @ 68o F Dry Std Flow Rate 19,062 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 290,591 Purchased Equipment Total (B) 22% of control device cost (A) 353,068

Installation - Standard Costs 56% of purchased equip cost (B) 197,718 Installation - Site Specific Costs NA Installation Total 197,718 Total Direct Capital Cost, DC 550,786 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 123,574 Total Capital Investment (TCI) = DC + IC 674,360

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 180,893 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 172,632 Total Annual Cost (Annualized Capital Cost + Operating Cost) 353,525

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 16.3 64.9 0.005 gr/dscf 3.2 61.7 5,731 Total Particulates 16.3 64.9 0.005 gr/dscf 3.2 61.7 5,731 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA

Sulfuric Acid Mist - - 0.0 - NA Fluorides 4.1E-03 1.6E-02 99% 1.6E-04 1.6E-02 21,997,770 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 1.6E-04 6.5E-04 99% 6.5E-06 0.0 549,944,248

Notes & Assumptions
1 Nov 16, 2004 Cost Estimate from Turbosonic and adjusted for inflation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 2
3 Used 0.6 power law factor to adjust price to calculated acfm from bid basis of 37200 acfm
4 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies. 5 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-4: PM Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 290,591

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 29,059 MN Sales Taxes 6.5% of control device cost (A) 18,888 Freight 5% of control device cost (A) 14,530 Purchased Equipment Total (B) 22% 353,068

Installation

Foundations & supports 6% of purchased equip cost (B) 21,184 Handling & erection 40% of purchased equip cost (B) 141,227 Electrical 1% of purchased equip cost (B) 3,531 Piping 5% of purchased equip cost (B) 17,653 Insulation 3% of purchased equip cost (B) 10,592 Painting 1% of purchased equip cost (B) 3,531 Installation Subtotal Standard Expenses 56% 197,718

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 197,718 Total Direct Capital Cost, DC 550,786

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 35,307 Construction & field expenses 10% of purchased equip cost (B) 35,307 Contractor fees 10% of purchased equip cost (B) 35,307 Start-up 1% of purchased equip cost (B) 3,531 Performance test 1% of purchased equip cost (B) 3,531 Model Studies N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 10,592 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 123,574

Total Capital Investment (TCI) = DC + IC 674,360

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 674,360

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535 Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100.00 % of Maintenance Labor 31,784 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 69 kW-hr, 7946 hr/yr, 100% utilization 27,709
NA NA - Water 0.78 $/mgal, 21 gpm, 7946 hr/yr, 100% utilization 7,863
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 11 gpm, 7946 hr/yr, 100% utilization 8,650
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 180,893

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 13,487 Property tax (1% total capital costs) 1% of total capital costs (TCI) 6,744 Insurance (1% total capital costs) 1% of total capital costs (TCI) 6,744 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 63,655 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 172,632

Total Annual Cost (Annualized Capital Cost + Operating Cost) 353,525

See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-4: PM Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3
Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 22,139 15 0.6 87.1 64.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.40
L/G ratio* Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 10 1.125 40 0.5 5.0 3.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41 H2O WW Disch Pump 11 gpm 1.125 40 0.5 0.3 0.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41

Other Other
Other Total 68.9 * L/G = Gal/1,000 acf

Reagent Use & Other Operating Costs
Caustic Use 0.00 lb/hr SO2 2.50 lb NaOH/lb SO2 0.00 lb/hr Caustic
Lime Use 0.00 lb/hr SO2 1.53 lb Lime/lb SO2 0.00 lb/hr Lime Circulating Water Rate 221 gpm Water Makeup Rate/WW Disch = 5% of circulating water rate = 11 gpm Evap H2O Loss 10 gpm Water Makeup Rate 21 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 68.9 kW-hr 547,335 27,709 $/kwh, 69 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 21.1 gpm 10,045 7,863 $/mgal, 21 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 11.1 gpm 5,277 8,650 $/mgal, 11 gpm, 7946 hr/yr, 100% utilization WW Treat Biotreatemen 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Urea 405 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-5: PM Control -Baghouse

Operating Unit: DRI Mtl Handling - DePress Vent

Emission Unit Number EU 064, 081 Stack/Vent Number SV 029, 064 Design Capacity 4,608,111 Tons/yr Standardized Flow Rate 19,307 scfm @ 32o F Expected Utilization Rate 100% Temperature 104 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 8.0% Annual Interest Rate 7.0% Actual Flow Rate 22,139 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 20,720 scfm @ 68o F Dry Std Flow Rate 19,062 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 383,000 Purchased Equipment Total (B) 22% of control device cost (A) 465,345

Installation - Standard Costs 74% of purchased equip cost (B) 344,355 Installation - Site Specific Costs NA Installation Total 344,355 Total Direct Capital Cost, DC 809,700 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 209,405 Total Capital Investment (TCI) = DC + IC 1,019,106

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 170,144 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 217,122 Total Annual Cost (Annualized Capital Cost + Operating Cost) 387,266

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 16.3 64.9 0.003 gr/dscf 1.6 63.3 6,117 Total Particulates 16.3 64.9 0.003 gr/dscf 1.6 63.3 6,117 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA

Sulfuric Acid Mist - - 0.0 - NA Fluorides 4.1E-03 1.6E-02 99% 1.6E-04 1.6E-02 24,097,245 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 1.6E-04 6.5E-04 99% 6.5E-06 6.4E-04 602,431,118

Notes & Assumptions
1 September 2, 2005 Cost Estimate from Amerex
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1
3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapt er 1.5.1.8
4 Bag replacement at 10 min/bag EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min pe r bag. 5 Baghouse cloth area estimated using 9:1 air to cloth ratio for rock dust per Table 1.1, EPA Cont Cost Manual 6th ed Section 6 Chapter 1.
6 Adjusted bid price by air to cloth ratios fly ash (5) vs. crushed rock (9). Bid price for fly ash.
7 The control efficiencies for sulfuric acid mist, fluorides and lead are for example calculations and do not represent actual co ntrol efficiencies.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-5: PM Control -Baghouse

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 383,000

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 38,300 MN Sales Taxes 6.5% of control device cost (A) 24,895 Freight 5% of control device cost (A) 19,150 Purchased Equipment Total (B) 22% 465,345

Installation

Foundations & supports 4% of purchased equip cost (B) 18,614 Handling & erection 50% of purchased equip cost (B) 232,673 Electrical 8% of purchased equip cost (B) 37,228 Piping 1% of purchased equip cost (B) 4,653 Insulation 7% of purchased equip cost (B) 32,574 Painting 4% of purchased equip cost (B) 18,614 Installation Subtotal Standard Expenses 74% 344,355

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 344,355 Total Direct Capital Cost, DC 809,700

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 46,535 Construction & field expenses 20% of purchased equip cost (B) 93,069 Contractor fees 10% of purchased equip cost (B) 46,535 Start-up 1% of purchased equip cost (B) 4,653 Performance test 1% of purchased equip cost (B) 4,653 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 13,960 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 209,405

Total Capital Investment (TCI) = DC + IC 1,019,106

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 999,602

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568 Supervisor 15% 15% of Operator Costs 9,535
Maintenance

Maintenance Labor 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Maintenance Materials 100% of maintenance labor costs 31,784 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 40 kW-hr, 7946 hr/yr, 100% utilization 16,119
NA NA - NA NA - NA NA - Comp Air 0.31 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 100% utilization 6,491 N A N A - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization 75
NA NA - NA NA - NA NA - NA NA - Filter Bags 33.71 $/bag, 419 bags, 7946 hr/yr, 100% utilization 10,787 Total Annual Direct Operating Costs 170,144

Indirect Operating Costs Overhead 60% of total labor and material costs 82,003 Administration (2% total capital costs) 2% of total capital costs (TCI) 20,382 Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,191 Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,191 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 94,355 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 217,122

Total Annual Cost (Annualized Capital Cost + Operating Cost) 387,266

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment I - Emission Control Cost Analysis Table I-5: PM Control -Baghouse

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Filter bags & cages Equipment Life 2 years CRF 0.5531 Rep part cost per unit 33.711 $/bag Amount Required 419 Total Rep Parts Cost 15,749 Cost adjusted for freight & sales tax Installation Labor 3,754 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4
Total Installed Cost 19,503 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag.
A nnualized Cost 10,787

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Baghouse 22,139 10 40.1 Baghouse Shaker 0.0 Gross fabric area ft 2 0 EPA Cont Cost Manual 6th ed Section 6 Chapter 1 Eq 1.14 Other Other Other
Other

Other Total 40.1

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Gross BH Filter Area 5,621 ft 2

Cages 12 ft long 5 in dia 13.42 area/cage ft 2 419 Cages 11.036 $/cage Bags 1.69 $/ft2 of fabric 22.68 $/bag
Total 33.711

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 100.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 9,535 15% of Operator Costs Maintenance Maint Labor 32.00 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,784 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 40.1 kW-hr 318,408 16,119 $/kwh, 40 kW-hr, 7946 hr/yr, 100% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 100% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization Comp Air 0.31 $/mscf 2 scfm/kacfm 21,110 6,491 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 100% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization WW Treat Biotreatemen 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 100% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 65 75 $/ton, 0 ton/hr, 7946 hr/yr, 100% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 100% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 100% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization Filter Bags 33.71 $/bag 419 bags NA 10,787 $/bag, 419 bags, 7946 hr/yr, 100% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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# Attachment J

Steel Mill, Handling Material BACT Cost Tables3/6/2007Minnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment J - Emission Control Cost Analysis Material Handling,Table J-1: Cost Summary - Material Handling, Steel Mill QuicklimePM/PM10 Control Cost Summary *Control TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollutionControl Cost$/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber0.005gr/dscf0.05 18.7 $28,454 $32,180 $1,719 NA None High Waste-waterBaghouse0.0025gr/dscf0.02 18.7 $63,096 $36,469 $1,945 NA None Low Solid WasteDry ElectroStatic Precipitator(ESP)0.005gr/dscf0.05 18.7 $110,499 $42,254 $2,257 NA None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)0.005gr/dscf0.05 18.7 $223,627 $122,155 $6,524 NA None Low Waste-waterUncontrolled0%18.8* Based on highest emission rate if PM not equal to PM10Fluoride Control Cost Summary *Control TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollutionControl Cost$/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber99%0.02 2.20 $28,454 $32,180 $14,657 NANone High Waste-waterBaghouse99%0.02 2.20 $63,096 $36,469 $16,611 NANone Low Solid WasteDry ElectroStatic Precipitator(ESP)99%0.02 2.20 $110,499 $42,254 $19,246 NA None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)99%0.02 2.20 $223,627 $122,155 $55,639 NA None Low Waste-waterUncontrolled0%2.22The control efficiency fluorides are for example calculations and do not represent actual control efficiencies. Fluorospar binis only source of F- emissions in this source groupLead Control Cost Summary *Control TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost$/yrPollutionControl Cost$/tonIncrementalControl Cost$/tonAir Toxic's &AQRV's?EnergyImpacts?Non-Air EnvImpacts?Wet Scrubber99%0.0002 0.02 $28,454 $32,180 $1,731,615 NANone High Waste-waterBaghouse99%0.0002 0.02 $63,096 $36,469 $1,962,434 NANone Low Solid WasteDry ElectroStatic Precipitator(ESP)99%0.0002 0.02 $110,499 $42,254 $2,273,702 NA None Low Solid WasteWet Wall ElectroStaticPrecipitator (WWESP)99%0.0002 0.02 $223,627 $122,155 $6,573,210 NA None Low Waste-waterUncontrolled0%0.02The control efficiency for lead are for example calculations and do not represent actual control efficiencies. EAF dust transfer is the only source of Pb emissions in this source group.P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls Cost Summary3/6/2007 Page 1 of 143/6/2007



### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Steel Mill - Quicklime Study Year 2005
Emission Unit Number EU 115 & 116 Stack/Vent Number SV 039 Reference Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr A verage union labor rate for MN mining industry

Maintenance Labor 32 $/hr A verage union labor rate for MN mining industry

Electricity 0.051 $/kwh 0.049 2004 DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005 A verage natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig Water 0.78 $/mgal 0.76 2004 Kaar Consulting MSI Cost Mode l cost adjusted for 3% inflation

Cooling Water 0.27 $/mgal 0.23 1999 EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1 Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation

Compressed Air 0.31 $/mscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Neutralization 1.64 $/mgal 1.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 C h 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.15 $/mgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Solid Waste Disposal 27.32 $/ton 25.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3 % inflation

Hazardous Waste Disposal 273.18 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3 % inflation

Waste Transport 0.55 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Internal Waste Recycl e 1.16 $/ton 1.00 2000 Corus Study for MN Iron and Steel Projec t Study use $1/ton to cover cost of materials movement

Chemicals & Supplies Lime 25.31 $/ton 24.57 2004 Kaar Consulting MSI Cost Mode l cost adjusted for 3% inflation Causti c 280 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Soda Ash $/ton Oxygen 1.44 Mscf 1.40 2004 Kaar Consulting MSI Cost Mode l cost adjusted for 3% inflation EPA Urea 179.1 $/ton
A mmonia 0.101 $/lb Reagent # 8 $/ton

Catalyst & Replacement Parts SCR Catalyst 500 $/ft 3 Cormetech, Inc. CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst # 3 Catalyst # 4 Catalyst # 5

Filter Bags 36.84 $/bag 33.71 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation Tower Packing 100 $/ft 3 Replacement Parts Replacement Parts Replacement Parts

Other Sales Ta x 6.5 %

Interest Rate 7.00% Per Minnesota Pollution Control Agony request Standard interest rate specified by the US Office of Management and Budge

Operating Information A nnual Op. Hr s 7946 Hours Engineering Estimate Utilization Rat e 26.2% 2004 Kaar Consulting MSI Cost Mode l Equipment Life 20 yrs Engineering Estimate Design Capacity 25,246 Tons/yr Standardized Flow Rate 998 scfm @ 32o F Temperature 77 Deg F Moisture Content 2.0% Actual Flow Rate 1,090 acfm Standardized Flow Rate 1,071 scfm @ 68o F Dry Std Flow Rate 1,050 dscfm @ 68o F

Max Emis Pollutant Lb/Hr Uncontrolled Conc PM10 18.0 2.00 gr/dscf Total Particulates 18.0 2.00 gr/dscf 0.653264497 0.67480916 Nitrous Oxides (NOx) - - ppm Sulfur Dioxide (SO 2 )

- - ppm Sulfuric Acid Mist - - ppm Fluorides 2.1E+00 2.4E-01 gr/dscf 342,077 ppb (Assumes 99% control as PM) Volatile Organic Compounds (VOC) - - ppm 2.1E-02 Fluorspar Bin (SV 042) F- Ratio'd by flow rate (1050/350) Carbon Monoxide (CO) - - ppm 1.80E-04 EAF Dust Transfer (SV 047) Pb - Ratio'd by flow rate (1050/420) Lead (Pb) 1.8E-02 2.0E-03 gr/dscf 531 ppb (Assumes 99% control as PM)

Enter this data for each emission unit Enter data for this study (applies to all units)

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-3: PM Control - Dry ESP

Operating Unit: Steel Mill - Quicklime

Emission Unit Number EU 115 & 116 Stack/Vent Number SV 039 Chemical Engineering Design Capacity 25,246 Tons/yr Standardized Flow Rate 998 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 26% Temperature 77 Deg F 2003 402 Expected Annual Hours of Operation 7,946 Hours Moisture Content 2.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 1,090 acfm Inflation Adj 1.16 Expected Equipment Life 20 yrs Standardized Flow Rate 1,071 scfm @ 68o F Dry Std Flow Rate 1,050 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 40,601 Purchased Equipment Total (B) 22% of control device cost (A) 49,330

Installation - Standard Costs 67% of purchased equip cost (B) 33,051 Installation - Site Specific Costs NA Installation Total 33,051 Total Direct Capital Cost, DC 82,381 Total Indirect Capital Costs, IC 57% of purchased equip cost ( B ) 28,118 Total Capital Investment (TCI) = DC + IC 110,499

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 17,189 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 25,065 Total Annual Cost (Annualized Capital Cost + Operating Cost) 42,254

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 18.0 18.8 0.005 gr/dscf 0.0 18.7 2,257 Total Particulates 18.0 18.8 0.005 gr/dscf 0.0 18.7 2,257 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides 2.1E+00 2.2E+00 99% 2.2E-02 2.2E+00 19,246 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 1.8E-02 1.9E-02 99% 1.9E-04 0.0 2,273,702

Notes & Assumptions
1 Cost Estimate from EPA Air Compliance Advisor Ver 7.7 and adjusted for inflation. No vendor quotes available.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
3 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation
4 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3 5 Reduced operator time to 1/4 hr/shift because the source is so small.
6 Estimated ESP Grid Area at 219 ft 2 per 1000 acfm EPA example problem Manual Section 6 Chapter 3.4.5.1
7 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21
8 The control efficiency for fluorides and lead are for example calculations and do not represent actual control efficiencies.
9 The fluorospar bin is only source of F- emissions in this source group
10 EAF dust transfer is the only source of Pb emissions in this source group.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-3: PM Control - Dry ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 40,601

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 4,060 MN Sales Taxes 6.5% of control device cost (A) 2,639 Freight 5% of control device cost (A) 2,030 Purchased Equipment Total (B) 22% 49,330

Installation

Foundations & supports 4% of purchased equip cost (B) 1,973 Handling & erection 50% of purchased equip cost (B) 24,665 Electrical 8% of purchased equip cost (B) 3,946 Piping 1% of purchased equip cost (B) 493 Insulation 2% of purchased equip cost (B) 987 Painting 2% of purchased equip cost (B) 987 Installation Subtotal Standard Expenses 67% 33,051

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 33,051 Total Direct Capital Cost, DC 82,381

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 9,866 Construction & field expenses 20% of purchased equip cost (B) 9,866 Contractor fees 10% of purchased equip cost (B) 4,933 Start-up 1% of purchased equip cost (B) 493 Performance test 1% of purchased equip cost (B) 493 Model Studies 2% of purchased equip cost (B) 987 Contingencies 3% of purchased equip cost (B) 1,480 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 28,118

Total Capital Investment (TCI) = DC + IC 110,499

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 110,499

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.3 hr/8 hr shift, 7946 hr/yr 7,946 Supervisor 48% % of Operator Costs. 3,814
Maintenance

Maintenance Labor 239 ft2 grid area, 1.0 $/ft2 of grid area 4,771 Maintenance Materials 1 1% of purchased equipment cost 493 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1 kW-hr, 7946 hr/yr, 26.2487065469698% utilization 142
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization 22
NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 17,189

Indirect Operating Costs Overhead 60% of total labor and material costs 10,215 Administration (2% total capital costs) 2% of total capital costs (TCI) 2,210 Property tax (1% total capital costs) 1% of total capital costs (TCI) 1,105 Insurance (1% total capital costs) 1% of total capital costs (TCI) 1,105 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 10,430 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 25,065

Total Annual Cost (Annualized Capital Cost + Operating Cost) 42,254

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Anal y sis Table J-3: PM Control - Dry ESP

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per ba g ( 13 hr total ) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per ba g

. Total Installed Cos t 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower Ba g house & ES P 1,090 4.48 0.9 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 0 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 239 ft 2 1.94E-03 kW/ft 2 0.5 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 1.3

Reagent Use & Other Operating Costs WESP Pump acfm 5 gpm/kacfm 0 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disch 20% of circulating water rate = 0 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 26.2%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.3 hr/8 hr shift 248 7,946 $/Hr, 0.3 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 3,814 % of Operator Costs. Maintenance
Maint Labor 239 ft 2 grid area 0.954 $/ft 2 of grid area 4,771 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 493 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1.3 kW-hr 2,809 142 $/kwh, 1 kW-hr, 7946 hr/yr, 26.2487065469698% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 26.2487065469698% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 26.2487065469698% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization
WW Treat Biotreatemen t 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Waste Transport 0.55 $/ton-mi 0.0 Mi 0 0 $/ton-mi, 0 Mi, 7946 hr/yr, 26.2487065469698% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 19 22 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 26.2487065469698% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 26.2487065469698% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 26.2487065469698% utilization SCR Catalyst 500 $/ft3 0 f t 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 26.2487065469698% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 26.2487065469698% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-4: PM Control - Wet Scrubber

Operating Unit: Steel Mill - Quicklime

Emission Unit Number EU 115 & 116 Stack/Vent Number SV 039 Chemical Engineering Design Capacity 25,246 Tons/yr Standardized Flow Rate 998 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 26% Temperature 77 Deg F 2003 402 Expected Annual Hours of Operation 7,946 Hours Moisture Content 2.0% 2005 465 A nnual Interest Rate 7.0% A ctual Flow Rate 1,090 acfm Inflation Adj 1.16 Expected Equipment Life 20 yrs Standardized Flow Rate 1,071 scfm @ 68o F Dry Std Flow Rate 1,050 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 12,261 Purchased Equipment Total (B) 22% of control device cost (A) 14,897

Installation - Standard Costs 56% of purchased equip cost (B) 8,343 Installation - Site Specific Costs NA Installation Total 8,343 Total Direct Capital Cost, DC 23,240 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 5,214 Total Capital Investment (TCI) = DC + IC 28,454

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 18,106 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 14,074 Total Annual Cost (Annualized Capital Cost + Operating Cost) 32,180

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 18.0 18.8 0.005 gr/dscf 0.0 18.7 1,719 Total Particulates 18.0 18.8 0.005 gr/dscf 0.0 18.7 1,719 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA

Sulfuric Acid Mist - - 0.0 - NA Fluorides 2.1E+00 2.2E+00 99% 2.2E-02 2.2E+00 14,657 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 1.8E-02 1.9E-02 99% 1.9E-04 0.0 1,731,615

Notes & Assumptions
1 Cost Estimate from EPA Air Compliance Advisor Ver 7.7 and adjusted for inflation. No vendor quotes available.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 2 3 Reduced operator time to 1/4 hr/shift and maintenance to 1/8 hr/shift because the source is so small.
4 The control efficiency fluorides are for example calculations and do not represent actual control efficiencies.
5 The control efficiency for fluorides and lead are for example calculations and do not represent actual control efficiencies.
6 The fluorospar bin is only source of F- emissions in this source group
7 EAF dust transfer is the only source of Pb emissions in this source group.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-4: PM Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 12,261

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 1,226 MN Sales Taxes 6.5% of control device cost (A) 797 Freight 5% of control device cost (A) 613 Purchased Equipment Total (B) 22% 14,897

Installation

Foundations & supports 6% of purchased equip cost (B) 894 Handling & erection 40% of purchased equip cost (B) 5,959 Electrical 1% of purchased equip cost (B) 149 Piping 5% of purchased equip cost (B) 745 Insulation 3% of purchased equip cost (B) 447 Painting 1% of purchased equip cost (B) 149 Installation Subtotal Standard Expenses 56% 8,343

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 8,343 Total Direct Capital Cost, DC 23,240

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 1,490 Construction & field expenses 10% of purchased equip cost (B) 1,490 Contractor fees 10% of purchased equip cost (B) 1,490 Start-up 1% of purchased equip cost (B) 149 Performance test 1% of purchased equip cost (B) 149 Model Studies N A of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 447 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 5,214

Total Capital Investment (TCI) = DC + IC 28,454

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 28,454

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.3 hr/8 hr shift, 7946 hr/yr 7,946 Supervisor 15% 15% of Operator Costs 1,192 Maintenance

Maintenance Labor 32.00 $/Hr, 0.1 hr/8 hr shift, 7946 hr/yr 3,973 Maintenance Materials 100.00 % of Maintenance Labor 3,973 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 3 kW-hr, 7946 hr/yr, 26.2487065469698% utilization 361
NA NA - Water 0.78 $/mgal, 2 gpm, 7946 hr/yr, 26.2487065469698% utilization 214
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 2 gpm, 7946 hr/yr, 26.2487065469698% utilization 447
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 18,106

Indirect Operating Costs Overhead 60% of total labor and material costs 10,250 Administration (2% total capital costs) 2% of total capital costs (TCI) 569 Property tax (1% total capital costs) 1% of total capital costs (TCI) 285 Insurance (1% total capital costs) 1% of total capital costs (TCI) 285 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,686 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 14,074

Total Annual Cost (Annualized Capital Cost + Operating Cost) 32,180

See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-4: PM Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3
Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Scrubber 1,090 15 0.6 4.3 3.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.40
L/G ratio* Liquid SPGR D P ft H2O Efficiency Hp kW Circ Pump 10 1.125 40 0.5 0.2 0.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41 H2O WW Disch Pump 2 gpm 1.125 40 0.5 0.0 0.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 2 Eq 2.41

Other Other
Other Total 3.4 * L/G = Gal/1,000 acf

Reagent Use & Other Operating Costs
Caustic Use 0.00 lb/hr SO2 2.50 lb NaOH/lb SO2 0.00 lb/hr Caustic
Lime Use 0.00 lb/hr SO2 1.53 lb Lime/lb SO2 0.00 lb/hr Lime Circulating Water Rate 11 gpm Water Makeup Rate/WW Disch = 20% of circulating water rate = 2 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 26.2%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.25 hr/8 hr shift 248 7,946 $/Hr, 0.3 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 1,192 15% of Operator Costs Maintenance Maint Labor 32 $/Hr 0.125 hr/8 hr shift 124 3,973 $/Hr, 0.1 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 3,973 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 3.4 kW-hr 7,131 361 $/kwh, 3 kW-hr, 7946 hr/yr, 26.2487065469698% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 26.2487065469698% utilization Water 0.78 $/mgal 2.2 gpm 273 214 $/mgal, 2 gpm, 7946 hr/yr, 26.2487065469698% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 26.2487065469698% utilization
WW Treat Neutralizatio n 1.64 $/mgal 2.2 gpm 273 447 $/mgal, 2 gpm, 7946 hr/yr, 26.2487065469698% utilization WW Treat Biotreatemen 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 26.2487065469698% utilization Urea 405 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 26.2487065469698% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 26.2487065469698% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 26.2487065469698% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 26.2487065469698% utilization *annual use rate is in same units of measurement as the unit cost factor See summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-5: PM Control -Baghouse

Operating Unit: Steel Mill - Quicklime

Emission Unit Number EU 115 & 116 Stack/Vent Number SV 039 Chemical Engineering Design Capacity 25,246 Tons/yr Standardized Flow Rate 998 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 26% Temperature 77 Deg F 2003 402 Expected Annual Hours of Operation 7,946 Hours Moisture Content 2.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 1,090 acfm Inflation Adj 1.16 Expected Equipment Life 20 yrs Standardized Flow Rate 1,071 scfm @ 68o F Dry Std Flow Rate 1,050 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 23,713 Purchased Equipment Total (B) 22% of control device cost (A) 28,811

Installation - Standard Costs 74% of purchased equip cost (B) 21,320 Installation - Site Specific Costs NA
Installation Total 21,320 Total Direct Capital Cost, DC 50,131 Total Indirect Capital Costs, IC 45% of purchased equip cost (B ) 12,965 Total Capital Investment (TCI) = DC + I C 63,096

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 17,810 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 18,660 Total Annual Cost (Annualized Capital Cost + Operating Cost ) 36,469

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/y r T/y r $/Ton Rem

PM10 18.0 18.8 0.0025 gr/dscf 0.02 18.7 1,945 Total Particulates 18.0 18.8 0.0025 gr/dscf 0.02 18.7 1,945 Nitrous Oxides (NOx) - - 0.0 - NA Sulfur Dioxide (SO 2 )

- - 0.0 - NA

Sulfuric Acid Mist - - 0.0 - NA Fluorides 2.1E+00 2.2E+00 99% 2.2E-02 2.2E+00 16,611 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 1.8E-02 1.9E-02 99% 1.9E-04 0.0 1,962,434

Notes & Assumptions
1 Cost Estimate from EPA Air Compliance Advisor Ver 7.7 and adjusted for inflation. No vendor quotes available.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1
3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapt er 1.5.1.8
4 Bag replacement at 10 min/bag EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min pe r bag. 5 Reduced operator time to 1/4 hr/shift and maintenance to 1/8 hr/shift because the source is so small.
6 Filter area estimated using air to cloth ratio of 5:1 7 The control efficiency for fluorides and lead are for example calculations and do not represent actual control efficiencie s 8 The fluorospar bin is only source of F- emissions in this source group
9 EAF dust transfer is the only source of Pb emissions in this source group.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-5: PM Control -Baghouse

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 23,713

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 2,371 MN Sales Taxes 6.5% of control device cost (A) 1,541 Freight 5% of control device cost (A) 1,186 Purchased Equipment Total (B) 22% 28,811

Installation

Foundations & supports 4% of purchased equip cost (B) 1,152 Handling & erection 50% of purchased equip cost (B) 14,405 Electrical 8% of purchased equip cost (B) 2,305 Piping 1% of purchased equip cost (B) 288 Insulation 7% of purchased equip cost (B) 2,017 Painting 4% of purchased equip cost (B) 1,152 Installation Subtotal Standard Expenses 74% 21,320

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 21,320 Total Direct Capital Cost, DC 50,131

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 2,881 Construction & field expenses 20% of purchased equip cost (B) 5,762 Contractor fees 10% of purchased equip cost (B) 2,881 Start-up 1% of purchased equip cost (B) 288 Performance test 1% of purchased equip cost (B) 288 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 864 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 12,965

Total Capital Investment (TCI) = DC + I C 63,096

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos t 62,351

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.3 hr/8 hr shift, 7946 hr/yr 7,946 Supervisor 15% 15% of Operator Costs 1,192
Maintenance

Maintenance Labor 32.00 $/Hr, 0.1 hr/8 hr shift, 7946 hr/yr 3,973 Maintenance Materials 100% of maintenance labor costs 3,973 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.05 $/kwh, 2 kW-hr, 7946 hr/yr, 26.2487065469698% utilization 208

NA NA - NA NA - NA NA - Comp Air 0.31 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 26.2487065469698% utiliz a 84 NA NA - NA NA - NA NA - NA NA - NA NA - Waste Recycle 1.16 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization 22
NA NA - NA NA - NA NA - NA NA - Filter Bags 33.71 $/bag, 16 bags, 7946 hr/yr, 26.2487065469698% utilization 412 Total Annual Direct Operating Cost s 17,810

Indirect Operating Costs Overhead 60% of total labor and material costs 10,250 Administration (2% total capital costs) 2% of total capital costs (TCI) 1,262 Property tax (1% total capital costs) 1% of total capital costs (TCI) 631 Insurance (1% total capital costs) 1% of total capital costs (TCI) 631 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,886 Total Annual Indirect Operating Cost s Sum indirect oper costs + capital recovery cost 18,660

Total Annual Cost (Annualized Capital Cost + Operating Cost ) 36,469

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-5: PM Control -Baghouse

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages Equipment Life 2 years CRF 0.5531 Rep part cost per unit 33.711 $/bag Amount Required 16 Total Rep Parts Cost 601 Cost adjusted for freight & sales tax Installation Labo r 143 10 min per bag, Labor + Overhead (68% = $29.65/hr ) EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1. 4 Total Installed Cos t 745 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag
Annualized Cost 412

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower, Baghouse 1,090 10 2.0 Baghouse Shaker 0.0 Gross fabric area ft 2 0 EPA Cont Cost Manual 6th ed Section 6 Chapter 1 Eq 1.14 Other Other Other
Other

Other
Total 2.0

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs
Gross BH Filter Area 210 ft 2

Cages 10 ft long 5 in dia 13.42 area/cage ft 2 16 Cages 11.036 $/cage Bags 1.69 $/ft2 of fabric 22.68 $/bag
Total 33.711

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 26.2%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 0.25 hr/8 hr shift 248 7,946 $/Hr, 0.3 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 1,192 15% of Operator Costs
Maintenance Maint Labor 32.00 $/Hr 0.125 hr/8 hr shift 124 3,973 $/Hr, 0.1 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 3,973 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2.0 kW-hr 4,115 208 $/kwh, 2 kW-hr, 7946 hr/yr, 26.2487065469698% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 26.2487065469698% utilization Water 0.78 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization Comp Air 0.31 $/mscf 2 scfm/kacfm 273 84 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 26.2487065469698% utilization
WW Treat Neutralizatio n 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization WW Treat Biotreatemen 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 19 22 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 26.2487065469698% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 26.2487065469698% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 26.2487065469698% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 26.2487065469698% utilization Filter Bags 33.71 $/bag 16 bags NA 412 $/bag, 16 bags, 7946 hr/yr, 26.2487065469698% utilization
*annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-6: PM Control - Wet Wall ESP

Operating Unit: Steel Mill - Quicklime

Emission Unit Number EU 115 & 116 Stack/Vent Number SV 039 Chemical Engineering Design Capacity 25,246 Tons/yr Standardized Flow Rate 998 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 26% Temperature 77 Deg F 2003 402 Expected Annual Hours of Operation 7,946 Hours Moisture Content 2.0% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 1,090 acfm Inflation Adj 1.16 Expected Equipment Life 20 yrs Standardized Flow Rate 1,071 scfm @ 68o F Dry Std Flow Rate 1,050 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 80,726 Purchased Equipment Total (B) 22% of control device cost (A) 98,082

Installation - Standard Costs 71% of purchased equip cost (B) 69,638 Installation - Site Specific Costs NA Installation Total 69,638 Total Direct Capital Cost, DC 167,721 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 55,907 Total Capital Investment (TCI) = DC + IC 223,627

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 60,426 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 61,729 Total Annual Cost (Annualized Capital Cost + Operating Cost) 122,155

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 18.0 18.8 0.005 gr/dscf 0.0 18.7 6,524 Total Particulates 18.0 18.8 0.005 gr/dscf 0.0 18.7 6,524 Nitrous Oxides (NOx) - - 0.0 - N A Sulfur Dioxide (SO 2 )

- - 0.0 - NA
Sulfuric Acid Mist - - 0.0 - NA Fluorides 2.1E+00 2.2E+00 99% 2.2E-02 2.2E+00 55,639 Volatile Organic Compounds (VOC) - - 0.0 - NA Carbon Monoxide (CO) - - 0.0 - NA Lead (Pb) 1.8E-02 1.9E-02 99% 1.9E-04 0.0 6,573,210

Notes & Assumptions
1 Cost Estimate from EPA Air Compliance Advisor Ver 7.7 and adjusted for inflation. No vendor quotes available.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
3 Piping cost estimated to be 5% of purchase price; same as PM wet scrubber. Change to account for additional piping needed for w ater sprays in WESP.
4 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3. Cost adjusted for inflation
5 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
6 ESP blower electrical use Eq 3.46 EPA Cont Cost Manual Section 6 Chapter 3 7 ESP grid electrical use Eq 3.48 EPA Cont Cost Manual Section 6 Chapter 3
8 WESP pump electrical use Eq 3.48 EPA Cont Cost Manual Section 6 Chapter 3
9 ESP supervision cost = 48% of operator cost = supervisor 15% + coordinator 33% per EPA Cont Cost Manual Section 6 Chapter 3. Table 3.21
10 The control efficiency for fluorides and lead are for example calculations and do not represent actual control efficiencies.
11 The fluorospar bin is only source of F- emissions in this source group

12 EAF dust transfer is the only source of Pb emissions in this source group.

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-6: PM Control - Wet Wall ESP

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 80,726

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 8,073 MN Sales Taxes 6.5% of control device cost (A) 5,247 Freight 5% of control device cost (A) 4,036 Purchased Equipment Total (B) 22% 98,082

Installation

Foundations & supports 4% of purchased equip cost (B) 3,923 Handling & erection 50% of purchased equip cost (B) 49,041 Electrical 8% of purchased equip cost (B) 7,847 Piping (3) 5% of purchased equip cost (B) 4,904 Insulation 2% of purchased equip cost (B) 1,962 Painting 2% of purchased equip cost (B) 1,962 Installation Subtotal Standard Expenses 71% 69,638

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 69,638 Total Direct Capital Cost, DC 167,721

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 19,616 Construction & field expenses 20% of purchased equip cost (B) 19,616 Contractor fees 10% of purchased equip cost (B) 9,808 Start-up 1% of purchased equip cost (B) 981 Performance test 1% of purchased equip cost (B) 981 Model Studies 2% of purchased equip cost (B) 1,962 Contingencies 3% of purchased equip cost (B) 2,942 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 55,907

Total Capital Investment (TCI) = DC + IC 223,627

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 223,627

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr 31,784 Supervisor 48% % of Operator Costs. 15,256
Maintenance

Maintenance Labor 35,000 ft2 grid area, 1.0 $/ft2 of grid area 4,771 Maintenance Materials 1 1% of purchased equipment cost 981 Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 69 kW-hr, 7946 hr/yr, 26.2487065469698% utilization 7,303
NA NA - Water 0.78 $/mgal, 1 gpm, 7946 hr/yr, 26.2487065469698% utilization 107
NA NA - NA NA - WW Treat Neutralization 1.64 $/mgal, 1 gpm, 7946 hr/yr, 26.2487065469698% utilization 224
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 60,426

Indirect Operating Costs Overhead 60% of total labor and material costs 31,676 Administration (2% total capital costs) 2% of total capital costs (TCI) 4,473 Property tax (1% total capital costs) 1% of total capital costs (TCI) 2,236 Insurance (1% total capital costs) 1% of total capital costs (TCI) 2,236 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 21,109 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 61,729

Total Annual Cost (Annualized Capital Cost + Operating Cost) 122,155

See Summary page for notes and assumptions

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### Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Table J-6: PM Control - Wet Wall ESP

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Equipment Life 5 years
CRF 0.0000 Rep part cost per unit 500 $/ft 3
Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 A ssume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed A nnualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 36.83582717 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
A nnualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW Blower Baghouse & ES P 1,090 4.48 0.9 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq. flow Liquid SPGR D P ft H2O Efficiency Hp kW WESP Pump 5 gpm 1.000 40 0.5 0.1 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 1 gpm 1.000 40 0.5 0.0 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.47

ESP Grid 35,144 ft 2 1.94E-03 kW/ft 2 68.2 EPA Cont Cost Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 69.2

Reagent Use & Other Operating Costs WESP Pump 1,090 acfm 5 gpm/kacfm 5 gpm EPA Cont Cost Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disc h 20% of circulating water rate = 1 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 26.2%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 32 $/Hr 1.0 hr/8 hr shift 993 31,784 $/Hr, 1.0 hr/8 hr shift, 7946 hr/yr Supervisor 48% of Operator Costs. NA 15,256 % of Operator Costs. Maintenance Maint Labor 35,000 ft2 grid area 0.954 $/ft 2 of grid area 4,771 ft2 grid area, 1.0 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 981 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 69.2 kW-hr 144,252 7,303 $/kwh, 69 kW-hr, 7946 hr/yr, 26.2487065469698% utilization Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7946 hr/yr, 26.2487065469698% utilization Water 0.78 $/mgal 1.1 gpm 136 107 $/mgal, 1 gpm, 7946 hr/yr, 26.2487065469698% utilization Cooling Water 0.27 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 26.2487065469698% utilization
WW Treat Neutralizatio n 1.64 $/mgal 1.1 gpm 136 224 $/mgal, 1 gpm, 7946 hr/yr, 26.2487065469698% utilization WW Treat Biotreatemen 4.15 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization SW Disposal 27.32 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Haz W Disp 273 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Waste Transport 0.55 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Waste Recycle 1.16 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7946 hr/yr, 26.2487065469698% utilization Lime 25.309984 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 26.2487065469698% utilization Caustic 280 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7946 hr/yr, 26.2487065469698% utilization Oxygen 1.442 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7946 hr/yr, 26.2487065469698% utilization SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7946 hr/yr, 26.2487065469698% utilization Filter Bags 36.8358272 $/bag 0 bags 0 0 $/bag, 0 bags, 7946 hr/yr, 26.2487065469698% utilization *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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# Attachment K

Diesel Powered Stationary EnginesMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment K - Emission Control Cost AnalysisTable K-1: Cost Summary - Emergency Generators and PumpsPM/PM10 Control Cost SummaryControl TechnologyControlEff %EmissionReductionT/yrInstalledCapital Cost$AnnualizedOperatingCost $/yrPollutionControl Cost$/tonEmergency GeneratorClassificationMinimum98%30.38* NA NA Site SpecificGCPVaries byDesignNA NA NA Site SpecificOxidation Catalyst 30% 0.53 $5,031,939 $552,480 $1,040,452Diesel Filter 90% 1.59 $4,206,913 $461,896 $289,954* for 8760 hrsSO2 Control Cost SummaryControl TechnologyControlEff %EmissionReductionT/yrInstalledCapital Cost$AnnualizedOperatingCost $/yrPollutionControl Cost$/tonEmergency GeneratorClassificationMinimum98%20.8* NA NA Site SpecificLow Sulfur FuelVaries by% SulfurcontentFuel specific NA NA Site Specific* for 8760 hrsAttach K - Emergency Generator Sept 2006 Revision3/6/2007 Page 1 of 5Minnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment K - Emission Control Cost AnalysisTable K-1: Cost Summary - Emergency Generators and PumpsNOx Control Cost SummaryControl TechnologyControlEff %EmissionReductionT/yrInstalledCapital Cost$AnnualizedOperatingCost $/yrPollutionControl Cost$/tonEmergency GeneratorClassification combinedwith GCPMinimum98%859 NA NA Site SpecificSCR 90% 45 $11,685,869 $1,290,046 $28,645* based on 8760 hrs.CO/VOC Control Cost SummaryControl TechnologyControlEff %EmissionReductionT/yrInstalledCapital Cost$AnnualizedOperatingCost $/yrPollutionControl Cost$/tonEmergency GeneratorClassification combinedwith GCPMinimum98%225* NA NA Site SpecificOxidation Catalyst CO: 98% 11.14 $5,031,939 $552,480 $49,583VOC: 90% 1.57 $5,031,939 $552,480 $352,797* based on 8760 hrs.Attach K - Emergency Generator Sept 2006 Revision3/6/2007 Page 2 of 5

# BACT Report -Attachment K - Emission Control Cost Analysis

Ca p ital Recover y Factor s Primar y Installatio n Interest Rate 7.0% Equipment Life 15 years Equipment Life Estimate (1) CRF 0.1098

Ca p ital Cos t Equipment Life 15 years
CRF 0.1098 Unit Cost 806200 $/unit MACE Estimate (2) Annual Cost 7000.00 $ CCEE Estimate (1)
# of units 13.00 Capital Cost 11,685,869 Cost adjusted for freight & sales tax Installation Labor 0 Assume packaged unit
Total Installed Cost 11,685,869 Annualized Cost 1,290,046

Control Efficiency (%) 90 (2) Uncontrolled NOx Emissions (tpy) 50.040 Controlled PM Emissions (tpy) 5.004 Emission Reduction PM (tpy) 45.036

Controlled Cost ($/ton PM) $28,645

Notes: (1) "Control of Compressor Emissions, Related Costs and Considerations, Thomas P. Mark, 10/31/03. (2) "Emission Control Technology for Stationary Internal Combustion Engines", MACE, July 1997. 

# Table K-2: Control Cost Analysis NOx Emission Controls: SCR

Attach K - Emergency Generator Sept 2006 RevisionSCR NOx 3/6/2007 Page 3 of 3

# BACT Report -Attachment K - Emission Control Cost Analysis

PM/VOC/CO Emission Controls: Oxidation Catalyst

Ca p ital Recover y Factor s Primar y Installatio n Interest Rate 7.0% Equipment Life 15 years Equipment Life Estimate (1) CRF 0.1098

Catal y st Re p lacement Cos t Equipment Life 15 years
CRF 0.1098 Catalyst cost per unit 53000 $/f t 3 

## Vendor Estimate (2) Amount Required 6.55 f t 3



## # of units 13.00 Catalyst Cost 5,031,939 Cost adjusted for freight & sales tax Installation Labor 0 Assume packaged unit
Total Installed Cost 5,031,939 Annualized Cost 552,480

PM Control Efficiency (%) 30 (3) Uncontrolled PM Emissions (tpy) 1.770 Controlled PM Emissions (tpy) 1.239 Emission Reduction PM (tpy) 0.531

Controlled Cost ($/ton PM) $1,040,452

VOC Control Efficiency (%) 90 (3) Uncontrolled VOC Emissions (tpy) 1.740 Controlled VOC Emissions (tpy) 0.174 Emission Reduction VOC (tpy) 1.566 Combined CO & VOC Efficiency: Controlled Cost ($/ton VOC) $352,797 $43,473

CO Control Efficiency (%) 98 (3) Uncontrolled CO Emissions (tpy) 11.370 Controlled CO Emissions (tpy) 0.227 Emission Reduction PM (tpy) 11.143

Controlled Cost ($/ton CO) $49,583

Notes: (1) "Control of Compressor Emissions, Related Costs and Considerations, Thomas P. Mark, 10/31/03. (2) Ziegler Power Systems, proposal cost estimate for a catalytic oxidiation unit, 10/22/03 (3) "Emission Control Technology for Stationary Internal Combustion Engines", MACE, July 1997. 

# Table K-3: Control Cost Analysis

Attach K - Emergency Generator Sept 2006 RevisionOxidation Catalyst PM 3/6/2007 Page 4 of 5

# BACT Report -Attachment K - Emission Control Cost Analysis

Ca p ital Recover y Factor s Primar y Installatio n Interest Rate 7.0% Equipment Life 15 years Equipment Life Estimate (1) CRF 0.1098

Ca p ital Cos t Equipment Life 15 years
CRF 0.1098 Unit Cost 36 $/bhp Vendor Estimate (2) Equipment Size 8062.00 bhp
# of units 13.00 Capital Cost 4,206,913 Cost adjusted for freight & sales tax Installation Labor 0 Assume packaged unit
Total Installed Cost 4,206,913 Annualized Cost 461,896

Control Efficiency (%) 90 (2) Uncontrolled PM Emissions (tpy) 1.770 Controlled PM Emissions (tpy) 0.177 Emission Reduction PM (tpy) 1.593

Controlled Cost ($/ton PM) $289,954

Notes: (1) "Control of Compressor Emissions, Related Costs and Considerations, Thomas P. Mark, 10/31/03. (2) "Emission Control Technology for Stationary Internal Combustion Engines", MACE, July 1997. (3) Based on fuel input capacity of 3.86 mmbtu/hr 

# PM Emission Controls: Diesel Filter Table K-4: Control Cost Analysis

Attach K - Emergency Generator Sept 2006 RevisionDiesel Filter PM 3/6/2007 Page 5 of 5

# Attachment L

RACT/BACT/LAER Clearinghouse SummaryMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-1: TaconiteControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME THROUGHPUTUNITS POLLUTANT CONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1UNITS CASE-BYCASEBASISEMISSIONLIMIT 2UNITS STDEMISSIONLIMITUNITSMN-0064 NORTHSHORE MININGCOMPANY3/22/2006 FURNACE 5 HOOD EXHAUST(WASTE GAS (#501, #502, #503)160 LT/H pellets Particulate Matter(PM)A ELECTROSTATIC PRECIPITATER -HIGH EFFICIENCY (WET ESP)0.01 GR/DSCF BACT-PSD 0.18 LB/MMBTUMN-0064 NORTHSHORE MININGCOMPANY3/22/2006 FURNACE 5 HOOD EXHAUST(WASTE GAS (#501, #502, #503)160 LT/H pellets Particulate Matter< 10 μ (PM10)N WET SCRUBBER, HE 0.005 GR/DSCF BACT-PSDMN-0064 NORTHSHORE MININGCOMPANY3/22/2006 FURNACE 5 HOOD EXHAUST(WASTE GAS (#501, #502, #503)160 LT/H pellets Nitrogen Oxides(NOx)N 40 PPM @ 15%O2BACT-PSD 46 LB/HMN-0064 NORTHSHORE MININGCOMPANY3/22/2006 FURNACE 5 HOOD EXHAUST(WASTE GAS (#501, #502, #503)160 LT/H pellets Sulfur Dioxide(SO2)A WET ESP, HE 0.13 LB/MMBTU 0.072 LB/MMBTUMN-0036 ISPAT INLAND MININGCO.1/14/2000 METAL ORE MINING, TACONITE,INDURATING FURNACE370 MMBTU/H Nitrogen Dioxide(NO2)P FUEL USE IS LIMITED TO 270MMBTU/HR FOR ALL EU26BURNERS COMBINED (4 STACKS)IN ADDITION TO THE USE OFEXISTING LOW NOX BURNERS. 11CONTROL OPTIONS EXAMINED.1088 LB/H BACT-PSDBACT-PSD Emission LimitsPollutantBACT LimitUnitsPM0.01GR/DSCFPM100.005GR/DSCFSO20.13LB/MMBTUNOx40PPM @ 15% O2No Performance LimitsTaconite RBLC BACT Limits SummaryOther (non-BACT)-case-by-case PM10Emission Limitspage 1 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-2: Direct Reduced Iron (DRI)Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcType FuelTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSLA-0107LOUISIANA IRONWORKS (TONDU) - DRIPLANT5/5/1996REFORMER FURNACEDRINATURALGAS1160.6 MMBTU/H PM10SCRUBBING SPENT GAS FROM THE DRIFURNACE0.001GR/SCFBACT-PSD 6.92LB/H 0.001GR/DSCFLA-0101AMERICAN IRONREDUCTION - GULFCOAST DRI FACILITY3/18/1996REFORMER FURNACES, 2 UNITSDRINATURALGAS1090 MMBTU/H PM10SCRUBBING SPENT GAS FROM THE DRIFURNACES0.003GR/SCFBACT-PSD 6.14LB/H 0.003GR/DSCFMO-0011PEA RIDGE IRON ORECO.8/9/1995ADDITION OF DIRECTREDUCTION FURNACE&COALHANDLINGDRI#6RESIDUALFUEL OIL0.01 GRAIN\DRYPM10USES A #6 RESIDUAL FUEL OIL. SPRAYDRYER \ FABRIC FILTER Barr EngineeringNote: Facility shut down in 2001. Newequipment probably not installed. RBLC hasnote that in 1997 startup was delayed due tolack of funds.0.01GR/DSCFBACT-PSD 0LA-0101AMERICAN IRONREDUCTION - GULFCOAST DRI FACILITY3/18/1996REFORMER FURNACES, 2 UNITSDRINATURALGAS1090 MMBTU/H NOXLOW NOX BURNERS0.132LB/MMBTUBACT-PSD 143.88LB/HAL-0086TUSCALOOSA STEELCORP. - MOBILE DRIPLANT10/10/1995DIRECT REDUCED IRONMATERIAL HANDLING SYSTEMDRI 150 T/H PMCYCLONE AND VENTURI SCRUBBER0.63LB/HBACT-PSD 0AL-0086TUSCALOOSA STEELCORP. - MOBILE DRIPLANT10/10/1995REFORMER AND DIRECTREDUCED IRON SHAFT FURNACEDRI 150 T/H PMVENTURI SCRUBBER1.5LB/HBACT-PSD 0.02LB/T DRIMO-0011PEA RIDGE IRON ORECO.8/9/1995ADDITION OF DIRECTREDUCTION FURNACE&COALHANDLINGDRI#6RESIDUALFUEL OIL0.01 GRAIN\DRYNOX#6 RESIDUAL FUEL OIL, SNCR BarrEngineering Note: Facility shut down in 2001.New equipment probably not installed. RBLChas note that in 1997 startup was delayeddue to lack of funds.52LB/HRBACT-PSD 0MO-0011PEA RIDGE IRON ORECO.8/9/1995ADDITION OF DIRECTREDUCTION FURNACE&COALHANDLINGDRI#6RESIDUALFUEL OIL0.01 GRAIN\DRYSO2USES A #6 RESIDUAL FUEL OIL SPRAYDRYER\ FABRIC FILTER Barr EngineeringNote: Facility shut down in 2001. Newequipment probably not installed. RBLC hasnote that in 1997 startup was delayed due tolack of funds.104LB/HRBACT-PSD 0AL-0086TUSCALOOSA STEELCORP. - MOBILE DRIPLANT10/10/1995REFORMER AND DIRECTREDUCED IRON SHAFT FURNACEDRI 150 T/H NOXLOW NOX BURNERS105LB/HBACT-PSD 0.7LB/T DRILA-0107LOUISIANA IRONWORKS (TONDU) - DRIPLANT5/5/1996REFORMER FURNACEDRINATURALGAS1160.6 MMBTU/H NOXLOW NOX BURNERS153LB/HBACT-PSD 612.02T/YRBACT-PSD PM10 gr/dscf Emission LimitsMIN0.001GR/DSCFMAX 0.01 GR/DSCFMEDIAN 0.003 GR/DSCFCOUNT3CASESBACT-PSD SO2 Emission LimitsSO2BACT-PSD NOx Emission LimitsNOx0.132lb/MMBtuNOx0.02lb/t DRIOther (non-BACT)-case-by-case NOx Emission LimitsNo Performance LimitsNo Performance LimitsDRI RBLC BACT Limits SummaryOther (non-BACT)-case-by-case PM10 Emission LimitsNo Performance LimitsOther (non-BACT)-case-by-case SO2 Emission LimitsNo Performance Limitspage 2 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-3: Electric Arc Furnace (EAF)- PM10RBLC ID FACILITY NAMEPERMITDATEPROCESSNAMEProcType FUELTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSIN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE,ELECTRIC ARC(EAF)EAF 200 T/YR PM10FABRIC FILTERS (BAGHOUSE).SEE NOTES0.0052GR/DSCFBACT-PSD 0.0052GR/DSCFAR-0030ARKANSAS STEELASSOCIATES9/24/1998ELECTRIC ARCFURNACEEAF 50 T/H PM10BAGHOUSE0.0052GR/DSCFBACT-PSD 0.0052GR/DSCFPA-0214J & L SPECIALTYSTEEL, INC.4/2/2003ELECTRIC ARCFURNACE, (2)EAF 720000 T/YR PM10GOOD COMBUSTIONPRACTICES1.14LB/HBACT-PSD 5T/YR0.0018GR/DSCFVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998FURNACE,ELECTRIC ARC #5EAF 100 T/H OF STEEL PM10CONTROLLED BY BAGHOUSE7.5LB/HBACT-PSD 32.8T/YROH-0276CHARTER STEEL4/14/2003ELECTRIC ARCFURNACEEAF 110 T/H MELT PM10BAGHOUSE12.43LB/HBACT-PSD 40.15T/YR0.0024GR/DSCFNJ-0040CO-STEEL RARITAN12/19/1996ELECTRIC ARCFURNACEEAF 1160320 T/YR PM10PSE AND CANOPY HOODDRAW EXHAUST GASES TOBAGHOUSES WITH CAPACITYOF 1,000,000 ACFM.20LB/HBACT-PSD 6.7MG/DSCM0.003GR/DSCFTX-0398NUCOR JEWETT PLANT5/5/2000ELECTRIC ARCFURNACEEAF 600000 T/YR PM10FF30LB/HBACT-PSD 243.26T/YRTX-0398NUCOR JEWETT PLANT5/5/2000EAF BAGHOUSEEAF PM10 30.9LB/HBACT-PSDAR-0078NUCOR STEEL,ARKANSAS9/9/1999EAFEAF 425 t/h PM10FABRIC FILTER37LB/HBACT-PSD 162.1T/YR0.0018GR/DSCF*OH-0294NUCOR STEELMARION, INC.8/18/2005ELECTRIC ARCFURNACE(FUGITIVEEMISSIONS)EAF 70 T/H PM10USE OF SEGMENTED CANOPYHOOD, SCAVENGER DUCTING,CROSS-DRAFT PARTITIONINGAND CLOSED ROOFMONITORS.81.2T/YRBACT-PSDOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARCFURNACE (EAF)NO. 9, P907EAF 165 T/H PM10FABRIC FILTER, STACK TESTWAS NOT DONE FOR PM1043.17LB/HN/A 50.6T/YR0.0032GR/DSCFOH-0245TECHNOLOGIESINTERNATIONAL1/27/1999FURNACE (EAF)NO. 7, P905EAF 85 T/H PM10FABRIC FILTER, STACK TESTWAS NOT DONE ON PM1043.17LB/HN/A 189.24T/YRPA-0178ELLWOOD QUALITYSTEELS CO.4/30/2001ELECTRIC ARCFURNACEEAF 53 T/BATCH PM10DIRECT EVACUATION SYSTEM,BAGHOUSE0.15LB/TOther Case-by-Case 31T/YR0.0052GR/DSCFWA-0319NUCOR STEEL9/8/2004EAF, HIGHTEMPERATUREBAGHOUSEEAF 795000 t/yr PM10BAGHOUSE7.14LB/HOther Case-by-Case 0.0018GR/DSCFWA-0319NUCOR STEEL9/8/2004EAF, LOWTEMPERATUREBAGHOUSEEAF 795000 t/yr PM10LOW TEMPERATUREBAGHOUSE7.93LB/HOther Case-by-Case 0.0017GR/DSCFUT-0061NUCOR STEELCORPORATION8/29/1997ELECTRIC ARCFURNACES (#1 )EAF 65 T (EACH) PM10FABRIC FILTER15.43LB/HOther Case-by-Case 0.0026GR/DSCFNE-0025NUCOR STEELDIVISION6/22/2004ELECTRIC ARCFURNACEEAF 56 MMBTU/H PM10DIRECT EVACUATIONCONTROL (DEC)28.78LB/HOther Case-by-CaseOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005ELECTRIC ARCFURNACEEAF 350 t/h PM10BAGHOUSE15.57LB/H59.96T/YR0.0032GR/DSCFBACT-PSD PM10 gr/dscf Emission LimitsMIN0.0018GR/DSCF MIN0.0017GR/DSCFMAX0.0052GR/DSCF MAX0.0052GR/DSCFMEDIAN0.0030GR/DSCF MEDIAN0.0026GR/DSCFCOUNT7CASES COUNT5CASESOther (non-BACT)-case-by-case PM10 gr/dscfEmission LimitsEAF RBLC PM10 BACT Limits Summarypage 3 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-4: Electric Arc Furnace (EAF)- PMRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASE BASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0021QUANEXCORPORATION -MACSTEEL DIVISION2/18/1998ELECTRIC ARC FURNACES, 2EAF 86 T/H PMPOSITIVE PRESSUREMULTICOMPARTMENT BAGHOUSE0.0018GR/DSCFBACT-PSD 27.4LB/H0AL-0197NUCOR STEELDECATUR, LLC7/11/2002ELECTRIC ARC FURNACE, (2)EAF 440 T/H PMBAGHOUSE0.0032GR/DSCFBACT-PSD 46.7LB/H0.0032GR/DSCFIN-0073QUALITECH STEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/H PMDIRECT SHELL EVAC; BAGHOUSE.THE FURNACE IS IN ENCLOSEDBUILDING. MATERIAL DELIVEREDTHROUGH HOLE IN FLOOR.BAGHOUSE COLLECTOR FORFURNACE AND ROOM.0.0032GR/DSCFBACT-PSD 0 0.0032GR/DSCFAL-0124SIMCALA INC9/18/1998FURNACE, ELECTRIC ARCSILICONEAF 20 MW PMPOSITIVE PRESSURE BAGHOUSEAND MULTICLONES0.0032GR/DSCFBACT-PSD 7.3LB/H0.37LB/MW-HAL-0129IPSCO STEEL INC10/16/1998FURNACE, ELECTRIC ARCEAF 200 T/H PMBAGHOUSE WITH STACK0.0033GR/DSCFBACT-PSD 21.8LB/H0VA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998FURNACE, ELECTRIC ARC #5EAF 100 T/H OF STEEL PMCONTROLLED BY BAGHOUSE0.0034GR/DSCFBACT-PSD 9.8LB/H0.0034GR/DSCFCO-0054CF & I STEEL L.P. DBAROCKY MOUNTAINSTEEL MILLS6/21/2004ELECTRIC ARC FURNACE (EAF)EAF 156 T/H PMFF(FABRIC FILTER)0.0052GR/DSCFBACT-PSD 0.0052GR/DSCFMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF 560000 T/YR PMSIDE DRAFT/CANOPY HOOD ANDBAGHOUSE0.0052GR/DSCFBACT-PSD 24.7LB/H0.0052GR/DSCFTX-0417NUCOR CORP.1/15/2003ELECTRIC ARC FURNACEEAF PMBAGHOUSE FILTRATION SYSTEM0.0052GR/DSCFBACT-PSD 0.0052GR/DSCFAR-0044ARKANSAS STEELASSOCIATES1/5/2001FURNACE, ELECTIC ARCEAF 50 T/H PMBAGHOUSE.0.0052GR/DSCFBACT-PSD 0.0052GR/DSCFKY-0094NORTH AMERICANSTAINLESS12/1/2003EAFEAF 154 t/batch PMBAGHOUSE13.94LB/HBACT-PSD 0.1LB/T13.94LB/HNJ-0040CO-STEEL RARITAN12/19/1996ELECTRIC ARC FURNACEEAF 1160320 T/YR PMPSE AND CANOPY HOOD DRAWEXHAUST GASES TO BAGHOUSESWITH CAPACITY OF 1,000,000 ACFM20LB/HBACT-PSD 6.7MG/DSCM0.003GR/DSCFAL-0202CORUS TUSCALOOSA6/3/2003ELECTRIC ARC FURNACEEAF 160 T/H PMDIRECT EVACUATION CANOPY,ELEPHANT HOUSE, AND MELTSHOPBAGHOUSE32.5LB/HBACT-PSD 0.0035GR/DSCF0.0035GR/DSCFOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 7, P905EAF 85 T/H PMFABRIC FILTER, DIRECT EVACUATIONCONTROL (DEC) AND BUILDINGEVACUATION SYSTEM56.8LB/HN/A 249T/YR0.0032GR/DSCFOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 9, P907EAF 165 T/H PMFABRIC FILTER, DIRECT EVACUATIONCONTROL (DEC) AND BUILDINGEVACUATION SYSTEM56.8LB/HN/A 249T/YR0.0032GR/DSCFIA-0031IPSCO STEEL INC3/14/1996ELECTRIC ARC FURNACE/STEELFOUNDRYEAF 230 T/H PMBAGHOUSE-POLYBAGS 32MODULES/260 BAGS PER MODULE0.0033GR/DSCFOther Case-by-Case25.1LB/H0.0033GR/DSCFTN-0122HOEGANAESCORPORATION2/11/2000ELECTRIC ARC FURNACE (EAF)EAF 45 MVA/70.4 MMBTU/H PMFABRIC FILTER18.07LB/HOther Case-by-Case 0.0052GR/DSCFNE-0025NUCOR STEEL DIVISION6/22/2004ELECTRIC ARC FURNACEEAF 56 MMBTU/H PMDIRECT EVACUATION CONTROL(DEC)37.89LB/HOther Case-by-CaseIN-0070NUCOR STEEL6/20/1996ELECTRIC ARC FURNACE (EAF)EAF 502 T/H PMBAGHOUSE101.2T/YROther Case-by-Case 0.0018GR/DSCFOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005ELECTRIC ARC FURNACEEAF 350 t/h PMBAGHOUSE0.0032GR/DSCF78.89T/YR0.0032GR/DSCF*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(FUGITIVE EMISSIONS)EAF 70 T/H PMUSE OF SEGMENTED CANOPY HOOD,SCAVENGER DUCTING, CROSSDRAFT PARTITIONING AND CLOSEDROOF MONITORS.140T/YRBACT-PSD PM gr/dscf Emission LimitsMIN 0.0018 GR/DSCF MIN 0.0018 GR/DSCFMAX 0.0052 GR/DSCF MAX 0.0052 GR/DSCFMEDIAN 0.0033 GR/DSCF MEDIAN 0.0032 GR/DSCFCOUNT13CASES COUNT5CASESOther (non-BACT)-case-by-case PM gr/dscf EmissionLimitsEAF RBLC PM BACT Limits Summarypage 4 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-5: Electric Arc Furnace (EAF)- SO2 and SOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSTN-0155NUCOR STEELCORPORATION11/6/2000ELECTRIC ARC FURNACEEAF 150 T/H SO2LIMIT HIGH-SULFUR STEEL PRODUCTIONTO 125,000 TON/YR; MAINTENANCE OF ALOG OF IRON PYRITE USAGE DURINGHIGH-SULFUR STEEL PRODUCTION,PROPERLY DESIGNED EAF; SCRAPMANAGEMENT PLAN0.16LB/TBACT-PSD 3.5PPMVAR-0077BLUEWATER PROJECT7/22/2004ELECTRIC ARC FURNACE (EAF)EAF 350 t/h SO2LOW SULFUR COKE AND SCRAPMANAGEMENT0.2LB/TBACT-PSDTX-0417NUCOR CORP.1/15/2003ELECTRIC ARC FURNACEEAF SO2LOW SULFUR FUEL0.35LB/TBACT-PSDSC-0072SMI STEEL - SOUTHCAROLINA11/26/2001EAFEAF 850000 T/YR SO2SCRAP MANAGEMENT PLAN0.35LB/TBACT-PSDAL-0129IPSCO STEEL INC10/16/1998FURNACE, ELECTRIC ARCEAF 200 T/H SO2 0.7LB/TBACT-PSD 140LB/H0AR-0030ARKANSAS STEELASSOCIATES9/24/1998ELECTRIC ARC FURNACEEAF 50 T/H SO2DES WITH NO ADD-IN CONTROLS(EXISTING)0.7LB/TBACT-PSD 35LB/H*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(FUGITIVE EMISSIONS)EAF 70 T/H SO2 0.7T/YRBACT-PSDMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF 560000 T/YR SO2 1LB/T STEELPRODUCEDBACT-PSD 280T/YRAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001FURNACE, ELECTRIC ARCEAF 225 T/H SO2LOW SULFUR COKE/SCRAPMANAGEMENT.1.5LB/TBACT-PSDNJ-0040CO-STEEL RARITAN12/19/1996ELECTRIC ARC FURNACEEAF 1160320 T/YR SOXBAGHOUSE2LB/HBACT-PSDVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998FURNACE, ELECTRIC ARC #5EAF 100 T/H OF STEESO2 16.8LB/HBACT-PSD 73.5999T/YR0*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(STACK EMISSIONS)EAF 70 T/H SO2 17.5LB/HBACT-PSD 70T/YRNY-0094NUCOR AUBURN STEEL6/22/2004EAFEAF 110 t/h SO2 25.3LB/HBACT-PSD 0.25LB/TIN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF 200 T/YR SO2SULFUR CONTENT OF DIRECT REDUCEDIRON, CHARGE CARBON, AND INJECTIONCARBON50LB/HBACT-PSD 0.25LB/T*AR-0086NUCOR-YAMATO STEELCOMPANY,BLYTHEVILLE MILL6/11/2004EAF #1 BAGHOUSE, SN-01EAF 450 T/H STEEL SO2LOW SULFUR COKE USAGE90LB/HBACT-PSD 394.2T/YR0.2LB/T STEELAR-0021QUANEXCORPORATION -MACSTEEL DIVISION2/18/1998ELECTRIC ARC FURNACES, 2EAF 86 T/H SO2USE OF HIGH QUALITY SCRAP90.3LB/HBACT-PSD 0 0AL-0202CORUS TUSCALOOSA6/3/2003ELECTRIC ARC FURNACEEAF 160 T/H SO2 99.2LB/HBACT-PSD 0.62LB/TIN-0073QUALITECH STEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/H SO2LIMIT OPERATIONS; THREE BAR WITHDIFFERENT SULFUR CONTENT: LOWSULFUR .003 LBS/TON, 1100 SERIES .52LBS/TON AND 1200 SERIES 1.4 LBS/TON149T/YRBACT-PSD 0 0AR-0078NUCOR STEEL,ARKANSAS9/9/1999EAFEAF 425 t/h SO2SCRAP MANAGEMENT155LB/HBACT-PSD 678.9T/YRAL-0197NUCOR STEELDECATUR, LLC7/11/2002ELECTRIC ARC FURNACE, (2)EAF 440 T/H SO2 220LB/HBACT-PSD 0.5LB/TOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 7, P905EAF 85 T/H SO2LOOKED AT CHARGE SUBSTITUTION(NOT FEASIBLE) AND SO2 CONTROLS(NOT FEASIBLE)5.95LB/HN/A 26.1T/YROH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 9, P907EAF 165 T/H SO2LOOKED AT CHARGE SUBSTITUTION(NOT FEASIBLE) AND SO2 CONTROLS(NOT FEASIBLE)11.55LB/HN/A 50.6T/YRPA-0214J & L SPECIALTY STEEL,INC.4/2/2003ELECTRIC ARC FURNACE, (2)EAF 720000 T/YR SOX 0.09LB/HOther Case-by-CaseOH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003EAFEAF 200 T/H SO2 0.15LB/TOther Case-by-Case 30LB/HCO-0054CF & I STEEL L.P. DBAROCKY MOUNTAINSTEEL MILLS6/21/2004ELECTRIC ARC FURNACE (EAF)EAF 156 T/H SO2ALTERNATIVE RAW MATERIALS +PROCESS CONTROLS0.25LB/T (STEELPRD).Other Case-by-CasePA-0178ELLWOOD QUALITYSTEELS CO.4/30/2001ELECTRIC ARC FURNACEEAF 53 T/BATCH SO2DIRECT EVACUATION SYSTEM0.45LB/TOther Case-by-Case 92.9T/YRTN-0122HOEGANAESCORPORATION2/11/2000ELECTRIC ARC FURNACE (EAF)EAF 45 MVA/70.4 MMSO2SULFUR CONTENT OF NO. 2 FUEL OILLIMITED TO 0.25% BY WEIGHT3.86LB/HOther Case-by-Case 0.07LB/TIA-0031IPSCO STEEL INC3/14/1996ELECTRIC ARC FURNACE/STEELFOUNDRYEAF 230 T/H SO2BASELINE NO CONTROL14LB/HOther Case-by-Case 61T/YR0page 5 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-5: Electric Arc Furnace (EAF)- SO2 and SOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSUT-0061NUCOR STEELCORPORATION8/29/1997ELECTRIC ARC FURNACES (#1 )EAF 65 T (EACH) SO2 19.95LB/HOther Case-by-CaseOH-0276CHARTER STEEL4/14/2003ELECTRIC ARC FURNACEEAF 110 T/H MELT SO2PRODUCTION LIMITS. SEE NOTE22LB/H71.06T/YR0.2LB/TOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005ELECTRIC ARC FURNACEEAF 350 t/h SO2 105LB/H375T/YRBACT-PSD SO2 and SOx lb/t steel Emission LimitsMIN0.16lb/t steel MIN0.07lb/t steelMAX1.50lb/t steel MAX0.45lb/t steelMEDIAN0.35lb/t steel MEDIAN0.20lb/t steelCOUNT14CASES COUNT4CASESEAF RBLC SO2 and SOx BACT Limits SummaryOther (non-BACT)-case-by-case SO2 and SOx lb/tsteel Emission Limitspage 6 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-6: Electric Arc Furnace (EAF)- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcType FUELTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTD EMISSIONLIMIT UNITSTX-0417NUCOR CORP.1/15/2003ELECTRIC ARC FURNACEEAF NOXOXY-FUEL BURNERS AND GOODENGINEERING PRACTICES0.3LB/TBACT-PSDAR-0077BLUEWATER PROJECT7/22/2004ELECTRIC ARC FURNACE (EAF)EAF NATURAL GAS 350 t/h NOXLOW NOX BURNERS0.35LB/TBACT-PSDOH-0245 [b]REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 9, P907EAF 165 T/H NOXLOOKED AT SCR, SNCR, AND FGR ALLINFEASIBLE0.35LB/TBACT-PSD 33LB/HAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001FURNACE, ELECTRIC ARCEAF 225 T/H NOXLOW NOX BURNER.0.38LB/TBACT-PSDIN-0073QUALITECH STEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/H NOX 0.5LB/TBACT-PSD 00SC-0072SMI STEEL - SOUTHCAROLINA11/26/2001EAFEAF NATURAL GAS 850000 T/YR NOXLOW NOX OXY-FUEL" BURNERSMOUNTED IN EAF"0.51LB/TBACT-PSDMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF COAL/COKE 560000 T/YR NOX 0.53LB/T STEELPRODUCEDBACT-PSD 148.4T/YRTN-0155NUCOR STEELCORPORATION11/6/2000ELECTRIC ARC FURNACEEAF NATURAL GAS 150 T/H NOXTHE PROPER OPERATION OF THE EAFAND DEC SYSTEMS, OXY-FUELNATURAL GAS BURNERS IN THE SHAFT,ELBOW BOX AND SIDEWALLS0.7LB/TBACT-PSD 21PPMVAR-0030ARKANSAS STEELASSOCIATES9/24/1998ELECTRIC ARC FURNACEEAF ELECTRICITY 50 T/H NOXDES WITH NO ADD-ON CONTROL(EXISTING)1LB/TBACT-PSD 50LB/HOH-0245 [b]REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 7, P905EAF 85 T/H NOXLOOKED AT SCR, SNCR, AND FGR ALLINFEASIBLE.8.5LB/HBACT-PSD 37.2T/YRTN-0122HOEGANAESCORPORATION2/11/2000ELECTRIC ARC FURNACE (EAF)EAF NATURAL GAS 45 MVA/70.4 MMBTU/H NOXLOW NOX BURNERS11.04LB/HBACT-PSD 0.2LB/TNJ-0040CO-STEEL RARITAN12/19/1996ELECTRIC ARC FURNACEEAF NATURAL GAS 1160320 T/YR NOX 24LB/HBACT-PSDNY-0094NUCOR AUBURN STEEL6/22/2004EAFEAF NATURAL GAS 110 t/h NOX 27.32LB/HBACT-PSD 0.27LB/T*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE (STACKEMISSIONS)EAF ELECTRICITY 70 T/H NOX 27.72LB/HBACT-PSD 110.88T/YROH-0276CHARTER STEEL4/14/2003ELECTRIC ARC FURNACEEAF ELECTRIC 110 T/H MELT NOXDIRECT EVACUATION CONTROL ANDLOW NOX OXY-FUEL BURNERS36.29LB/HBACT-PSD 117.25T/YRVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998FURNACE, ELECTRIC ARC #5EAF 100 T/H OF STEEL NOX 37.8LB/HBACT-PSD 165.6T/YR 0AL-0202CORUS TUSCALOOSA6/3/2003ELECTRIC ARC FURNACEEAF 160 T/H NOX 56LB/HBACT-PSD 0.35LB/TIN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF ELECTRICITY 200 T/YR NOXLOW NOX/OXYFUEL BURNERS ANDCOMBUSTION CONTROLS.70LB/HBACT-PSD 0.35LB/TAL-0197NUCOR STEELDECATUR, LLC7/11/2002ELECTRIC ARC FURNACE, (2)EAF 440 T/H NOX 176LB/HBACT-PSD 0.4LB/TPA-0178ELLWOOD QUALITYSTEELS CO.4/30/2001ELECTRIC ARC FURNACEEAF NATURAL GAS 53 T/BATCH NOXDIRECT EVACUATION SYSTEM,OXYFUEL0.1LB/TOther Case-by-Case 20.7T/YRCO-0054 [a]CF & I STEEL L.P. DBAROCKY MOUNTAINSTEEL MILLS6/21/2004ELECTRIC ARC FURNACE (EAF)EAF ELECTRIC POWE156 T/H NOXGOOD COMBUSTION PRACTICES.0.15LB/TOther Case-by-CasePA-0214J & L SPECIALTY STEEL,INC.4/2/2003ELECTRIC ARC FURNACE, (2)EAF NATURAL GAS 720000 T/YR NOXLOW NOX BURNERS16.62LB/HOther Case-by-Case 72.8T/YRUT-0061NUCOR STEELCORPORATION8/29/1997ELECTRIC ARC FURNACES (#1 )EAF NATURAL GAS 65 T (EACH) NOXEXISTING LOW NOX BURNERS47.25LB/HOther Case-by-CaseIA-0031IPSCO STEEL INC3/14/1996ELECTRIC ARC FURNACE/STEELFOUNDRYEAF ELECTRICITY 230 T/H NOXOXYFUEL/LOW NOX BURNER SCRAPPREHEATING BURNERS ONLYCONSIDERED BASELINE63LB/HOther Case-by-Case 276T/YR 0*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(FUGITIVE EMISSIONS)EAF ELECTRICITY 70 T/H NOX 1.11T/YROH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005ELECTRIC ARC FURNACEEAF ELECTRICITY 350 t/h NOX 189LB/H675T/YRBACT-PSD NOx lb/t Steel Emission LimitsMIN0.200lb/t steel MIN0.100lb/t steelMAX1.000lb/t steel MAX0.100lb/t steelMEDIAN0.380lb/t steel MEDIAN0.100lb/t steelCOUNT13CASES COUNT1CASESEAF RBLC NOx BACT Limits SummaryOther (non-BACT)-case-by-case NOx lb/t SteelEmission Limits[a] Carl Hund of CF&I Steel indicated on 6/9/06 that the limit of 0.15 lb NOx / T steel had not been met, and that renegotiationswere in progress to set a higher limit. This case is not included in the statistical analysis.[b] Pat Monnot of Republic Technologies in Ohio said on 6/12/06 that his facility had touble meeting both of their limits for NOxemissions(0.10 lb/T and 0.35 lb/T). These cases are not included in the statistical analysispage 7 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-7: Electric Arc Furnace (EAF)- COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0030 [a]ARKANSAS STEELASSOCIATES9/24/1998ELECTRIC ARC FURNACEEAF 50 T/H CODES WITH AIR GAP FOR CO COMBUSTION(EXISTING)0.6LB/TBACT-PSD 300LB/HKY-0094NORTH AMERICANSTAINLESS12/1/2003EAFEAF 154 t/batch CO2LB/TBACT-PSD 265.76LB/HAL-0129IPSCO STEEL INC10/16/1998FURNACE, ELECTRIC ARCEAF 200 T/H CODEC WITH POST-COMBUSTION2LB/TBACT-PSD 400LB/H0AR-0077BLUEWATER PROJECT7/22/2004ELECTRIC ARC FURNACE (EAF)EAF 350 t/h COAIR GAP2LB/TBACT-PSDTX-0417NUCOR CORP.1/15/2003ELECTRIC ARC FURNACEEAF COGOOD COMBUSTION PRACTICE2LB/TBACT-PSDSC-0072SMI STEEL - SOUTHCAROLINA11/26/2001EAFEAF 850000 T/YR CODESTRUCTION OF CO IN THE DUCTELBOW AND WATER COOLEDDUCTWORK2LB/TBACT-PSDAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001FURNACE, ELECTRIC ARCEAF 225 T/H COOXIDATION WITH SIDE DRAFT AIR GAP2LB/TBACT-PSDTN-0155NUCOR STEELCORPORATION11/6/2000ELECTRIC ARC FURNACEEAF 150 T/H COPROPER OPERATION OF EAF ANDDIRECT EVACUATION CONTROL SYSTEM,USE OF OXY-FUEL FOR POSTCOMBUSTION CONTROL; USE OFOXYGEN LANCING.4LB/TBACT-PSD 200PPMVIN-0073QUALITECH STEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/H COPOST COMBUSTION UNDER HOOD BYOXYGEN INJECTION AND OXY FUELBURNERS & FOURTH HOLE WITHADJUSTABLE GAP TO ALLOW AIR INTOWATER COOLED DUCTWORK FORCOMBUS4.7LB/TBACT-PSD 0 0OH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003EAFEAF 200 T/H CO4TH HOLE4.8LB/TBACT-PSD 960LB/HPA-0178ELLWOOD QUALITYSTEELS CO.4/30/2001ELECTRIC ARC FURNACEEAF 53 T/BATCH CODIRECT EVACUATION SYSTEM5LB/TBACT-PSD 1032.5T/YRMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF 560000 T/YR CO5LB/T STEELPRODUCEDBACT-PSD 1400T/YRAR-0044ARKANSAS STEELASSOCIATES1/5/2001FURNACE, ELECTIC ARCEAF 50 T/H CODIRECT SHELL EVACUATION CONTROL(DEC) SYSTEM WITH AIR GAP FOR COCOMBUSTION.6LB/TBACT-PSD 420LB/HNC-0065AMERISTEEL CORP.4/29/1999STEEL PRODUCTION, ELECTRICARC FURNACEEAF 569400 T/YR COCONTROL: SEE PROCESS DESCRIPTION.EMISSION LIMIT IN LB/TON STEELPRODUCED6LB/TBACT-PSD*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(FUGITIVE EMISSIONS)EAF 70 T/H CO11.37T/YRBACT-PSDWV-0018ALLOY12/16/2002ELECTRIC ARC FURNACEEAF 18000 T/YR CODIRECT EVACUATION CANOPY USED TOINTRODUCE AMBIENT AIR MIX WITHEXHAUST TO PROMOTE COCOMBUSTION.54LB/HBACT-PSD 25.22LB/T2.25LB/MW-HTN-0122HOEGANAESCORPORATION2/11/2000ELECTRIC ARC FURNACE (EAF)EAF 45 MVA/70.4 MMBTU/H COCOMBUSTION AIR GAP BETWEEN THEWATER-COOLED DUCT AND THE ELBOWOFF152.9LB/HBACT-PSD 2.77LB/TNY-0094NUCOR AUBURN STEEL6/22/2004EAFEAF 110 t/h CODIRECT SHELL EVACUATION (DSE)CONTROLS TO LIMIT CO EMISSIONS.202.4LB/HBACT-PSD 2LB/TVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998FURNACE, ELECTRIC ARC #5EAF 100 T/H OF STEEL COCONTROLLED BY DEC WITH AIRGAP240LB/HBACT-PSD 1052.2T/YR0NJ-0040CO-STEEL RARITAN12/19/1996ELECTRIC ARC FURNACEEAF 1160320 T/YR COGOOD COMBUSTION PRACTICES275LB/HBACT-PSD*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE (STACKEMISSIONS)EAF 70 T/H CO284.2LB/HBACT-PSD 1136.8T/YRAL-0202CORUS TUSCALOOSA6/3/2003ELECTRIC ARC FURNACEEAF 160 T/H CODIRECT EVACUATION CANOPY320LB/HBACT-PSD 2LB/TOH-0276CHARTER STEEL4/14/2003ELECTRIC ARC FURNACEEAF 110 T/H MELT CODIRECT EVACUATION CONTROL356.4LB/HBACT-PSD 1151.2T/YRIN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF 200 T/YR CODEC AIR GAP AND POST COMBUSTIONCHAMBER400LB/HBACT-PSD 2LB/T STEELAR-0021QUANEXCORPORATION -MACSTEEL DIVISION2/18/1998ELECTRIC ARC FURNACES, 2EAF 86 T/H COEXISTING SIDE DRAFT CONTROLSYSTEM.421.4LB/HBACT-PSD 0 0AL-0197NUCOR STEELDECATUR, LLC7/11/2002ELECTRIC ARC FURNACE, (2)EAF 440 T/H CO880LB/HBACT-PSD 2LB/TAR-0078NUCOR STEEL,ARKANSAS9/9/1999EAFEAF 425 t/h CODIRECT SHELL EVACUATION961.5LB/HBACT-PSD 4211.4T/YRTX-0398NUCOR JEWETT PLANT5/5/2000EAF BAGHOUSEEAF CO972LB/HBACT-PSDOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 7, P905EAF 85 T/H CODEC SYSTEM COMBUSTS 90% OF THECO. LOOKED AT SCRAP PREHEATING(NOT FEASIBLE). USED A DEC GAP TOHELP COMBUST THE CO.340LB/HN/A 1489.2T/YROH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 9, P907EAF 165 T/H CODEC COMBUSTS 90% OF THE CO. USED ADEC GAP TO HELP COMBUST THE CO.LOOKED AT SCRAP PREHEATING (NOTFEASIBLE)660LB/HN/A 2890.8T/YRCO-0054CF & I STEEL L.P. DBAROCKY MOUNTAINSTEEL MILLS6/21/2004ELECTRIC ARC FURNACE (EAF)EAF 156 T/H COPROCESS CONTROLS, INCLUDINGPATTERN OF CHARGING, RAWMATERIALS ADDITION, ETC.2LB/TOther Case-by-Casepage 8 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-7: Electric Arc Furnace (EAF)- COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSIA-0031IPSCO STEEL INC3/14/1996ELECTRIC ARC FURNACE/STEELFOUNDRYEAF 230 T/H COSLOT AND POST COMBUSTION CHAMBERDEC\ELBOW SLOT\POSTCOMBUSTION\WATER COOLED DUCT210LB/HOther Case-by-Case 921T/YR0TX-0398NUCOR JEWETT PLANT5/5/2000ELECTRIC ARC FURNACEEAF 600000 T/YR CO648LB/HOther Case-by-Case 3825T/YRUT-0061NUCOR STEELCORPORATION8/29/1997ELECTRIC ARC FURNACES (#1 )EAF 65 T (EACH) CO973.2LB/HOther Case-by-Case 997.5LB/HOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005ELECTRIC ARC FURNACEEAF 350 t/h CO1400LB/H5000T/YRBACT-PSD CO lb/t steel Emission LimitsMIN0.60lb/t steel MIN2lb/t steelMAX25.22lb/t steel MAX2lb/t steelMEDIAN2.00lb/t steel MEDIAN2lb/t steelCOUNT20CASES COUNT1CASESEAF RBLC CO BACT Limits SummaryOther (non-BACT)-case-by-case CO lb/t steel Emission Limits[a] Billy Ferguson of Arkansas Steel Associates, said on 6/8/06 that they were having no problems meeting the limit of0.6 LB/TON for their facility.page 9 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-8: Electric Arc Furnace (EAF)- VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcType FUELTHROUGHPUT UNITSPOLLUTANT Control EquipmentEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF COAL/COKE 560000 T/YRVOC 0.03LB/T STEEL PRODUCBACT-PSD84 T/YRAR-0077BLUEWATER PROJECT7/22/2004ELECTRIC ARC FURNACE (EAF)EAF NATURAL GAS350 t/hVOC SCRAP MANAGEMENT 0.13LB/T BACT-PSDAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001FURNACE, ELECTRIC ARCEAF 225 T/HVOC SCRAP MANAGEMENT. 0.13LB/T BACT-PSDKY-0094NORTH AMERICANSTAINLESS12/1/2003EAFEAF 154 t/batchVOC 0.15LB/T BACT-PSD19.95 LB/HIN-0073QUALITECHSTEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/HVOCSCRAPMANAGEMENT-NOHEAVY OILED SCRAP 0.15LB/T STEEL PROD. BACT-PSD00TN-0155NUCOR STEELCORPORATION11/6/2000ELECTRIC ARC FURNACEEAF NATURAL GAS150 T/HVOCSCRAPMANAGEMENTPLAN;PROPER OPERATION OFEAF AND DEC SYSTEMS,USE OF OXY-FUEL FOR 0.26LB/T BACT-PSDAL-0129IPSCO STEEL INC10/16/1998FURNACE, ELECTRIC ARCEAF 200 T/HVOCDEC WITH POSTCOMBUSTION CHAMBER 0.35LB/T BACT-PSD70 LB/H0AR-0030ARKANSAS STEELASSOCIATES9/24/1998ELECTRIC ARC FURNACEEAF ELECTRICITY 50 T/HVOCDIRECT EVACUATIONSYSTEM (DES) WITH AIRGAP FOR LONG RESIDENCETIME (EXISTING) 0.35LB/T BACT-PSD17.5 LB/HTX-0417NUCOR CORP.1/15/2003ELECTRIC ARC FURNACEEAFVOCCOMBUSTION IN DSESYSTEM 0.427LB/T BACT-PSD*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(FUGITIVE EMISSIONS)EAF ELECTRICITY 70 T/HVOC 0.8T/YR BACT-PSDNJ-0040CO-STEEL RARITAN12/19/1996ELECTRIC ARC FURNACEEAF NATURAL GAS1160320 T/YRVOCGOOD COMBUSTIONPRACTICES 6LB/H BACT-PSDIN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF ELECTRICITY 200 T/YRVOCSCRAP MANAGEMENT PLAN.THERMAL OXIDIZER ANDMAINTAINING A NEGATIVEPRESSURE AT THE DEC AIRGAP 18LB/H BACT-PSD*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(STACK EMISSIONS)EAF ELECTRICITY 70 T/HVOC 20.02LB/H BACT-PSD80.08 T/YRAL-0202CORUS TUSCALOOSA6/3/2003ELECTRIC ARC FURNACEEAF 160 T/HVOCDEC AND GOOD SCRAPQUALITY 20.8LB/H BACT-PSD0.13 LB/TOH-0276CHARTER STEEL4/14/2003ELECTRIC ARC FURNACEEAF ELECTRIC 110 T/H MELTVOCDIRECT EVACUATIONCONTROL ANDOPERATIONAL PRACTICES 22LB/H BACT-PSD71.06 T/YRVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998FURNACE, ELECTRIC ARC #5EAF 100 T/H OF STEEVOCSCRAP MANAGEMENT PLANEXISTS 30LB/H BACT-PSD131.4 T/YR0IA-0031IPSCO STEEL INC3/14/1996ELECTRIC ARC FURNACE/STEELFOUNDRYEAF ELECTRICITY 230 T/HVOCDEC/ELBOW SLOT/POSTCOMBUSTION/WATERCOOLED DUCT 31LB/H BACT-PSD136 T/YR0AR-0078NUCOR STEEL,ARKANSAS9/9/1999EAFEAF 425 t/hVOC SCRAP MANAGEMENT 44.1LB/H BACT-PSD193.2 T/YRAL-0197NUCOR STEELDECATUR, LLC7/11/2002ELECTRIC ARC FURNACE, (2)EAF 440 T/HVOC 88LB/H BACT-PSD0.2 LB/TOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005ELECTRIC ARC FURNACEEAF ELECTRICITY 350 t/hVOC 122.5LB/H BACT-PSD437.5 T/YROH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 7, P905EAF 85 T/HVOCDEC GAP HELPS TO BURNVOC. LOOKED AT THERMALINC. IT WOULD COST$254,000 PER TON(INFEASIBLE) 29.75LB/H N/A130.3 T/YROH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 9, P907EAF 165 T/HVOCDECGAPHELPSTOBURNUP VOC. LOOKED ATTHERMAL INCINERATOR, ITWOULD COST $254,000 PER 57.75LB/H N/A252.9 T/YRpage 10 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-8: Electric Arc Furnace (EAF)- VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcType FUELTHROUGHPUT UNITSPOLLUTANT Control EquipmentEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSOH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003EAFEAF NATURAL GAS200 T/HVOC 0.1LB/T Other Case-by-Case20 LB/HTN-0122HOEGANAESCORPORATION2/11/2000ELECTRIC ARC FURNACE (EAF)EAF NATURAL GAS45 MVA/70.4 MMVOC 0.11LB/H Other Case-by-Case0.002 LB/TCO-0054CF&ISTEELL.P.DBAROCKY MOUNTAINSTEEL MILLS6/21/2004ELECTRIC ARC FURNACE (EAF)EAF ELECTRIC PO156 T/HVOCPROCESS AND RAWMATERIAL CONTROLS. 0.13LB/T Other Case-by-CasePA-0178ELLWOOD QUALITYSTEELS CO.4/30/2001ELECTRIC ARC FURNACEEAF NATURAL GAS53 T/BATCHVOCDIRECT EVACUATIONSYSTEM 0.3LB/T Other Case-by-Case62 T/YRPA-0214J & L SPECIALTY STEEL,INC.4/2/2003ELECTRIC ARC FURNACE, (2)EAF NATURAL GAS720000 T/YRVOC 0.82LB/H Other Case-by-Case3.6 T/YRBACT-PSD VOC lb/t steel Emission LimitsMIN0.030lb/t steel MIN0.002lb/t steelMAX0.427lb/t steel MAX0.300lb/t steelMEDIAN0.150lb/t steel MEDIAN0.115lb/t steelCOUNT11CASES COUNT4CASESEAF RBLC VOC BACT Limits SummaryOther (non-BACT)-case-by-case VOC lb/t steelEmission Limitspage 11 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-9: Electric Arc Furnace (EAF)- FLControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANTCONTROLEQUIPMENT EMISSION LIMIT 1 UNITSCASE-BY-CASEBASISEMISSION LIMIT2 UNITSEMISLIMIT2AVGTIMECONDITIONSTDEMISSIONLIMIT UNITSVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998FURNACE, ELECTRIC ARC #5EAF 100 T/H OF STEEL FLCONTROLLED BYBAGHOUSE0.54LB/HBACT-PSD 2.4T/YR0IN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF 200 T/YR FLPROCESSOPERATIONS0.68LB/HBACT-PSDOH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003EAFEAF 200 T/H FL 1.4LB/HOther Case-by-CaseBACT-PSD FL lb/t steel Emission LimitsEAF RBLC FL BACT Limits SummaryOther (non-BACT)-case-by-case FL lb/t steel EmissionLimitsNo Performance Limits No Performance Limitspage 12 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-9: Electric Arc Furnace (EAF)- PbControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0077BLUEWATER PROJECT7/22/2004ELECTRIC ARC FURNACE (EAF)EAF 350 t/h PBFABRIC FILTER0.0009LB/TBACT-PSDKY-0094NORTH AMERICANSTAINLESS12/1/2003EAFEAF 154 t/batch PBBAGHOUSE0.001LB/TBACT-PSD 0.167LB/HIN-0073QUALITECH STEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/H PBBAGHOUSE0.07LB/HBACT-PSD 0.31T/YR0IN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF 200 T/YR PBBAGHOUSE. SEE NOTES0.114LB/HBACT-PSDMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF 560000 T/YR PBBAGHOUSE0.13MG/M3BACT-PSD 2.8LB/HNJ-0040CO-STEEL RARITAN12/19/1996ELECTRIC ARC FURNACEEAF 1160320 T/YR PBBAGHOUSE0.22LB/HBACT-PSD*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE (STACKEMISSIONS)EAF 70 T/H PBBAGHOUSE AND DUST HANDLINGSYSTEM. USE OF DIRECT-SHELLEVACUATION CONTROL SYSTEM. USE OFSEGMENTED CANOPY HOOD,SCAVENGER DUCTING, CROSS-DRAFTPARTITIONING AND CLOSED ROOFMONITORS.0.25LB/HBACT-PSD 1T/YRVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998FURNACE, ELECTRIC ARC #5EAF 100 T/H OF STEEL PBCONTROLLED BY BAGHOUSE0.3LB/HBACT-PSD 1.3T/YR0AR-0021QUANEXCORPORATION -MACSTEEL DIVISION2/18/1998ELECTRIC ARC FURNACES, 2EAF 86 T/H PBPOSITIVE PRESSURE,MULTICOMPARTMENT, FABRICFILTERBAGHOUSE0.3LB/HBACT-PSD 0 0AR-0044ARKANSAS STEELASSOCIATES1/5/2001FURNACE, ELECTIC ARCEAF 50 T/H PBBAGHOUSE - 3% OF BAGHOUSE DUST0.4LB/HBACT-PSD 1.5T/YROH-0276CHARTER STEEL4/14/2003ELECTRIC ARC FURNACEEAF 110 T/H MELT PBBAGHOUSE0.55LB/HBACT-PSD 1.78T/YR0.0001GR/DSCFFL-0192AMERISTEELCORPORATION9/28/1999ELECTRIC ARC FURNACEEAF 720000 T/YR PBBAGHOUSES0.7LB/HBACT-PSD 2.8T/YROH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005ELECTRIC ARC FURNACEEAF 350 t/h PBBAGHOUSE0.819LB/HBACT-PSD 3.16T/YRTN-0155NUCOR STEELCORPORATION11/6/2000ELECTRIC ARC FURNACEEAF 150 T/H PBLEAD MANAGEMENT AND ABATEMENTPROGRAM, EAF BAGHOUSEBACT-PSDOH-0245 [a]REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 7, P905EAF 85 T/H PBFABRIC FILTER, DIRECT EVACUATIONCONTROL (DEC) AND BUILDINGEVACUATION SYSTEM0.036LB/HN/A 0.16T/YROH-0245 [a]REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 9, P907EAF 165 T/H PBFABRIC FILTER, DIRECT EVACUATIONCONTROL (DEC) AND BUILDINGEVACUATION SYSTEM0.036LB/HN/A 0.16T/YROH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003EAFEAF 200 T/H PBFABRIC FILTER0.26LB/HN/AIA-0031IPSCO STEEL INC3/14/1996ELECTRIC ARC FURNACE/STEELFOUNDRYEAF 230 T/H PBBAGHOUSE-POLYBAGS 32 MODULES /260 BAGS PER MODULE0.13LB/HOther Case-by-Case 0.55T/YR0CO-0054CF & I STEEL L.P. DBAROCKY MOUNTAINSTEEL MILLS6/21/2004ELECTRIC ARC FURNACE (EAF)EAF 156 T/H LEAD OXIDESELECT RAW MATERIAL TO MINIMIZELEAD INPUT AND CONTROL OPERATINGTEMPERATURE TO FIX VAPOR LEAD TOTHE PM TO BE REMOVED WITH HIGHEFFICIENCY FF.0.00057LB/TOther Case-by-Case*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(FUGITIVE EMISSIONS)EAF 70 T/H PBUSE OF SEGMENTED CANOPY HOOD,SCAVENGER DUCTING, CROSS-DRAFTPARTITIONING AND CLOSED ROOFMONITORS.0.01T/YRBACT-PSD Pb lb/t steel Emission LimitsMIN 0.00090 lb/t steel MIN 0.00057 lb/t steelMAX 0.00100 lb/t steel MAX 0.00057 lb/t steelMEDIAN 0.00095 lb/t steel MEDIAN 0.00057 lb/t steelCOUNT2CASES COUNT1CASESOther (non-BACT)-case-by-case Pb lb/t steel Emission LimitsEAF RBLC Pb BACT Limits Summary[a] Pat Monnot of Republic Technologies in Ohio said on 6/12/06 that his facility did not meet the initial limit of 0.024 Lb/Hour. They did astack test, and based on that Method 12 test, they came to a new limit of 0.036 Lb/Hour.page 13 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-10: Ladle Metallurgical Furnace (LMF)-PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0077BLUEWATER PROJECT7/22/2004LADLE METALLURGY FURNACELMF 350 T/H PM10FABRIC FILTER0.0018GR/DSCFBACT-PSD 0.0018GR/DSCFIN-0073QUALITECH STEELCORP.10/31/1996LADLE METALLURGY STATION(LMS)LMF 135 T/H PM10ADDITIVES ADDED UNDER HOOD ONLY,ARTIFICIAL SLAG ADDED BY CHUTE,COVERING LADLE IF TRANSFERDELAYEDAND ARGON STIRRING UNDERA HOOD.0.0032GR/DSCFBACT-PSD 0.0032GR/DSCFIN-0108NUCOR STEEL11/21/2003LADLE METALLURGY FURNACES(2)LMF 502 T/H PM10BAGHOUSE. CONTROL METHOD: STACKTESTING AND VISIBLE EMISSIONNOTATIONS0.0052GR/DSCFBACT-PSD 0.0052GR/DSCFAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001FURNACE, LADLE METALLURGYLMF 225 T/H PM10FABRIC FILTER.0.0052GR/DSCFBACT-PSD 0.0052GR/DSCFOH-0276CHARTER STEEL4/14/2003LADLE METALLURGY FURNACELMF 110 T/H PM10BAGHOUSE2.2LB/HBACT-PSD 7.2T/YR0.0024GR/DSCFVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998METALLURGICAL STATION,LADLE, #5LMF 100 T/H OF STEEL PM10CONTROLLED BY BAGHOUSE2.8LB/HBACT-PSD 12.2T/YR0*AR-0086NUCOR-YAMATO STEELCOMPANY,BLYTHEVILLE MILL6/11/2004LMF #1 BAGHOUSE, SN-35LMF 250 T/YR STEEL PM10FABRIC FILTER7LB/HBACT-PSD 29.3T/YR0.0052GR/DSCFOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999LADLE METALLURGY FACILITY(LMF), P123LMF PM10FABRIC FILTER. NO STACK TEST FORPM10.2.44LB/HN/A 10.69T/YR0.005GR/DSCFOH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003LADLE REFINERLMF PM10 0.52LB/HOther Case-by-CaseOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005LADLE METALLURGY FURNACELMF 350 t/h PM10 2.4LB/H9.24T/YRBACT-PSD PM10 gr/dscf steel Emission LimitsMIN0.0018GR/DSCF MIN0.0050GR/DSCFMAX0.0052GR/DSCF MAX0.0050GR/DSCFMEDIAN0.0042GR/DSCF MEDIAN0.0050GR/DSCFCOUNT6CASES COUNT1CASESLMF RBLC PM10 BACT Limits SummaryOther (non-BACT)-case-by-case PM10 gr/dscfEmission Limitspage 14 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-11: Ladle Metallurgical Furnace (LMF)-PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSIN-0108NUCOR STEEL11/21/2003LADLE METALLURGY FURNACES(2)LMF 502 T/H PM FILTERABBAGHOUSE. COMPLIANCE METHOD:STACK TESTING AND VISIBLE EMISSIONNOTATIONS.0.0018GR/DSCFBACT-PSD 0.0018GR/DSCFAR-0021QUANEXCORPORATION -MACSTEEL DIVISION2/18/1998FURNACE, LADLE METALLURGYLMF 0 PMROUTED TO EAF BAGHOUSES.MULTICOMPARTMENT POSITIVEPRESSURE BAGHOUSES.0.0018GR/DSCFBACT-PSD 0 0OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005LADLE METALLURGY FURNACELMF 350 t/h PMBAGHOUSE0.0032GR/DSCFBACT-PSD 12.14T/YR0.0032GR/DSCFIN-0073QUALITECH STEELCORP.10/31/1996LADLE METALLURGY STATION(LMS)LMF 135 T/H PMADDITIVES ADDED UNDER HOOD ONLY,ARTIFICIAL SLAG ADDED BY CHUTE,COVERING LADLE IF TRANSFERDELAYEDAND ARGON STIRRING UNDERA HOOD.0.0032GR/DSCFBACT-PSD 0.0032GR/DSCFAR-0044ARKANSAS STEELASSOCIATES1/5/2001LADLE METALLURGY STATIONLMF 50 T/H PMBAGHOUSE.0.0052GR/DSCFBACT-PSD 1LB/H0.0052GR/DSCFVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998METALLURGICAL STATION,LADLE, #5LMF 100 T/H OF STEEL PMCONTROLLED BY BAGHOUSE0.0052GR/DSCFBACT-PSD 2.8LB/H0TX-0417NUCOR CORP.1/15/2003LADLE METALLURGY FURNACESTATIONS (2)LMF PMCLOSE-CAPTURE HOOD AND ROOFCANOPY HOOD OVER THE CASTINGDECK, RESULTING IN 98.8% CAPTURE,THEN ROUTED TO LMF/CASTERBAGHOUSE.0.0052GR/DSCFBACT-PSDTX-0399NUCOR JEWETT PLANT1/5/2003WEST LMF/CASTER BUILDINGLMF PM 11.63LB/HBACT-PSD 25.78T/YROH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999LADLE METALLURGY FACILITY(LMF), P123LMF PMFABRIC FILTER3.12LB/HN/A 13.67T/YR0.005GR/DSCFOH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003LADLE REFINERLMF PM0.68LB/HOther Case-by-CaseTN-0122HOEGANAESCORPORATION2/11/2000LADLE METALLURGY FACILITY(LMF)LMF 110650 LB MOLTEN STEEL/H PMBAGHOUSE1.53LB/HOther Case-by-Case 0.0052GR/DSCFBACT-PSD PM GR/DSCF Emission LimitsMIN 0.0018 GR/DSCF MIN 0.0050 GR/DSCFMAX 0.0052 GR/DSCF MAX 0.0052 GR/DSCFMEDIAN 0.0032 GR/DSCF MEDIAN 0.0051 GR/DSCFCOUNT7CASES COUNT2CASESLMF RBLC PM BACT Limits SummaryOther (non-BACT)-case-by-case PM gr/dscf EmissionLimitspage 15 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-12: Ladle Metallurgical Furnace (LMF)-SO2Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATEPROCESSNAME Proc TypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSTX-0399NUCOR JEWETTPLANT1/5/2003WESTLMF/CASTERBUILDINGLMF SO2 0.04LB/HBACT-PSD 0.16T/YRVA-0241ROANOKEELECTRIC STEELCORPORATION11/6/1998METALLURGICALSTATION, LADLE,#5LMF 100 T/H OF STEEL SO2 6LB/HBACT-PSD 26.3T/YR0*AR-0086NUCOR-YAMATOSTEEL COMPANY,BLYTHEVILLE MILL6/11/2004LMF #1BAGHOUSE, SN35LMF 250 T/YR STEEL SO2LOW SULFUR COKE USAGE90LB/HBACT-PSD 394.2T/YR0.36LB/TSTEELAR-0055NUCOR YAMATOSTEEL (ARMOREL)10/10/2001FURNACE, LADLEMETALLURGYLMF 225 T/H SO2LOW SULFUR COKE USE.0.076LB/TBACT-PSDAR-0077BLUEWATERPROJECT7/22/2004LADLEMETALLURGYFURNACELMF 350 T/H SO2 0.08LB/TBACT-PSDIN-0108NUCOR STEEL11/21/2003LADLEMETALLURGYFURNACES (2)LMF 502 T/H SO2 0.185LB/TBACT-PSD 92.87LB/HOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999LADLEMETALLURGYFACILITY (LMF),P123LMF SO2LOOKED AT CHARGE SUBSTITUTION(NOT FEASIBLE) & FLUE GASDESULFURIZATION. LOOKED AT ADDON CONTROLS (WET SCRUBBER,SPRAY DRYER ABORPTION AND DRYSORBENT INJECTION)525LB/3 HPERIODN/A 1748LB/DOH-0246THE TIMKENCOMPANY/FAIRCREST PLANT2/20/2003LADLE REFINERLMF SO2 0.94LB/HOther Case-by-CaseTN-0122HOEGANAESCORPORATION2/11/2000LADLEMETALLURGYFACILITY (LMF)LMF 110650 LB MOLTEN STEEL/H SO2 2.32LB/HOther Case-by-Case 9.3T/YROH-0292WHEELINGPITTSBURGHSTEELCORPORATION1/6/2005LADLEMETALLURGYFURNACELMF 350 t/h SO2 14LB/H50T/YROH-0276CHARTER STEEL4/14/2003LADLEMETALLURGYFURNACELMF 110 T/H SO2 220LB/H22LB/HBACT-PSD SO2 lb/t steel Emission LimitsMIN0.0760lb/t steel MINNAlb/t steelMAX0.3600lb/t steel MAXNAlb/t steelMEDIAN0.1325lb/t steel MEDIANNAlb/t steelCOUNT4CASES COUNTNACASESLMF RBLC SO2 BACT Limits SummaryOther (non-BACT)-case-by-case SO2 lb/t steelEmission Limitspage 16 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-13: Ladle Metallurgical Furnace (LMF)-NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC IDFACILITYNAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BYCASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSIN-0108NUCOR STEEL11/21/2003LADLE METALLURGYFURNACES (2)LMF 502 T/H NOX 0.0176LB/TBACT-PSD 8.8LB/HAR-0077BLUEWATERPROJECT7/22/2004LADLE METALLURGYFURNACELMF 350 T/H NOX 0.02LB/TBACT-PSDAR-0055NUCOR YAMATOSTEEL(ARMOREL)10/10/2001FURNACE, LADLEMETALLURGYLMF 225 T/H NOX 0.02LB/TBACT-PSDOH-0276CHARTER STEEL4/14/2003LADLE METALLURGYFURNACELMF 110 T/H NOX 1.65LB/HBACT-PSD 5.32T/YROH-0246THE TIMKENCOMPANY/FAIRCREST PLANT2/20/2003LADLE REFINERLMF NOXLOW NOX BURNERS1.67LB/HBACT-PSDTN-0122HOEGANAESCORPORATION2/11/2000LADLE METALLURGYFACILITY (LMF)LMF 110650 LB MOLTEN STEEL/H NOXPROPER COMBUSTIONCONTROL2.23T/MOBACT-PSDVA-0241ELECTRICSTEELCORPORATION11/6/1998METALLURGICALSTATION, LADLE, #5LMF 100 T/H OF STEEL NOX 6LB/HBACT-PSD 26.3T/YRTX-0399NUCOR JEWETTPLANT1/5/2003WEST LMF/CASTERBUILDINGLMF NOX 6.36LB/HBACT-PSD 26.26T/YROH-0292WHEELINGPITTSBURGHSTEELCORPORATION1/6/2005LADLE METALLURGYFURNACELMF 350 t/h NOX 18.9LB/H67.5T/YRTN-0157HOEGANAESCORP.12/31/2003LADLE METALLURGYFACILITYLMF NOXGOOD COMBUSTION PRACTICE.26.7TONS/YEARBACT-PSD NOx lb/t steel Emission LimitsMIN0.0176lb/t steel MINNAlb/t steelMAX0.0200lb/t steel MAXNAlb/t steelMEDIAN0.0200lb/t steel MEDIANNAlb/t steelCOUNT3CASES COUNTNACASESLMF RBLC NOx BACT Limits SummaryOther (non-BACT)-case-by-case NOx lb/tsteel Emission Limitspage 17 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-14: Ladle Metallurgical Furnace (LMF)-COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0077BLUEWATER PROJECT7/22/2004LADLE METALLURGY FURNACELMF 350 T/H COSIDE DRAFT AIR GAP0.05LB/TBACT-PSDIN-0108NUCOR STEEL11/21/2003LADLE METALLURGY FURNACES(2)LMF 502 T/H CO 0.0713LB/TBACT-PSD 35.77LB/HAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001FURNACE, LADLE METALLURGYLMF 225 T/H COOXIDATION WITH SIDE DRAFT AIR GAP0.28LB/TBACT-PSDAR-0044ARKANSAS STEELASSOCIATES1/5/2001LADLE METALLURGY STATIONLMF 50 T/H CODIRECT SHEEL EVACUATION CONTROL(DEC) SYSTEM WITH AIR GAP.0.6LB/TBACT-PSD 42LB/HTX-0399NUCOR JEWETT PLANT1/5/2003WEST LMF/CASTER BUILDINGLMF CO 5.34LB/HBACT-PSD 22.06T/YRTN-0122HOEGANAESCORPORATION2/11/2000LADLE METALLURGY FACILITY(LMF)LMF 110650 LB MOLTEN STEEL/H COPROPER COMBUSTION CONTROL7.36T/MOBACT-PSDAL-0202CORUS TUSCALOOSA6/3/2003LADLE METALLURGY STATIONLMF 160 T/H CO 32LB/HBACT-PSD 0.2LB/TOH-0276CHARTER STEEL4/14/2003LADLE METALLURGY FURNACELMF 110 T/H CO 33LB/HBACT-PSD 107T/YRVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998METALLURGICAL STATION,LADLE, #5LMF 100 T/H OF STEEL CO 48LB/HBACT-PSD 210.2T/YR0*AR-0086NUCOR-YAMATO STEELCOMPANY,BLYTHEVILLE MILL6/11/2004LMF #1 BAGHOUSE, SN-35LMF 250 T/YR STEEL COOXIDATION WITH SIDE DRAFT AIR GAPS70LB/HBACT-PSD 306.6T/YR0.005LB/T STEELTN-0157HOEGANAES CORP.12/31/2003LADLE METALLURGY FACILITYLMF COGOOD COMBUSTION PRACTICE.88.3TONS/YEARBACT-PSDOH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003LADLE REFINERLMF CO 0.91LB/HOther Case-by-CaseOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005LADLE METALLURGY FURNACELMF 350 t/h CO 140LB/H500T/YRBACT-PSD CO lb/t steel Emission LimitsMIN 0.005 lb/t steel MIN NA lb/t steelMAX 0.600 lb/t steel MAX NA lb/t steelMEDIAN 0.136 lb/t steel MEDIAN NA lb/t steelCOUNT6CASES COUNTNACASESLMF RBLC CO BACT Limits SummaryOther (non-BACT)-case-by-case CO lb/t steel EmissionLimitspage 18 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-15: Ladle Metallurgical Furnace (LMF)- VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSAR-0077BLUEWATER PROJECT7/22/2004LADLE METALLURGY FURNACELMF 350 T/H VOC 0.005LB/TBACT-PSDIN-0108NUCOR STEEL11/21/2003LADLE METALLURGY FURNACES(2)LMF 502 T/H VOC 0.0086LB/TBACT-PSD 4.32LB/HVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998METALLURGICAL STATION,LADLE, #5LMF 100 T/H OF STEEL VOC 0.2LB/HBACT-PSD 0.8T/YROH-0276CHARTER STEEL4/14/2003LADLE METALLURGY FURNACELMF 110 T/H VOC 0.22LB/HBACT-PSD 0.17T/YRTX-0399NUCOR JEWETT PLANT1/5/2003WEST LMF/CASTER BUILDINGLMF VOC 0.35LB/HBACT-PSD 1.44T/YROH-0292WHEELING PITTSBURGHSTEEL CORPORATION1/6/2005LADLE METALLURGY FURNACELMF 350 t/h VOC 12.25LB/HBACT-PSD 43.75T/YRTN-0122HOEGANAESCORPORATION2/11/2000LADLE METALLURGY FACILITY(LMF)LMF 110650 LB MOLTEN STEEL/H VOC 0.04T/MOOther Case-by-CaseOH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003LADLE REFINERLMF VOC 0.07LB/HOther Case-by-CaseBACT-PSD VOC lb/t steel Emission LimitsMIN0.0050lb/t steel MINNAlb/t steelMAX0.0086lb/t steel MAXNAlb/t steelMEDIAN0.0068lb/t steel MEDIANNAlb/t steelCOUNT2CASES COUNTNACASESLMF RBLC VOC BACT Limits SummaryOther (non-BACT)-case-by-case VOC lb/t steelEmission Limitspage 19 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-16A: Ladle Metallurgical Furnace (LMF)- FLControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT Control EquipmentEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998METALLURGICAL STATION,LADLE, #5LMF 100 T/H OF STEEL FLCONTROLLED BY BAGHOUSE0.16LB/HBACT-PSD 0.68T/YR0BACT-PSD FL lb/t steel Emission LimitsLMF RBLC FL BACT Limits SummaryOther (non-BACT)-case-by-case FL lb/t steelEmission LimitsNo Performance Limits No Performance Limitspage 20 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-16B: Ladle Metallurgical Furnace (LMF)- PbControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT Control EquipmentEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSOH-0276CHARTER STEEL4/14/2003LADLE METALLURGY FURNACELMF 110 T/H PBBAGHOUSE0.02LB/HBACT-PSD 0.07T/YR0.0001GR/DSCFTX-0399NUCOR JEWETT PLANT1/5/2003WEST LMF/CASTER BUILDINGLMF LEAD OXIDE 0.05LB/HBACT-PSD 0.1T/YRVA-0241ROANOKE ELECTRICSTEEL CORPORATION11/6/1998METALLURGICAL STATION,LADLE, #5LMF 100 T/H OF STEEL PBCONTROLLED BY BAGHOUSE0.09LB/HBACT-PSD 0.4T/YR0OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005LADLE METALLURGY FURNACELMF 350 t/h PBBAGHOUSE0.126LB/HBACT-PSD 0.485T/YRBACT-PSD Pb gr/dscf Emission LimitsMIN0.0001GR/DSCF MINNAGR/DSCFMAX0.0001GR/DSCF MAXNAGR/DSCFMEDIAN0.0001GR/DSCF MEDIANNAGR/DSCFCOUNT1CASES COUNTNACASESLMF RBLC Pb BACT Limits SummaryOther (non-BACT)-case-by-case PB gr/dscfEmission Limitspage 21 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-17: Melt Shop (MS)- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANTCONTROLEQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSWI-0206SAUKVILLE PLANT12/19/2003MELT SHOP, P01, S01MS 137.5 T/D PM10REVERSE AIRBAGHOUSE (EXISTING)0.0014GR/DSCFBACT-PSD 5.56LB/HVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H PM10FURNACE SHAFTEVACUATION; POSITIVEP BAGHOUSE WITH ADESIGN FLOW OF1,100,000 ACFM($550/TON REMOVED)0.0018GR/DSCFBACT-PSD 17LB/H0.0018GR/DSCFIL-0068KEYSTONE STEEL &WIRE COMPANY6/1/2000FURNACE, EAF & LMFMS 1200000 T/Y PM10BAGHOUSE;INCLUDESEMISSIONS OF PM,PM10 AND PB. PMEMISSION FACTOR IS0.27 LB/TON STEELPRODUCED. PBEMISSION FACTOR IS0.006 LB/TON STEELPRODUCED.0.0018GR/DSCFBACT-PSD 0.21LB/T STEELPRODUCED0.0018GR/DSCFFL-0192AMERISTEELCORPORATION9/28/1999ELECTRIC ARC FURNACE ANDMELT SHOPMS 720000 T/YR PM10TWO BAGHOUSES, ONEFOR EAF AND ONE FORTHE MELT SHOP.EMISSION LIMIT OF.0042 GR/DSCF IN THEFIRST YEAR.0.0034GR/DSCFBACT-PSD 0.0034GR/DSCFOK-0087EJIW ARDMOREFOUNDRY INC.9/9/2003MELT AREAMS 560 T/D PM10BAGHOUSE0.0045GR/DSCFBACT-PSD 0.0045GR/DSCFIN-0109BETA STEEL CORP.5/30/2003STEEL FURNACE MELTSHOPMS 1100000 T/YR PM10BAGHOUSE, ROOFCANOPIES0.0052GR/DSCFBACT-PSD 257T/YR0.0052GR/DSCFIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H PM10BAGHOUSES.COMPLIANCE METHOD:STACK TESTING ANDBAG LEAK DETECTIONSYSTEM0.0052GR/DSCFBACT-PSD 0.0052GR/DSCFWI-0094CHARTER STEELDIVISION2/26/1997ELECTRIC ARC FURNACE, MELTSHOP, P01, S01MS 450000 T/YR PM10BAGHOUSE3.03LB/HBACT-PSD 0.0015GR/DSCFWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR PM10BAGHOUSE5.56LB/HBACT-PSD 0.0015GR/DSCFTX-0399NUCOR JEWETT PLANT1/5/2003EAF, LMF, CASTER MELTSHOPMS 240 T/H PM10FF34.21LB/HBACT-PSD 149.86T/YR*OH-0285NORTH STAR BHPSTEEL, LTD8/5/2003ELECTRIC ARC FURNACE WITHTWO LADLE MELT FURNACESMS 315 T STEEL/H PM10TWO BAGHOUSES167.2T/ROLLING 12-MONTHSBACT-PSD 35.7T/ROLLING12-MONTHS0.0018GR/DSCFVA-0240CHAPARRAL STEELCOMPANY4/24/1998MELTSHOP, MISC. OPERATIONSMS 53 MMBTU/H PM10 12LB/MMCFOther Case-by-Case 0.6LB/H0.084GR/DSCFTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS AMS PM10BAGHOUSE17.9LB/HOther Case-by-Case 71.6T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS BMS PM10BAGHOUSE26LB/HOther Case-by-Case 104.2T/YROK-0048GRIFFIN WHEEL CO10/18/1999ELECTRIC ARC FURNACE/LADLEMETALLURGY FURNACEMS PM104TH HOLE EVACUATIONW/ A STORAGE TYPECANOPY83.2T/YROther Case-by-CaseBACT-PSD PM10 GR/DSCF Emission LimitsMIN0.0014GR/DSCF MIN0.084GR/DSCFMAX0.0052GR/DSCF MAX0.084GR/DSCFMEDIAN0.0018GR/DSCF MEDIAN0.084GR/DSCFCOUNT10CASESCOUNT1CASESMS RBLC PM10 BACT Limits SummaryOther (non-BACT)-case-by-case PM10 gr/dscfEmission Limitspage 22 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-18: Melt Shop (MS)- PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC IDFACILITYNAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR PMBAGHOUSE6.05LB/HBACT-PSD 0.0015GR/DSCFWI-0094CHARTER STEELDIVISION2/26/1997ELECTRIC ARC FURNACE, MELTSHOP, P01, S01MS 450000 T/YR PMBAGHOUSE6.05LB/HBACT-PSD 0.0015GR/DSCFAR-0033NUCOR YAMATOSTEEL COMPANY3/28/20002 ELECTRIC ARCFURNACES,MELTSHOP, TUNDISHMS 450 T/H PMMULTI-COMPARTMENTPOSITIVE PRESSUREBAGHOUSE24.7LB/HBACT-PSD 0.054LB/T0.0018GR/DSCFNC-0064NUCOR STEEL4/20/1999STEEL PLANT, MELT SHOP(EAF,LMS,CSC)MS 250 T/H PMNEGATIVE PRESSUREBAGHOUSE0.0032GR/DSCFBACT-PSD 226.5T/YR0.0032GR/DSCFSC-0075NUCOR STEELDARLINGTONCOUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONS STEEL/H PMPOSITIVE PRESSURE REVERSEAIR CLEANING BAGHOUSE- 3MAIN FANS, 2 REVERSE AIRFANS. UNCAPTURED FUGITIVESVENTED THRU ROOFMONITORS.0.0052GR/DSCFBACT-PSD 0.0052GR/DSCF*NC-0112NUCOR STEEL11/23/2004MELT SHOP ROOF MONITORSMS PM 4.8LB/HBACT-PSD 21.1T/YR*OH-0285NORTH STARBHP STEEL, LTD8/5/2003ELECTRIC ARC FURNACE WITHTWO LADLE MELT FURNACESMS 315 T STEEL/H PM 46.9T/ROLLING12 MONTHSBACT-PSDTX-0399NUCOR JEWETTPLANT1/5/2003EAF, LMF, CASTER MELTSHOPMS 240 T/H PMFF55.55LB/HBACT-PSD 243.31T/YROK-0048GRIFFIN WHEELCO10/18/1999ELECTRIC ARC FURNACE/LADLEMETALLURGY FURNACEMS PM4TH HOLE EVACUATION W/ ASTORAGE TYPE CANOPY86.1T/YR OF PMBACT-PSD 0.0052GR/DSCFTN-0122HOEGANAESCORPORATION2/11/2000MELT SHOP OPERATIONSMS PMFABRIC FILTER0.005GR/DSCFOther Case-by-Case 0.0052GR/DSCFMI-0275RAVENNACASTINGCENTER, INC.4/14/2000IRON MELT SHOPMS 27 T/H PMFABRIC FILTER.0.01LB/1000 LBEXHAUSTOther Case-by-Case 0.0052GR/DSCFNC-0113NUCOR STEEL11/23/2004MELT SHOP ROOF MONITORSMS PM 4.8LB21.1TONSBACT-PSD PM GR/DSCF Emission LimitsMIN0.0015GR/DSCF MIN0.0052GR/DSCFMAX0.0052GR/DSCF MAX0.0052GR/DSCFMEDIAN0.0018GR/DSCF MEDIAN0.0052GR/DSCFCOUNT5CASES COUNT2CASESMS RBLC PM BACT Limits SummaryOther (non-BACT)-case-by-case PM gr/dscfEmission Limitspage 23 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-19: Melt Shop (MS)- PM FilterableControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITS POLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITS*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS PM FILTERABLEONE (1) BAGHOUSE, NEGATIVEPRESSURE, REVERSE AIR CLEANING,THREE FEET PER MINUTE FILTERVELOCITY, AND 1.16 MILLION DSCFMFLOW RATE0.0018GR/DSCFBACT-PSD 78.4T/YR0.0018GR/DSCFIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H PM FILTERABLEBAGHOUSES 1 & 2. EACH BAGHOUSECAN SUFFICIENTLY CONTROLEMISSIONS INDEPENDENTLY.COMPLIANCE METHOD: STACK TESTINGAND BAG LEAK DETECTION SYSTEM.0.0018GR/DSCFBACT-PSD 0.0018GR/DSCFNC-0113NUCOR STEEL11/23/2004MELT SHOPMS PM FILTERABLEONE (1) BAGHOUSE, NEGATIVEPRESSURE, REVERSE AIR CLEANING,THREE FEET PER MINUTE FILTERVELOCITY, AND 1.16 MILLION DSCFMFLOW RATE0.0018GR/DSCF78.4TONSBACT-PSD PM Filterable gr/dscf Emission LimitsMIN0.0018GR/DSCF MINNAGR/DSCFMAX0.0018GR/DSCF MAXNAGR/DSCFMEDIAN0.0018GR/DSCF MEDIANNAGR/DSCFCOUNT3CASES COUNTNACASESMS RBLC PM Filterable BACT Limits SummaryOther (non-BACT)-case-by-case PM Filterablegr/dscf Emission Limitspage 24 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-20: Melt Shop (MS)- SO2 and SOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONS STEEL/H SO20.2LB/T OFSTEELBACT-PSD 30LB/HIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H SO2SCRAP MANAGEMENT PLAN. COMPLIANCEMETHOD: SO2 CEM.0.25LB/TBACT-PSD 125LB/HIN-0109BETA STEEL CORP.5/30/2003STEEL FURNACE MELTSHOPMS 1100000 T/YR SO20.33LB/TBACT-PSD 49.87LB/HNC-0064NUCOR STEEL4/20/1999STEEL PLANT, MELT SHOP(EAF,LMS,CSC)MS 250 T/H SO2SCRAP STEEL MANAGEMENT PLAN0.35LB/TBACT-PSD 383.2T/YRVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H SO20.7LB/TBACT-PSD 150.5LB/H0IL-0068KEYSTONE STEEL &WIRE COMPANY6/1/2000FURNACE, EAF & LMFMS 1200000 T/Y SO2USE OF LOW SULFUR INJECTION COKE(0.65% OR LESS). WORK PRACTICES2LB/T STEELPRODUCEDBACT-PSDPA-0235KOPPEL STEEL CORP.11/26/2003MELT SHOPMS 598000 T/YR SOX50LB/HBACT-PSDAR-0033NUCOR YAMATO STEELCOMPANY3/28/20002 ELECTRIC ARCFURNACES,MELTSHOP, TUNDISHMS 450 T/H SO2LOW SULFUR COKE AND SCRAPMANAGEMENT67.5LB/HBACT-PSD 0.15LB/TWI-0094CHARTER STEELDIVISION2/26/1997ELECTRIC ARC FURNACE, MELTSHOP, P01, S01MS 450000 T/YR SOXNATURAL GAS. BASIS IS SYNTHETIC MINORLIMIT0.176LB/HOther Case-by-CaseWI-0206SAUKVILLE PLANT12/19/2003MELT SHOP, P01, S01MS 137.5 T/D SO2THE AMOUNT OF STEEL TAPPED MAY NOTEXCEED 62,500 TONS PER MONTH, ASDETERMINED BY AN AVERAGE OVER ANY 12CONSECUTIVE MONTHS. THIS RESTRICTIONIS PROPOSED BY THE PERMITTEE TO LIMITTHE POTENTIAL TO EMIT OF SULFUR DIOXIDEAND0.176LB/TOther Case-by-CaseWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR SO2THE SO2 LIMITS WERE SYNTHETIC MINORLIMITS TO AVOID TRIGGERING PSD.0.176LB/TOther Case-by-CaseVA-0240CHAPARRAL STEELCOMPANY4/24/1998MELTSHOP, MISC. OPERATIONSMS 53 MMBTU/H SO20.6LB/MMCFOther Case-by-Case 0.1LB/HTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS AMS SO2NONE INDICATED5.1LB/HOther Case-by-Case 19.6T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS BMS SO2NONE INDICATED8.7LB/HOther Case-by-Case 33.8T/YRTN-0122HOEGANAESCORPORATION2/11/2000MELT SHOP OPERATIONSMS SO213.14LB/HOther Case-by-Case 25.8T/YR*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS SO2SCRAP MANAGEMENT0.35LB/T STEEL383.25T/YRNC-0113NUCOR STEEL11/23/2004MELT SHOPMS SO2SCRAP MANAGEMENT0.35LB/T STEEL383.25TONSBACT-PSD SO2 and SOx lb/t steel Emission LimitsMIN 0.15 lb/t steel MIN 0.176 lb/t steelMAX 2.00 lb/t steel MAX 0.176 lb/t steelMEDIAN 0.35 lb/t steel MEDIAN 0.176 lb/t steelCOUNT9CASES COUNT2CASESMS RBLC SO2 and SOx BACT Limits SummaryOther (non-BACT)-case-by-case SO2 and SOx lb/tsteel Emission Limitspage 25 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-21: MS NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSWI-0094CHARTER STEELDIVISION2/26/1997ELECTRIC ARC FURNACE, MELTSHOP, P01, S01MS 450000 T/YR NOXCONTROL OF OPERATING PARAMETERSTO ENSURE PROPER OPERATION OF THEEMISSIONS UNITS0.51LB/HBACT-PSDTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS AMS NOXNONE INDICATED6LB/HBACT-PSD 24T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS BMS NOXNONE INDICATED10.3LB/HBACT-PSD 41.2T/YRTN-0122HOEGANAESCORPORATION2/11/2000MELT SHOP OPERATIONSMS NOXPROPER COMBUSTION CONTROL17.14LB/HBACT-PSD 68.6T/YRAR-0033NUCOR YAMATO STEELCOMPANY3/28/20002 ELECTRIC ARCFURNACES,MELTSHOP, TUNDISHMS 450 T/H NOXLOW NOX BURNERS.171LB/HBACT-PSD 0.38LB/T*OH-0285NORTH STAR BHPSTEEL, LTD8/5/2003ELECTRIC ARC FURNACE WITHTWO LADLE MELT FURNACESMS 315 T STEEL/H NOXDIRECT EVACUATION CONTROL SYSTEMWITH AIR GAP, AND COOLED POSTCOMBUSTION CHAMBER WITH BURNERS179.6LB/HBACT-PSD 786.7T/ROLLING 12-MONTHS0.57LB/TTX-0399NUCOR JEWETT PLANT1/5/2003EAF, LMF, CASTER MELTSHOPMS 240 T/H NOX 215.52LB/HBACT-PSD 578.61T/YRTN-0157HOEGANAES CORP.12/31/2003STEEL MELT SHOPMS 76.5 tons/hour NOXLOW NOX BURNERS.17.87LB/HRBACT-PSD 54.5TONS/YEAR0.2LB/TON STEELFL-0192AMERISTEELCORPORATION9/28/1999ELECTRIC ARC FURNACE ANDMELT SHOPMS 720000 T/YR NOXCOMBUSTION PRACTICES. EMISSIONLIMIT UNITS: LB/T OF STEEL (PRIMARY),LB/H 24 HR AVE (ALTERNATE).ADDITIONAL EMISSION LIMIT: 118.8 T/YR0.33LB/TBACT-PSD 330LB/HWI-0206SAUKVILLE PLANT12/19/2003MELT SHOP, P01, S01MS 137.5 T/D NOXDEC (DIRECT EVACUATION CONTROL)AND LOW NOX SUPPLEMENTALBURNERS. ALSO REQUIRES CONTROL OFDEC AND EAF OPERATING PARAMETERS.0.33LB/TBACT-PSDIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H NOXNATURAL GAS FIRED OXY FUELBURNERS, COMPLIANCE METHOD: NOXCONTINUOUS EMISSIONS MONITOR.0.35LB/TBACT-PSD 175.7LB/HIN-0109BETA STEEL CORP.5/30/2003STEEL FURNACE MELTSHOPMS 1100000 T/YR NOX0.45LB/TBACT-PSD 68.58LB/HNC-0064NUCOR STEEL4/20/1999STEEL PLANT, MELT SHOP(EAF,LMS,CSC)MS 250 T/H NOX0.51LB/TBACT-PSD 558.5T/YRWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR NOXLOW NOX BURNER0.51LB/TBACT-PSDVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H NO2LOW NOX BURNERS; WORK PRACTICES0.7LB/TBACT-PSD 150.5LB/H0OK-0048GRIFFIN WHEEL CO10/18/1999ELECTRIC ARC FURNACE/LADLEMETALLURGY FURNACEMS NOX0.2LB/T STEELBACT-PSDSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONS STEEL/H NOX0.35LB/T STEELBACT-PSD 52.5LB/H*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS NOX0.36LB/T STEELBACT-PSD 394.2T/YRIL-0068KEYSTONE STEEL &WIRE COMPANY6/1/2000FURNACE, EAF & LMFMS 1200000 T/Y NOXDEC, OXY/FUEL BURNERS. WORKPRACTICES0.51LB/T STEELPRODUCEDBACT-PSDPA-0237J & L SPECIALTY STEEL,INC.4/2/2003MELT SHOPMS 720000 T/YR NOXLAER DETERMINED TO BE PROPEROPERATION OF DIRECT EVACUATIONCONTROL504T/YRLAERMI-0275RAVENNA CASTINGCENTER, INC.4/14/2000IRON MELT SHOPMS 27 T/H NO23.1LB/HOther Case-by-Case 13.2T/YRVA-0240CHAPARRAL STEELCOMPANY4/24/1998MELTSHOP, MISC. OPERATIONSMS 53 MMBTU/H NOX100LB/MMCFOther Case-by-Case 5.3LB/HPA-0235KOPPEL STEEL CORP.11/26/2003MELT SHOPMS 598000 T/YR NOX165T/YROther Case-by-CaseNC-0113NUCOR STEEL11/23/2004MELT SHOP ROOF MONITORSMS NOX9.6LB41.6TONS*NC-0112NUCOR STEEL11/23/2004MELT SHOP ROOF MONITORSMS NOX9.6LB/H41.6T/YRNC-0113NUCOR STEEL11/23/2004MELT SHOPMS NOX0.36LB/T STEEL394.2TONSBACT-PSD NOx lb/t steel Emission LimitsMIN0.20lb/t steel MINNAlb/t steelMAX0.70lb/t steel MAXNAlb/t steelMEDIAN0.36lb/t steel MEDIANNAlb/t steelCOUNT12CASES COUNTNACASESMS RBLC NOx BACT Limits SummaryOther (non-BACT)-case-by-case NOx lb/t steelEmission Limitspage 26 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-22: Melt Shop (MS)-COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSIL-0068KEYSTONE STEEL &WIRE COMPANY6/1/2000FURNACE, EAF & LMFMS 1200000 T/Y CODEC, OXY/FUEL BURNERS, COMBUSTIONCHAMBER. WORK PRACTICES1.34LB/T STEELPRODUCEDBACT-PSD 1.34LB/TON STEELPRODUCEIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H CODIRECT SHELL EVACUATION (DSE).COMPLIANCE METHOD: CO CEM2LB/TBACT-PSD 1004LB/HSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONS STEEL/H CO 2.76LB/T OFSTEELBACT-PSD 414LB/HFL-0192AMERISTEELCORPORATION9/28/1999ELECTRIC ARC FURNACE ANDMELT SHOPMS 720000 T/YR CODIRECT EVACUATION CONTROL/ AIR GAPOXIDATION. EMISSION LIMIT UNITS: LB/TOF STEEL (PRIMARY), LB/H 24 HR AVE(ALTERNATE)ADDITIONAL EMISSIONLIMIT: 1080 T/YR3LB/TBACT-PSD 300LB/HWI-0206SAUKVILLE PLANT12/19/2003MELT SHOP, P01, S01MS 137.5 T/D CODEC (DIRECT EVACUATION CONTROL)WITH A SECOND HOLE" TO INTRODUCEAIR FOR SECONDARY COMBUSTION ANDTHE CONTROL OF OPERATINGPARAMETERS AND CARBON SOURCE TOENSURE PROPER OPERATION OF THEEMISSIONS UNITS"3.5LB/TBACT-PSDWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR CODIRECT EVACUATION CONTROL (DEC)SYSTEM3.5LB/TBACT-PSDWI-0094CHARTER STEELDIVISION2/26/1997ELECTRIC ARC FURNACE, MELTSHOP, P01, S01MS 450000 T/YR COUSE OF A DIRECT EVACUATIONCONTROL (DEC) SYSTEM AND THECONTROL OF OPERATING PARAMETERSTO ENSURE PROPER OPERATION OF THEEMISSIONS UNITS.3.83LB/HBACT-PSDVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H CODUCTING/EXTERNAL COMBUSTIONCHAMBER AT 12 MMBTU/HR; WORKPRACTICES4LB/TBACT-PSD 860LB/H0NC-0064NUCOR STEEL4/20/1999STEEL PLANT, MELT SHOP(EAF,LMS,CSC)MS 250 T/H CODIRECT SHELL EVACUATION (DSE) PLUSCOMBUSTION CHAMBER FOLLOWINGCONSTEEL CONVEYOR PREHEATINGSECTION.4LB/TBACT-PSD 4380T/YRMI-0275RAVENNA CASTINGCENTER, INC.4/14/2000IRON MELT SHOPMS 27 T/H CO24 TON/HR POURING MAXIMUM PASSESTHROUGH FABRIC FILTER/STACK15.1LB/HBACT-PSD 42.8T/YR*NC-0112NUCOR STEEL11/23/2004MELT SHOP ROOF MONITORSMS CO 25.7LB/HBACT-PSD 113.1T/YROK-0048GRIFFIN WHEEL CO10/18/1999ELECTRIC ARC FURNACE/LADLEMETALLURGY FURNACEMS CO4TH HOLE FUME CONTROLW/COMBUSTOIN AIR83.2T/YRBACT-PSD 0.0052GR/DSCFTN-0122HOEGANAESCORPORATION2/11/2000MELT SHOP OPERATIONSMS CO 158.82LB/HBACT-PSD 635.3T/YRTN-0157HOEGANAES CORP.12/31/2003STEEL MELT SHOPMS 76.5 tons/hour CODIRECT EVACUATION CONTROL (DEC)FOR ELECTRIC ARC FURNACE.COMPLIANCE TO BE VERIFIED BY STACKTESTING WITHIN 180 DAYS OF STARTUPOF THE MODIFIED SOURCE. GOODCOMBUSTION CONTROL FROM OTHEREMISSION SOURCES IN THE MELT SHOP.383LB/HBACT-PSD 1104TONS/12MONTHSTX-0399NUCOR JEWETT PLANT1/5/2003EAF, LMF, CASTER MELTSHOPMS 240 T/H CO 537.89LB/HBACT-PSD 279T/YRIN-0109BETA STEEL CORP.5/30/2003STEEL FURNACE MELTSHOPMS 1100000 T/YR CODIRECT SHELL EVACUATION (DSE)817LB/HBACT-PSD 3578.8T/YRAR-0033NUCOR YAMATO STEELCOMPANY3/28/20002 ELECTRIC ARCFURNACES,MELTSHOP, TUNDISHMS 450 T/H COAIR GAP900LB/HBACT-PSD 2LB/TPA-0235KOPPEL STEEL CORP.11/26/2003MELT SHOPMS 598000 T/YR CO 1346T/YRBACT-PSD 5LB/T*OH-0285NORTH STAR BHPSTEEL, LTD8/5/2003ELECTRIC ARC FURNACE WITHTWO LADLE MELT FURNACESMS 315 T STEEL/H CODIRECT EVACUATION CONTROL SYSTEMWITH AIR GAP, AND COOLED POSTCOMBUSTION CHAMBER WITH BURNERS2362.5LB/HBACT-PSD 10347.8T/ROLLING 12-MONTHS7.5LB/TVA-0240CHAPARRAL STEELCOMPANY4/24/1998MELTSHOP, MISC. OPERATIONSMS 53 MMBTU/H CO21LB/MMCFOther Case-by-Case 0LB/HTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS AMS CONONE INDICATED81.9LB/HOther Case-by-Case 327.6T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS BMS CONONE INDICATED140.8LB/HOther Case-by-Case 563.2T/YR*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS CODIRECT SHELL EVACUATION (DSE) VIATHE CONSTEEL PROCESS PLUSCOMBUSTION CHAMBER (AIR GAP)2.3LB/T STEEL2518.5T/YRpage 27 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-22: Melt Shop (MS)-COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSNC-0113NUCOR STEEL11/23/2004MELT SHOPMS CODIRECT SHELL EVACUATION (DSE) VIATHE CONSTEEL PROCESS PLUSCOMBUSTION CHAMBER (AIR GAP)2.3LB/T STEEL2518.5TONSNC-0113NUCOR STEEL11/23/2004MELT SHOP ROOF MONITORSMS CO 25.7LB113.1TONSBACT-PSD CO lb/t steel Emission LimitsMIN 1.34 lb/t steel MIN NA lb/t steelMAX 7.50 lb/t steel MAX NA lb/t steelMEDIAN 3.25 lb/t steel MEDIAN NA lb/t steelCOUNT14CASES COUNTNACASESMS RBLC CO BACT Limits SummaryOther (non-BACT)-case-by-case CO lb/t steelEmission Limitspage 28 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-23: Melt Shop (MS)-VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR VOCDIRECT EVACUATION CONTROL (DEC)ONELECTRIC ARC FURNACE0.06LB/TBACT-PSDIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H VOCSCRAP MANAGEMENT PLAN.COMPLIANCE METHOD: STACK TESTINGAND TOTAL HYDROCARBON CEM.0.09LB/TBACT-PSD 45.18LB/HIN-0109BETA STEEL CORP.5/30/2003STEEL FURNACE MELTSHOPMS 1100000 T/YR VOCSCRAP MANAGEMENT PROGRAM TOELIMINATE STEEL SCRAP WITH HIGHRESIDUAL OIL CONTENT.0.15LB/TBACT-PSD 83.2T/YRVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H VOCSCRAP HANDLING PLAN; WORKPRACTICES0.35LB/TBACT-PSD 75.3LB/HNC-0064NUCOR STEEL4/20/1999STEEL PLANT, MELT SHOP(EAF,LMS,CSC)MS 250 T/H VOCSCRAP STEEL, MANAGEMENT PLAN0.35LB/TBACT-PSD 383.3T/YRSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONS STEEL/H VOC0.35LB/T STEELBACT-PSD 52.5LB/HTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS AMS VOCNONE INDICATED31.2LB/HBACT-PSD 124.9T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS BMS VOCNONE INDICATED53.7LB/HBACT-PSD 214.7T/YRTX-0399NUCOR JEWETT PLANT1/5/2003EAF, LMF, CASTER MELTSHOPMS 240 T/H VOC 103.9LB/HBACT-PSD 279T/YRWI-0094CHARTER STEELDIVISION2/26/1997ELECTRIC ARC FURNACE, MELTSHOP, P01, S01MS 450000 T/YR VOCNATURAL GAS. BASIS IS SYNTHETICMINOR LIMIT.0.06LB/HOther Case-by-CaseWI-0206SAUKVILLE PLANT12/19/2003MELT SHOP, P01, S01MS 137.5 T/D VOCDEC (DIRECT EVACUATION CONTROL)0.06LB/TOther Case-by-Case 0.066LB/TFL-0192AMERISTEELCORPORATION9/28/1999ELECTRIC ARC FURNACE ANDMELT SHOPMS 720000 T/YR VOCNEW SHREDDER HAS REDUCED VOCEMISSION POTENTIAL OF AUTOMOBILEGENERATED WASTE BY 20-30%.EMISSION LIMIT UNITS: LB/T OF STEEL(PRIMARY), LB/H 24 HR AVE(ALTERNATE)ADDITIONAL EMISSIONLIMIT: 106.2 TPY0.295LB/TOther Case-by-Case 29.5LB/HTN-0122HOEGANAESCORPORATION2/11/2000MELT SHOP OPERATIONSMS VOC0.5LB/HOther Case-by-Case 2T/YRMI-0275RAVENNA CASTINGCENTER, INC.4/14/2000IRON MELT SHOPMS 27 T/H VOC4.4LB/HOther Case-by-Case 10.8T/YRVA-0240CHAPARRAL STEELCOMPANY4/24/1998MELTSHOP, MISC. OPERATIONSMS 53 MMBTU/H VOC5.3LB/MMCFOther Case-by-Case 0.3LB/H*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS VOC0.13LB/T STEEL142.4T/YRNC-0113NUCOR STEEL11/23/2004MELT SHOPMS VOC0.13LB/T STEEL142.4TONSNC-0113NUCOR STEEL11/23/2004MELT SHOP ROOF MONITORSMS VOC1.7LB7.6TONS*NC-0112NUCOR STEEL11/23/2004MELT SHOP ROOF MONITORSMS VOC1.7LB/H7.6T/YRBACT-PSD VOC lb/t steel Emission LimitsMIN0.06lb/t steel MIN0.060lb/t steelMAX0.35lb/t steel MAX0.295lb/t steelMEDIAN0.14lb/t steel MEDIAN0.178lb/t steelCOUNT8CASES COUNT2CASESMS RBLC VOC BACT Limits SummaryOther (non-BACT)-case-by-case VOC lb/t steel EmissionLimitspage 29 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-24: Melt Shop (MS)- PbControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITS*OH-0285NORTH STAR BHPSTEEL, LTD8/5/2003ELECTRIC ARC FURNACE WITHTWO LADLE MELT FURNACESMS 315 T STEEL/H PBTWO BAGHOUSES0.19LB/HBACT-PSD 1.06T/ROLLING 12MONTHS0.0018GR/DSCFVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H PBFURNACE SHAFT EVACUATION; POSITIVEP BAGHOUSE WITH A DESIGN FLOW OF1,100,000 ACFM ($550/TON REMOVED)0.34LB/HBACT-PSD 0 0TX-0399NUCOR JEWETT PLANT1/5/2003EAF, LMF, CASTER MELTSHOPMS 240 T/H LEAD OXIDE 0.88LB/HBACT-PSD 2.7T/YRSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONS STEEL/H PBPOSITIVE PRESSURE, REVERSE AIRCLEANING BAGHOUSE WITH 3 FANS, 2REVERSE AIR FANS, DSE, SIDE DRAFTHOOD ON LMF, ROOF MONITORS.1.9LB/HBACT-PSDWI-0094CHARTER STEELDIVISION2/26/1997ELECTRIC ARC FURNACE, MELTSHOP, P01, S01MS 450000 T/YR PBSYNTHETIC MINOR LIMIT0.008LB/HOther Case-by-CaseTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS AMS PBBAGHOUSE0.045LB/HOther Case-by-Case 0.18T/YRMI-0275RAVENNA CASTINGCENTER, INC.4/14/2000IRON MELT SHOPMS 27 T/H PBFABRIC FILTER0.07LB/HOther Case-by-Case 0.16T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS BMS PBBAGHOUSE0.077LB/HOther Case-by-Case 0.31T/YR*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS PB 0.0016LB/T STEEL1.52T/YRNC-0113NUCOR STEEL11/23/2004MELT SHOPMS PB 0.0016LB/T STEEL1.52TONSBACT-PSD Pb lb/t steel Emission LimitsMIN 0.0016 lb/t steel MIN NA lb/t steelMAX 0.0016 lb/t steel MAX NA lb/t steelMEDIAN 0.0016 lb/t steel MEDIAN NA lb/t steelCOUNT2CASES COUNTNACASESMS RBLC Pb BACT Limits SummaryOther (non-BACT)-case-by-case Pb lb/t steel EmissionLimitspage 30 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-25: Ladle Tundish Preheater (LP)- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT Control EquipmentEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0030ARKANSAS STEELASSOCIATES9/24/1998DRYER, LADLELP PM10 0.0052GR/DSCF1BACT-PSD 0.0052GR/DSCF1AR-0030ARKANSAS STEELASSOCIATES9/24/1998DRYER, LADLELP PM10 0.0052GR/DSCF1BACT-PSD 0.0052GR/DSCF1AR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, TUNDISHLP PM10GOOD COMBUSTION PRACTICES ANDNATURAL GAS0.0052GR/DSCF1BACT-PSD 0.0052GR/DSCF1AR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001LADLE PREHEAT & DRYOUTSTATIONSLP 225 T/H PM10GOOD COMBUSTION PRACTICE0.0075LB/MMBTUBACT-PSD 0.0075LB/MMBTUOH-0276CHARTER STEEL4/14/2003LADLE PREHEATER AND DRYER,6 UNITSLP 10 MMBTU/H PM10BAGHOUSE0.074LB/HBACT-PSD 0.32T/YR0.0024GR/DSCF1OH-0276CHARTER STEEL4/14/2003TUNDISH PREHEATER, 3 UNITSLP 20 MMBTU/H PM10BAGHOUSE0.15LB/HBACT-PSD 0.66T/YR0.0024GR/DSCF1AR-0044ARKANSAS STEELASSOCIATES1/5/2001PREHEATERS, LADLE, (3)LP 4 MMBTU/H PM10NATURAL GAS COMBUSTION/GOODCOMBUSTION PRACTICES.0.2LB/HBACT-PSD 0.7T/YRTX-0398NUCOR JEWETT PLANT5/5/2000LADLE PREHEATLP PM10 0.2LB/HBACT-PSD 0.88T/YRTX-0398NUCOR JEWETT PLANT5/5/2000PREHEAT LADLELP PM10 0.23LB/HBACT-PSD 0.99T/YRIN-0090NUCOR STEEL1/19/2001LADLE PREHEATERSLP 15 MMBTU/HR EACH PM10PERMIT LIMITATION IS USE OF NATURALGAS OR PROPANEBACT-PSDIN-0090NUCOR STEEL1/19/2001TUNDISH PREHEATERS (2)LP 6 MMBTU/H PM10PERMIT LIMITATION IS USE OF NATURALGAS.BACT-PSDTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000B-SIDE LADLE HEATERSSIDEWALL VENT, 10CLP PM10NONE INDICATED0.15LB/HN/A 0.58T/YROH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ECCENTRIC BOTTOM TAPPINGLADLE PREHEATER FURNACELP 14 MMBTU/H PM10 0.196LB/HN/A 0.86T/YR0.014LB/MMBTUTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000A-SIDE LADLE HEATERSSIDEWALL VENTLP PM10NONE INDICATED0.04LB/HOther Case-by-Case 0.18T/YRBACT-PSD PM10 lb/MMBTU Emission LimitsMIN 0.0075 lb/MMBTU MIN 0.014 lb/MMBTUMAX 0.0075 lb/MMBTU MAX 0.014 lb/MMBTUMEDIAN 0.0075 lb/MMBTU MEDIAN 0.014 lb/MMBTUCOUNT1CASES COUNT1CASESLP RBLC PM10 BACT Limits SummaryOther (non-BACT)-case-by-case PM10 lb/MMBTUEmission Limits* BACT limits on a gr/dscf are equal to typical melt shop limits. It is logical to assume that the compliancedemonstration for the gr/dscf limits at these sources is at the melt shop exhaust. Preheaters are open flameburners. Since the preheater flue gas cannot be routed through a stack; preheater exhaust typically is routedto the melt shop baghouse along with the other melt shop sources.page 31 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-26: Ladle Tundish Preheater (LP)- SO2 and SOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSTX-0398NUCOR JEWETT PLANT5/5/2000LADLE PREHEATLP SO2 0.01LB/HBACT-PSD 0.04T/YRTN-0071WAUPACA FOUNDRY,INC.4/28/2000MISC. NATURAL GAS USAGEFOR PREHEATING LADLESLP 0.02 MMCF/H SO2USING NATURAL GAS AS FUEL ANDTAKING AN EMISSION LIMITATION.0.01LB/HBACT-PSDAR-0030ARKANSAS STEELASSOCIATES9/24/1998DRYER, LADLELP SO2 0.1LB/HBACT-PSDAR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, TUNDISHLP SO2 0.1LB/HBACT-PSDAR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, LADLELP SO2GOOD COMBUSTION PRACTICES(NATURAL GAS)0.1LB/HBACT-PSDIN-0090NUCOR STEEL1/19/2001LADLE PREHEATERSLP 15 MMBTU/HR EACH SO2PERMIT LIMITATION IS NATURAL GAS ORPROPANE USAGEBACT-PSDIN-0090NUCOR STEEL1/19/2001TUNDISH PREHEATERS (2)LP 6 MMBTU/H SOXPERMIT LIMITATION IS USE OF NATURALGAS.BACT-PSDTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000A-SIDE LADLE HEATERSSIDEWALL VENTLP SO2NONE INDICATED0.08LB/HOther Case-by-Case 0.014T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000B-SIDE LADLE HEATERSSIDEWALL VENT, 10CLP SO2NONE INDICATED0.27LB/HOther Case-by-Case 0.05T/YRNE-0025NUCOR STEELDIVISION6/22/2004LADLE PREHEATERS (TOTAL)LP 48 MMBTU/H SO2 346.59LB/TOther Case-by-CaseNE-0026NUCOR STEELDIVISION6/22/2004LADLE PREHEATERLP 48 MMBTU/H SO2 346.59LB/TOther Case-by-CaseOH-0276CHARTER STEEL4/14/2003LADLE PREHEATER AND DRYER,6 UNITSLP 10 MMBTU/H SO2 0.006LB/H0.03T/YROH-0276CHARTER STEEL4/14/2003TUNDISH PREHEATER, 3 UNITSLP 20 MMBTU/H SO2 0.01LB/H0.05T/YRBACT-PSD SO2 and SOx lb/t steel Emission LimitsMINNAlb/t steel MIN346.59lb/t steelMAXNAlb/t steel MAX346.59lb/t steelMEDIANNAlb/t steel MEDIAN346.59lb/t steelCOUNTNACASES COUNT0CASESLP RBLC SO2 and SOx BACT Limits SummaryOther (non-BACT)-case-by-case SO2 and SOx lb/tsteel Emission Limitspage 32 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-27: Ladle Tundish Preheater (LP)- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, TUNDISHLP NOX0.1LB/HBACT-PSDKY-0094NORTH AMERICANSTAINLESS12/1/2003DRYERS, NATURAL GAS, (2)EMISSION POINT 83LP 3.1 mmbtu/h NOXLOW NOX BURNERS0.304LB/HBACT-PSD 1.33T/YR0.098LB/MMBTUTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000A-SIDE LADLE HEATERSSIDEWALL VENTLP NOXTHE NATURAL-GAS FIRED SIDEWALLSUPPLEMENTAL BURNERS FOR THE (2)ELECTRIC ARC FURNACES ARE DESIGNEDTO MINIMIZE NOX EMISSIONS BY UTILIZINGBOTH OXYGEN AND AIR FOR OXIDATION.0.59LB/HBACT-PSD 2.34T/YRAR-0030ARKANSAS STEELASSOCIATES9/24/1998DRYER, LADLELP NOX0.7LB/HBACT-PSDOH-0276CHARTER STEEL4/14/2003LADLE PREHEATER AND DRYER,6 UNITSLP 10 MMBTU/H NOX0.98LB/HBACT-PSD 4.29T/YRAR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, LADLELP NOXGOOD COMBUSTION PRACTICES (NATURALGAS)1.2LB/HBACT-PSDOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ECCENTRIC BOTTOM TAPPINGLADLE PREHEATER FURNACELP 14 MMBTU/H NOXLOW NOX BURNER1.25LB/HBACT-PSD 5.5T/YR0.089LB/MMBTUTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000B-SIDE LADLE HEATERSSIDEWALL VENT, 10CLP NOXTHE NATURAL-GAS FIRED SIDEWALLSUPPLEMENTAL BURNERS FOR THE (2)ELECTRIC ARC FURNACES ARE DESIGNEDTO MINIMIZE NOX EMISSIONS BY UTILIZINGBOTH OXYGEN AND AIR FOR OXIDATION.1.91LB/HBACT-PSD 7.65T/YROH-0276CHARTER STEEL4/14/2003TUNDISH PREHEATER, 3 UNITSLP 20 MMBTU/H NOX1.96LB/HBACT-PSD 8.58T/YRTX-0398NUCOR JEWETT PLANT5/5/2000LADLE PREHEATLP NOX2.04LB/HBACT-PSD 8.95T/YRTX-0398NUCOR JEWETT PLANT5/5/2000PREHEAT LADLELP NOX2.3LB/HBACT-PSD 10.07T/YRAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001LADLE PREHEAT & DRYOUTSTATIONSLP 225 T/H NOXLOW NOX BURNERS0.098LB/MMBTUBACT-PSD 0.098LB/MMBTUIN-0073QUALITECH STEELCORP.10/31/1996LADLE PREHEAT/DRYERSTATIONSLP 8 MMBTU/H NOXLOW NOX BURNERS0.1LB/MMBTUBACT-PSD 32MMBTU/H0IN-0073QUALITECH STEELCORP.10/31/1996TUNDISH DRYERLP 5 MMBTU/H NOXLOW NOX BURNERS0.1LB/MMBTUBACT-PSD 5MMBTU/H0IN-0073QUALITECH STEELCORP.10/31/1996TUNDISH PREHEATERS (2)LP 5 MMBTU/H NOXLOW NOX BURNERS0.1LB/MMBTUBACT-PSD 5MMBTU/H0TX-0417NUCOR CORP.1/15/2003PROCESS HEATERS, LADLE &TUNDISHLP NOXLOW NOX BURNERS AND CLEAN FUEL.0.1LB/MMBTUBACT-PSD 0.1LB/MMBTUIN-0090NUCOR STEEL1/19/2001LADLE PREHEATERSLP 15 MMBTU/HR EACH NOXLOW NOX BURNERS0.1LB/MMBTUBACT-PSDIN-0079STEEL DYNAMICS, INC.7/7/1999DRYERS, NATURAL GAS FIRED;(PREHEATERS)LP 10 MMBTU/H NOXLOW NOX BURNERS0.1LB/MMBTUBACT-PSD 0IN-0080STEEL DYNAMICS, INC.7/7/1999PREHEATERS, NATURAL GASFIREDLP 10 MMBTU/H NOXLOW NOX BURNERS0.1LB/MMBTUBACT-PSD 0 0.1LB/MMBTUIN-0090NUCOR STEEL1/19/2001TUNDISH PREHEATERS (2)LP 6 MMBTU/H NOXLOW NOX BURNERS, BTU LIMIT0.15LB/MMBTUBACT-PSDNE-0025NUCOR STEEL DIVISION6/22/2004LADLE PREHEATERS (TOTAL)LP 48 MMBTU/H NOX82.92LB/TOther Case-by-CaseNE-0026NUCOR STEEL DIVISION6/22/2004LADLE PREHEATERLP 48 MMBTU/H NOXULTRA-LOW NOX BURNERS82.92LB/TOther Case-by-CaseBACT-PSD NOx lb/MMBTU Emission LimitsMIN 0.089 lb/MMBTU MIN NA lb/t steelMAX 2.040 lb/MMBTU MAX NA lb/t steelMEDIAN 1.090 lb/MMBTU MEDIAN NA lb/t steelCOUNT10CASES COUNTNACASESLP RBLC NOx BACT Limits SummaryOther (non-BACT)-case-by-case NOx lb/MMBTUEmission Limitspage 33 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-28: Ladle Tundish Preheater (LP)- COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001LADLE PREHEAT & DRYOUTSTATIONSLP 225 T/H COGOOD COMBUSTION PRACTICE0.0824LB/MMBTUBACT-PSD 0.0824LB/MMBTUAR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, TUNDISHLP CO0.1LB/HBACT-PSDAR-0030ARKANSAS STEELASSOCIATES9/24/1998DRYER, LADLELP CO0.2LB/HBACT-PSDKY-0094NORTH AMERICANSTAINLESS12/1/2003DRYERS, NATURAL GAS, (2)EMISSION POINT 83LP 3.1 mmbtu/h CO 0.255LB/HBACT-PSD 1.12T/YR0.0823LB/MMBTUAR-0044ARKANSAS STEELASSOCIATES1/5/2001PREHEATERS, LADLE, (3)LP 4 MMBTU/H CONATURAL GAS COMBUSTION/GOODCOMBUSTION PRACTICES.0.3LB/HBACT-PSD 1.2T/YRAR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, LADLELP COGOOD COMBUSTION PRACTICES(NATURAL GAS)0.3LB/HBACT-PSDTX-0398NUCOR JEWETT PLANT5/5/2000LADLE PREHEATLP CO 0.51LB/HBACT-PSD 2.24T/YRTX-0398NUCOR JEWETT PLANT5/5/2000PREHEAT LADLELP CO 0.58LB/HBACT-PSD 2.52T/YROH-0276CHARTER STEEL4/14/2003LADLE PREHEATER AND DRYER,6 UNITSLP 10 MMBTU/H CO 0.82LB/HBACT-PSD 3.59T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000B-SIDE LADLE HEATERSSIDEWALL VENT, 10CLP CONONE INDICATED1.61LB/HBACT-PSD 6.43T/YROH-0276CHARTER STEEL4/14/2003TUNDISH PREHEATER, 3 UNITSLP 20 MMBTU/H CO 1.64LB/HBACT-PSD 7.18T/YRIN-0090NUCOR STEEL1/19/2001LADLE PREHEATERSLP 15 MMBTU/HR EACH COPERMIT LIMITATION IS NATURAL GAS ORPROPANE USAGEBACT-PSDIN-0090NUCOR STEEL1/19/2001TUNDISH PREHEATERS (2)LP 6 MMBTU/H COPERMIT LIMITATION IS USE OF NATURALGAS.BACT-PSDOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ECCENTRIC BOTTOM TAPPINGLADLE PREHEATER FURNACELP 14 MMBTU/H CO1.2LB/HN/A 5.3T/YR0.086LB/MMBTUTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000A-SIDE LADLE HEATERSSIDEWALL VENTLP CONONE INDICATED0.49LB/HOther Case-by-Case 1.97T/YRNE-0025NUCOR STEEL DIVISION6/22/2004LADLE PREHEATERS (TOTAL)LP 48 MMBTU/H CO 729.89LB/TOther Case-by-CaseNE-0026NUCOR STEEL DIVISION6/22/2004LADLE PREHEATERLP 48 MMBTU/H CO 729.89LB/TOther Case-by-CaseBACT-PSD CO lb/t steel Emission LimitsMIN 0.0823 lb/MMBTU MIN NA lb/MMBTUMAX 0.0824 lb/MMBTU MAX NA lb/MMBTUMEDIAN 0.0824 lb/MMBTU MEDIAN NA lb/MMBTUCOUNT2CASES COUNTNACASESLP RBLC CO BACT Limits SummaryOther (non-BACT)-case-by-case CO lb/t steel Emission Limitspage 34 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-29: Ladle Tundish Preheater (LP)-VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001LADLE PREHEAT & DRYOUTSTATIONSLP 225 T/H VOCGOOD COMBUSTION PRACTICE0.0054LB/MMBTUBACT-PSD 0.0054LB/MMBTUTX-0398NUCOR JEWETT PLANT5/5/2000PREHEAT LADLELP VOC 0.01LB/HBACT-PSD 0.04T/YRKY-0094NORTH AMERICANSTAINLESS12/1/2003DRYERS, NATURAL GAS, (2)EMISSION POINT 83LP 3.1 mmbtu/h VOC 0.0167LB/HBACT-PSD 0.07T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000A-SIDE LADLE HEATERSSIDEWALL VENTLP VOCNONE INDICATED0.03LB/HBACT-PSD 0.13T/YRTX-0398NUCOR JEWETT PLANT5/5/2000LADLE PREHEATLP VOC 0.04LB/HBACT-PSD 0.18T/YROH-0276CHARTER STEEL4/14/2003LADLE PREHEATER AND DRYER,6 UNITSLP 10 MMBTU/H VOC 0.05LB/HBACT-PSD 0.24T/YRTN-0071WAUPACA FOUNDRY,INC.4/28/2000MISC. NATURAL GAS USAGE FORPREHEATING LADLESLP 0.02 MMCF/H VOCUSING NATURAL GAS AS FUEL ANDTAKING AN EMISSION LIMITATION0.08LB/HBACT-PSDAR-0030ARKANSAS STEELASSOCIATES9/24/1998DRYER, LADLELP VOC 0.1LB/HBACT-PSDAR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, TUNDISHLP VOC 0.1LB/HBACT-PSDAR-0030ARKANSAS STEELASSOCIATES9/24/1998PREHEATER, LADLELP VOCGOOD COMBUSTION PRACTICES(NATURAL GAS)0.1LB/HBACT-PSDOH-0276CHARTER STEEL4/14/2003TUNDISH PREHEATER, 3 UNITSLP 20 MMBTU/H VOC 0.11LB/HBACT-PSD 0.47T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000B-SIDE LADLE HEATERSSIDEWALL VENT, 10CLP VOCNONE INDICATED0.11LB/HBACT-PSD 0.42T/YRNE-0026NUCOR STEEL DIVISION6/22/2004LADLE PREHEATERLP 48 MMBTU/H VOC 25.7LB/TOther Case-by-CaseNE-0025NUCOR STEEL DIVISION6/22/2004LADLE PREHEATERS (TOTAL)LP 48 MMBTU/H VOC 25.77LB/TOther Case-by-CaseBACT-PSD VOC lb/MMBTU Emission LimitsMIN 0.0054 lb/MMBTU MIN NA lb/MMBTUMAX 0.0054 lb/MMBTU MAX NA lb/MMBTUMEDIAN 0.0054 lb/MMBTU MEDIAN NA lb/MMBTUCOUNT1CASES COUNTNACASESLP RBLC VOC BACT Limits SummaryOther (non-BACT)-case-by-case VOC lb/MMBTUEmission Limitspage 35 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-30: Tunnel Furnace (TF)Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSIN-0070NUCOR STEEL6/20/1996SNUB FURNACE ON NO.1TUNNEL FURNACETF 6 MMBTU/H PMFUEL SPEC: NATURAL GAS0SEE P2BACT-PSD 0IN-0070NUCOR STEEL6/20/1996SNUB FURNACE ON NO.1TUNNEL FURNACETF 6 MMBTU/H PM10FUEL SPEC: NATURAL GAS0SEE P2BACT-PSD 0AR-0077BLUEWATER PROJECT7/22/2004TUNNEL FURNACETF 160 MMBTU/H SO2NATURAL GAS COMBUSTION ONLY0.0006LB/MMBTUBACT-PSD 0.5T/YR0.0006LB/MMBTUAR-0077BLUEWATER PROJECT7/22/2004TUNNEL FURNACETF 160 MMBTU/H VOCNATURAL GAS COMBUSTION ONLY0.005LB/MMBTUBACT-PSD 3.9T/YRAR-0077BLUEWATER PROJECT7/22/2004TUNNEL FURNACETF 160 MMBTU/H PM10NATURAL GAS COMBUSTION ONLY0.0076LB/MMBTUBACT-PSD 5.4T/YR0.0076LB/MMBTUAR-0077BLUEWATER PROJECT7/22/2004TUNNEL FURNACETF 160 MMBTU/H COGOOD COMBUSTION PRACTICE0.037LB/MMBTUBACT-PSD 26T/YR0.037LB/MMBTUAR-0077BLUEWATER PROJECT7/22/2004TUNNEL FURNACETF 160 MMBTU/H NOXLOW NOX BURNERS0.1LB/MMBTUBACT-PSD 70T/YR0.1LB/MMBTUIN-0070NUCOR STEEL6/20/1996SNUB FURNACE ON NO.1TUNNEL FURNACETF 6 MMBTU/H NOXLOW NOX BURNERS0.19LB/MMBTUBACT-PSD 0 0BACT-PSD lb/MMBTU Emission LimitsPM100.0076lb/MMBTUSO20.0006lb/MMBTUVOC0.0050lb/MMBTUCO0.0370lb/MMBTUBACT-PSD NOx Emission LimitsMIN0.100lb/t steelMAX0.190lb/t steelMEDIAN0.145lb/t steelCOUNT2CASESTF RBLC BACT Limits SummaryOther (non-BACT)-case-by-case Emission LimitsNo Performance LimitsOther (non-BACT)-case-by-case NOx Emission LimitsNo Performance Limitspage 36 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-31: Material Handling (MH) and Fugitive (Fug)- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSION LIMIT2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACTgr/dscfLimitsNon-BACTgr/dscfLimitsAR-0044ARKANSAS STEELASSOCIATES1/5/2001ROADS, PAVED & UNPAVEDMH & Fug PM10 PWATER APPLICATON TO CONTROL FUGITIVEEMISSIONS.6.9T/YRBACT-PSDNAAR-0077BLUEWATER PROJECT7/22/2004MATERIAL HANDLING SILOSMH & Fug PM10 AFABRIC FILTERS0.01GR/DSCFBACT-PSD0.0100AR-0077BLUEWATER PROJECT7/22/2004ROADWAY EMISSIONSMH & Fug PM10 PAPPLICATION OF WETTING AGENT26.9T/YRBACT-PSDNAAR-0078NUCOR STEEL,ARKANSAS9/9/1999MATERIAL HANDLINGMH & Fug PM10 AFABRIC FILTER0.01GR/DSCFBACT-PSD0.0100AR-0078NUCOR STEEL,ARKANSAS9/9/1999LIME SILOMH & Fug PM10 AFABRIC FILTER0.1LB/HBACT-PSD 0.1T/YR0.0005GR/DSCF0.0005AR-0078NUCOR STEEL,ARKANSAS9/9/1999CARBON SILOMH & Fug PM10 AFABRIC FILTER0.1LB/HBACT-PSD 0.5T/YRNAIN-0073QUALITECH STEELCORP.10/31/1996MATL. CRUSHING, HANDLING, &STORAGEMH & Fug 5 LB/H PM10 PWORK PRACTICES; VE AVERAGE ASCALCULATED BY METHOD 9.3% OPACBACT-PSDNAIN-0073QUALITECH STEELCORP.10/31/1996MATL. HANDLING, BAGHOUSEWASTEMH & Fug 100 T/BINS PM10 PCOVERED CONVEYORS, BINS WITH FILTERSLOADING INTO SEALED TRUCKS WITHENCLOSED SHEDBACT-PSDNAIN-0090NUCOR STEEL1/19/2001LMS BAGHOUSE SILOMH & Fug PM10 PBIN VENT FILTER0.01GR/DSCFBACT-PSD0.0100IN-0090NUCOR STEEL1/19/2001STORAGE SILO FOR BLASTINGMEDIAMH & Fug 1000 DSCFM PM10 ABIN VENT0.01GR/DSCFBACT-PSD0.0100IN-0090NUCOR STEEL1/19/2001TRANSPORTATION ON ROADSMH & Fug PM10 PSPEED LIMITS, VACUUMING/SWEEPINGEVERY 14 DAYS. DUST SUPPRESSANT ONUNPAVED ROADS AT A RATE OF 0.16GAL/YD2 ONCE PER MONTH. EMISSION UNITIS LB SILT PER MILE16.8LB/MIBACT-PSDNAKY-0095RECMIX OF PA, INC.8/6/2004UNPAVED ROADMH & Fug PM10 PWATERING0.78T/YRBACT-PSDNAKY-0095RECMIX OF PA, INC.8/6/2004STOCKPILESMH & Fug 20000 t PM10 PMATERIAL HAS HIGH MOISTURE CONTENT0.78T/YRBACT-PSDNAKY-0095RECMIX OF PA, INC.8/6/2004OVERSIZE SLAG HANDLING,STOCKPILESMH & Fug 84000 t/yr PM10 PCOVERS TO OPENINGS0.78T/YRBACT-PSDNAKY-0095RECMIX OF PA, INC.8/6/2004OVERSIZE SLAG HANDLING,CONVEYOR TO STOCKPILESMH & Fug 84000 t/yr PM10 PWATERING0.78T/YRBACT-PSDNAKY-0095RECMIX OF PA, INC.8/6/2004CRUSHING OPERATIONMH & Fug 79800 t/yr PM10 PWATER MIST SPRAYS AT MULTIPLELOCATIONS0.78T/YRBACT-PSDNAKY-0095RECMIX OF PA, INC.8/6/2004FINAL AGGREGATE HANDLING,STORAGEMH & Fug 266000 t/yr PM10 PHIGH MOISTURE CONTENT0.78T/YRBACT-PSDNAKY-0095RECMIX OF PA, INC.8/6/2004FINAL AGGREGATE HANDLING,EXIT PILEMH & Fug 266000 t/yr PM10 PHIGH MOISTURE CONTENT0.78T/YRBACT-PSDNAMN-0061ERIE NUGGET6/26/2005COAL & FLUX UNLOADINGMH & Fug 4000000 DSCF PM10 AFF0.005GR/DSCFBACT-PSD 0.005GR/DSCF0.0050MN-0061ERIE NUGGET6/26/2005RAIL LOADOUTMH & Fug 4000000 DSCF PM10 AFF0.005GR/DSCFBACT-PSD 0.005GR/DSCF0.0050MN-0061ERIE NUGGET6/26/2005MATERIAL TRANSFEROPERATIONSMH & Fug 6000000 DSCF/H PM10 AFF0.005GR/DSCFBACT-PSD 0.005GR/DSCF0.0050MN-0064NORTHSHORE MININGCOMPANY3/22/2006TERTIARY CRUSHING (CRUSHERLINE 4 AND CRUSHER LINE 104)MH & Fug 700 LT/H Ore Particulate MattAFABRIC FILTER0.0025GR/DSCFBACT-PSD0.0025MN-0064NORTHSHORE MININGCOMPANY3/22/2006CONCENTRATOR BINS (WESTSTORAGE BINS #2, #3, #4, #5, #6,#7, #8, #9 AND #10)MH & Fug 200 LT/H concent Particulate MattAFABRIC FILTER0.003GR/DSCFBACT-PSD0.0030MN-0064NORTHSHORE MININGCOMPANY3/22/2006FURNACE 5 DISCHARGEMH & Fug 160 LT/H pellets Particulate MattAFABRIC FILTER0.01GR/DSCFBACT-PSD 0.18LB/MMBTU0.0100OH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003BAGHOUSE DUST HANDLINGSYSTEM MH & FugPM10 AFABRIC FILTER0.01GR/DSCFOther Case-by-Cas0.27LB/H0.010OH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001COKE AND BREEZECRUSHING/SCREENING/CONVEYINGMH & Fug PM10 ABAGHOUSE WITH 0.008 GR/DSCF3.43LB/HBACT-PSD 15.02T/YRNAOH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001ROADWAYS AND PARKINGMH & Fug PM10 PWATERING AS SUFFICIENT FREQUENCY TOENSURE COMPLIANCE1.56T/YRBACT-PSDNAOH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001LOAD IN AND LOAD OUT OFCOKE/COAL STORAGE PILESMH & Fug PM10 PLOAD-IN COAL, COKE, AND COKE BREEZEW/ STACKING TUBE; LOAD-IN COALW/WATER SPRAYS/DUST SUPPRESSANT;LOAD-OUT COAL UNDER PILE GRAVITYFEED AND WATER SPRAY; LOAD-OUT COKEW/ UNDER PILE GRAVITY FEED.1.98T/YRBACT-PSDNAOH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001COAL HANDLING, CONVEYING,AND TRANSFERMH & Fug 6602850 T/YR PM10 PRAIL CAR BOTTOM DUMPING ANDENCLOSED; BELT CONVEYORS ENCLOSED;WET AND/OR CHEMICAL SUPPRESSION3.77T/YRBACT-PSDNAOH-0276CHARTER STEEL4/14/2003SILOS CARBON, LIME, AND DUSTMH & Fug 50 T/H PM10 ABIN VENT0.45T/YRBACT-PSD 0.01GR/DSCF0.0100OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005BASIC OXYGEN FURNACES (2VESSELS), FUGITIVE EMISSIONSMH & Fug 375 t/h PM10 N28.06LB/HRACT 61.37T/YRNAOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR EAFMH & Fug 2.5 MM t/yr PM10 ABAGHOUSE AND BIN VENT FILTERS8.28T/YR0.01GR/DSCF0.010OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR BOFMH & Fug PM10 ATHREE BAGHOUSES16.83T/YRNAOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR LMFMH & Fug 2.5 mm t/yr PM10 ABIN VENT FILTERS0.882T/YR0.02GR/DSCF0.020page 37 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-31: Material Handling (MH) and Fugitive (Fug)- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSION LIMIT2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACTgr/dscfLimitsNon-BACTgr/dscfLimitsTX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000GRIZZLY TO STOCKMH & Fug PM10 NNONE INDICATED0.0002LB/HOther Case-by-Cas0.0001T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000RAILCAR LOADING FROMPELLETIZER SILO/BAGHOUSEDUSTMH & Fug PM10 NNONE INDICATED0.0003LB/HOther Case-by-Cas0.0011T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SCREEN TO CONV TO CONV,S15&16MH & Fug PM10 NNONE INDICATED0.0003LB/HOther Case-by-Cas0.0002T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SCREEN TO CONV TO STOCK,S20&21MH & Fug PM10 NNONE INDICATED0.0005LB/HOther Case-by-Cas0.0003T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CONV TO CONV, S11MH & Fug PM10 NNONE INDICATED0.0008LB/HOther Case-by-Cas0.0005T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CONV TO CONV, S12MH & Fug PM10 NNONE INDICATED0.0008LB/HOther Case-by-Cas0.0005T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CONV TO SCREEN, S13MH & Fug PM10 NNONE INDICATED0.0009LB/HOther Case-by-Cas0.0005T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SCREEN TO CONV TO STOCK,S22&23MH & Fug PM10 NNONE INDICATED0.001LB/HOther Case-by-Cas0.0006T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000OUTDOOR & INDOOR ALLOYHANDLING, 11A&BMH & Fug PM10 NNONE INDICATED0.0011LB/HOther Case-by-Cas0.0042T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000FEEDER TO FEEDER TO CONV TOSCREEN, S7-9MH & Fug PM10 NNONE INDICATED0.0018LB/HOther Case-by-Cas0.0011T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SHREDDER FUGITIVES, 16MH & Fug PM10 NNONE INDICATED0.0024LB/HOther Case-by-Cas0.006T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CONV TO CRUSHER TO CONV,S30&32MH & Fug PM10 NNONE INDICATED0.0026LB/HOther Case-by-Cas0.0016T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SCREEN TO CONV, S28MH & Fug PM10 NNONE INDICATED0.0101LB/HOther Case-by-Cas0.006T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CONV TO CONV TO BIN TOTRUCK, S17-19MH & Fug PM10 NNONE INDICATED0.0103LB/HOther Case-by-Cas0.0062T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000GRIZZLY TO CONV TO CONV, S4& S5MH & Fug PM10 NNONE INDICATED0.0118LB/HOther Case-by-Cas0.0071T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SCREEN, S14MH & Fug PM10 NNONE INDICATED0.013LB/HOther Case-by-Cas0.008T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000VIBRATING SCREEN, 22MH & Fug PM10 NNONE INDICATED0.015LB/HOther Case-by-Cas0.065T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SCREEN TO CONV, S29MH & Fug PM10 NNONE INDICATED0.0176LB/HOther Case-by-Cas0.0106T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CONV TO CONV, S33MH & Fug PM10 NNONE INDICATED0.0176LB/HOther Case-by-Cas0.01T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000FEEDER TO FEEDER TO CONV TOSCREEN, S24-26MH & Fug PM10 NNONE INDICATED0.0277LB/HOther Case-by-Cas0.0166T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CONV TO FEEDER, S6MH & Fug PM10 NNONE INDICATED0.029LB/HOther Case-by-Cas0.018T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SCREEN, S10MH & Fug PM10 NNONE INDICATED0.031LB/HOther Case-by-Cas0.019T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CRUSHER, S31MH & Fug PM10 ABAGHOUSE0.032LB/HOther Case-by-Cas0.019T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000PELLETIZER SILO, 15AMH & Fug PM10 ABAGHOUSE0.0324LB/HOther Case-by-Cas0.1296T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000MATERIAL HANDLING, 23MH & Fug PM10 NNONE INDICATED0.15LB/HOther Case-by-Cas0.67T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000FRONT-END LOADER DROP @MIXING BLDG, S35MH & Fug PM10 NNONE INDICATED0.221LB/HOther Case-by-Cas0.98T/YRNApage 38 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-31: Material Handling (MH) and Fugitive (Fug)- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSION LIMIT2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACTgr/dscfLimitsNon-BACTgr/dscfLimitsTX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000CRUSHER, SBH-1MH & Fug PM10 NTHE BAGHOUSE IS A CONTROL DEVICE FORTHE CRUSHER, BUT THESE EMISSIONLIMITS ARE LISTED SPECIFICALLY FOR THEBAGHOUSE.0.343LB/HOther Case-by-Cas0.2T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000SCREEN, S27MH & Fug PM10 NNONE INDICATED0.484LB/HOther Case-by-Cas0.291T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000UNPROCESSED RESIDUE &RESIDUE STORAGE PILE, 20A&21MH & Fug PM10 NNONE INDICATED0.14T/YROther Case-by-CaseNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000FINES/COARSE SAND/LIGHTORGANIC MATERIAL STORAGEMH & Fug PM10 NNONE INDICATED0.14T/YROther Case-by-CaseNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000STOCKPILE, S37MH & Fug PM10 NNONE INDICATED0.21T/YROther Case-by-CaseNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEEL MILL4/24/2000IN-PLANT VEHICLE TRAFFICMH & Fug PM10 PCHEMICAL AND WATER SPRAY12.5T/YROther Case-by-CaseNATX-0398NUCOR JEWETT PLANT5/5/2000LIME & DOLOMITE STORAGEMH & Fug PM10 AFF0.09LB/HBACT-PSD 0.38T/YRNATX-0398NUCOR JEWETT PLANT5/5/2000LIME STORAGEMH & Fug PM10 AFF0.09LB/HBACT-PSD 0.38T/YRNATX-0398NUCOR JEWETT PLANT5/5/2000DOLMITE STORAGEMH & Fug PM10 N0.09LB/HBACT-PSD 0.38T/YRNAVA-0240CHAPARRAL STEELCOMPANY4/24/1998UNPAVED RDS,STORAGE PILES &MATERIAL TRANSFER OP.MH & Fug 0 PM10 PDUST MANAGEMENT PLAN; WORKPRACTICE (90%)0.1LB/HOther Case-by-Cas0 0NABACT-PSD PM gr/dscf Emission LimitsMIN0.0025gr/dscf MIN0.0100gr/dscfMAX0.010gr/dscf MAX0.020gr/dscfMEDIAN0.010gr/dscf MEDIAN0.010gr/dscfCOUNT11CASES COUNT3CASESMH & Fug RBLC PM BACT Limits SummaryOther (non-BACT)-case-by-case PM gr/dscfEmission Limitspage 39 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-32: Material Handling (MH) and Fugitive (Fug)- PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASEBASISEMISSIONLIMIT 2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACTgr/dscfLimitsNon-BACTgr/dscfLimitsIN-0073QUALITECH STEELCORP.10/31/1996MATL. CRUSHING, HANDLING, &STORAGEMH & Fug 5 LB/H PM PWORK PRACTICES; VE AVERAGE ASCALCULATED BY METHOD 9.3% OPACBACT-PSDNAMN-0061ERIE NUGGET6/26/2005COAL & FLUX UNLOADINGMH & Fug 4000000 DSCF PM AFF0.005GR/DSCFBACT-PSD 0.005GR/DSCF0.0050MN-0061ERIE NUGGET6/26/2005RAIL LOADOUTMH & Fug 4000000 DSCF PM AFF0.005GR/DSCFBACT-PSD 0.005GR/DSCF0.0050MN-0061ERIE NUGGET6/26/2005MATERIAL TRANSFEROPERATIONSMH & Fug 6000000 DSCF/H PM AFF0.005GR/DSCFBACT-PSD 0.005GR/DSCF0.0050IN-0119AUBURN NUGGET5/31/2005SILOSMH & Fug PM ABIN FILTERS0.01GR/DSCFBACT-PSD0.0100OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR LMFMH & Fug 2.5 mm t/yr PM ABIN VENT FILTERS0.02GR/DSCF1.11T/YR0.02GR/DSCF0.020*NC-0112NUCOR STEEL11/23/2004RAW MATERIAL STORAGE SILOSMH & Fug PM ABIN VENT FILTERS0.01GR/DSCFBACT-PSD 0.01GR/DSCF0.0100NC-0113NUCOR STEEL11/23/2004RAW MATERIAL STORAGE SILOSMH & Fug PM ABIN VENT FILTERS0.01GR/DSCF0.010TX-0417NUCOR CORP.1/15/2003RAW MATERIAL RECEIVING ANDHANDLINGMH & Fug PM AFILTER SYSTEM0.01GR/DSCFBACT-PSD0.0100TN-0134PLANT 68/24/2001PHASE I SPENT DUST HANDLINGMH & Fug 80 T/H SAND PM APULSE-JET FABRIC FILTER BAGHOUSE0.005GR/DSCFBACT-PSD 1LB/H0.005GR/DSCF0.0050IA-0036IPSCO STEEL INC3/14/1996LIME/DOLOMITE STORAGEMH & Fug 230 T/H PM ABAGHOUSE-POLYBAGS PULSE-JETBAGHOUSE FILTER AREA=180 SQ. FT.0.0903GR/DSCFBACT-PSD 2.31LB/HCheckIA-0036IPSCO STEEL INC3/14/1996CARBON STORAGEMH & Fug 230 T/H PM ABAGHOUSE-POLYBAGS PULSE JETFILTER AREA = 318 SQ. FT0.043GR/DSCFBACT-PSD 0.23LB/H0.43GR/DSCF0.4300OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR BOFMH & Fug PM ATHREE BAGHOUSES1.8LB/H19.84T/YR0.01GR/DSCF0.010OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR EAFMH & Fug 2.5 MM t/yr PM ABAGHOUSE AND BIN VENT FILTERS1.8LB/H14.9T/YR0.01GR/DSCF0.010OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005BASIC OXYGEN FURNACES (2VESSELS), FUGITIVE EMISSIONSMH & Fug 375 t/h PM N61.01LB/HBACT-PSD 133.41T/YRNAOH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001COKE AND BREEZECRUSHING/SCREENING/CONVEYINGMH & Fug PM ABAGHOUSE WITH 0.008 GR/DSCF68.6LB/HBACT-PSD 15.02T/YRNAWI-0173WAUPACA FOUNDRYINC. - PLANT 17/11/2000LINE 1 & 2 GRINDING - P69, S29MH & Fug PM BBAGHOUSE, SHOULD DEMONSTRATECOMPLIANCE.0.73LB/HOther Case-by-CaseNATN-0066WAUPACA FOUNDRY,INC.4/28/2000SPENT DUST HANDLINGMH & Fug 0 PM APULSE-JET FABRIC FILTER BAGHOUSECONTROL SYSTEM.0.9LB/HBACT-PSDNATN-0073WAUPACA FOUNDRY,INC.4/28/2000SPENT SAND/DUST HANDLINGMH & Fug 80 T/H PM APULSE-JET FABRIC FILTER BAGHOUSECONTROL SYSTEM0.9LB/HBACT-PSDNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000OUTDOOR & INDOOR ALLOYHANDLING, 11A&BMH & Fug PM NNONE INDICATED0.0023LB/HOther Case-by-Case 0.0089T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000RAILCAR LOADING FROMPELLETIZER SILO/BAGHOUSEDUSTMH & Fug PM NNONE INDICATED0.0006LB/HOther Case-by-Case 0.0023T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000ALLOY PILES, 14MH & Fug PM NNONE INDICATED0.079LB/HOther Case-by-Case 0.054T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SHREDDER FUGITIVES, 16MH & Fug PM NNONE INDICATED0.0056LB/HOther Case-by-Case 0.014T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000VIBRATING SCREEN, 22MH & Fug PM NNONE INDICATED0.15LB/HOther Case-by-Case 0.65T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MATERIAL HANDLING, 23MH & Fug PM NNONE INDICATED0.32LB/HOther Case-by-Case 1.41T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000GRIZZLY TO STOCKMH & Fug PM NNONE INDICATED0.0004LB/HOther Case-by-Case 0.0002T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000GRIZZLY TO CONV TO CONV, S4& S5MH & Fug PM NNONE INDICATED0.0248LB/HOther Case-by-Case 0.0149T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CONV TO FEEDER, S6MH & Fug PM NNONE INDICATED0.062LB/HOther Case-by-Case 0.037T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000FEEDER TO FEEDER TO CONVTO SCREEN, S7-9MH & Fug PM NNONE INDICATED0.0037LB/HOther Case-by-Case 0.0022T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN, S10MH & Fug PM NNONE INDICATED0.065LB/HOther Case-by-Case 0.039T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CONV TO CONV, S11MH & Fug PM NNONE INDICATED0.0016LB/HOther Case-by-Case 0.001T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CONV TO CONV, S12MH & Fug PM NNONE INDICATED0.0016LB/HOther Case-by-Case 0.001T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CONV TO SCREEN, S13MH & Fug PM NNONE INDICATED0.0016LB/HOther Case-by-Case 0.001T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN TO CONV TO CONV,S15&16MH & Fug PM NNONE INDICATED0.0006LB/HOther Case-by-Case 0.0004T/YRNApage 40 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-32: Material Handling (MH) and Fugitive (Fug)- PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CONV TO CONV TO BIN TOTRUCK, S17-19MH & Fug PM NNONE INDICATED0.022LB/HOther Case-by-Case 0.013T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN TO CONV TO STOCK,S20&21MH & Fug PM NNONE INDICATED0.001LB/HOther Case-by-Case 0.0006T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN TO CONV TO STOCK,S22&23MH & Fug PM NNONE INDICATED0.0021LB/HOther Case-by-Case 0.0013T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000FEEDER TO FEEDER TO CONVTO SCREEN, S24-26MH & Fug PM NNONE INDICATED0.0581LB/HOther Case-by-Case 0.0349T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN, S27MH & Fug PM NNONE INDICATED1.02LB/HOther Case-by-Case 0.61T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN TO CONV, S28MH & Fug PM NNONE INDICATED0.0211LB/HOther Case-by-Case 0.0127T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN TO CONV, S29MH & Fug PM NNONE INDICATED0.037LB/HOther Case-by-Case 0.0222T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CONV TO CRUSHER TO CONV,S30&32MH & Fug PM NNONE INDICATED0.056LB/HOther Case-by-Case 0.0033T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CRUSHER, S31MH & Fug PM ABAGHOUSE0.068LB/HOther Case-by-Case 0.041T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CRUSHER, SBH-1MH & Fug PM NTHE BAGHOUSE IS A CONTROL DEVICEFOR THE CRUSHER, BUT THESEEMISSION LIMITS ARE PROVIDEDSPECIFICALLY FOR PM FROM THEBAGHOUSE.0.343LB/HOther Case-by-Case 0.2T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000CONV TO CONV, S33MH & Fug PM NNONE INDICATED0.037LB/HOther Case-by-Case 0.022T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000FRONT-END LOADER DROP @MIXING BLDG, S35MH & Fug PM NNONE INDICATED0.442LB/HOther Case-by-Case 1.95T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN, S14MH & Fug PM NNONE INDICATED0.028LB/HOther Case-by-Case 0.017T/YRNAIN-0079STEEL DYNAMICS, INC.7/7/1999SLAG, HANDLING ANDPROCESSINGMH & Fug 262800 T/YR PM BWATER SUPPRESSION AND MINIMIZINGDROP HEIGHTS55.4LB/HBACT-PSD 0NAIN-0080STEEL DYNAMICS, INC.7/7/1999HANDLING AND PROCESSING,SLAGMH & Fug 150 T/YR PM BWATER SUPPRESSION AND MINIMIZINGDROP HEIGHTS55LB/HBACT-PSD 0 0NASC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998EAF FLUX/ALLOY SYSTEMMH & Fug PM ABIN VENT FILTERS, VENT TO BAGHOUSE.0.5LB/HBACT-PSDNASC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998LMF FLUX/ALLOY SYSTEMMH & Fug PM ABIN VENT FILTERS0.5LB/HBACT-PSDGR/DSCFOH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001LOAD IN AND LOAD OUT OFCOKE/COAL STORAGE PILESMH & Fug PM ALOAD-IN COAL, COKE, AND COKE BREEZEW/ STACKING TUBE; LOAD-IN COALW/WATER SPRAYS/DUST SUPPRESSANT;LOAD-OUT COAL UNDER PILE GRAVITYFEED AND WATER SPRAY; LOAD-OUTCOKE W/ UNDER PILE GRAVITY FEED.4T/YRBACT-PSDNAOH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001COAL HANDLING, CONVEYING,AND TRANSFERMH & Fug 6602850 T/YR PM PRAIL CAR BOTTOM DUMPING ANDENCLOSED; BELT CONVEYORSENCLOSED; WET AND/OR CHEMICALSUPPRESSION7.95T/YRBACT-PSDNAOH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001ROADWAYS AND PARKINGMH & Fug PM PWATERING AS SUFFICIENT FREQUENCYTO ENSURE COMPLIANCE8.01T/YRBACT-PSDNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000FINES/COARSE SAND/LIGHTORGANIC MATERIAL STORAGEMH & Fug PM NNONE INDICATED0.14T/YROther Case-by-CaseNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000IN-PLANT VEHICLE TRAFFICMH & Fug PM PCHEMICAL AND WATER SPRAY34.8T/YROther Case-by-CaseNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000STOCKPILE, S37MH & Fug PM N0.43T/YROther Case-by-CaseNA*NC-0112NUCOR STEEL11/23/2004UNPAVED ROADSMH & Fug PM PPERIODIC APPLICATION OF WATER ANDCHEMICAL DUST SUPPRESSANTS TOUNPAVED ROADWAYS AND POSTEDSPEED LIMIT OF 10 MILES PER HOURBACT-PSDNANC-0113NUCOR STEEL11/23/2004UNPAVED ROADSMH & Fug PM PPERIODIC APPLICATION OF WATER ANDCHEMICAL DUST SUPPRESSANTS TOUNPAVED ROADWAYS AND POSTEDSPEED LIMIT OF 10 MILES PER HOURNAUT-0061NUCOR STEELCORPORATION8/29/1997FUGITIVES / STOCK PILES /TRANSFER POINTSMH & Fug PM PWATER SPRAYS INSTALLED AT ALLCONVEYOR TRANSFER POINTS ANDBATCHING EQUIPMENT DROP POINTS.BACT-PSDENCLOSETRANSFERPTSNAIN-0073QUALITECH STEELCORP.10/31/1996MATL. HANDLING, BAGHOUSEWASTEMH & Fug 100 T/BINS PM PCOVERED CONVEYORS, BINS WITHFILTERS LOADING INTO SEALED TRUCKSWITH ENCLOSED SHEDBACT-PSDNAMN-0064NORTHSHORE MININGCOMPANY3/22/2006TERTIARY CRUSHING (CRUSHERLINE 4 AND CRUSHER LINE 104)MH & Fug 700 LT/H Ore Particulate MattAFABRIC FILTER0.0025GR/DSCFBACT-PSD0.0025MN-0064NORTHSHORE MININGCOMPANY3/22/2006FURNACE 5 DISCHARGEMH & Fug 160 LT/H pellets Particulate MattAHIGH EFFICIENCY WET SCRUBBER0.005GR/DSCFBACT-PSD0.0050page 41 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-32: Material Handling (MH) and Fugitive (Fug)- PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleMN-0064NORTHSHORE MININGCOMPANY3/22/2006CONCENTRATOR BINS (WESTSTORAGE BINS #2, #3, #4, #5, #6,#7, #8, #9 AND #10)MH & Fug 200 LT/H concentrParticulate MattAFABRIC FILTER0.003GR/DSCFBACT-PSD0.0030VA-0240CHAPARRAL STEELCOMPANY4/24/1998UNPAVED RDS,STORAGE PILES &MATERIAL TRANSFER OP.MH & Fug 0 TSP PDUST MANAGEMENT PLAN; WORKPRACTICE (90%)0.2LB/HBACT-PSD 0 0NABACT-PSD PM gr/dscf Emission LimitsMIN0.0025gr/dscf MIN0.0100gr/dscfMAX0.430gr/dscfMAX0.020gr/dscfMEDIAN0.005gr/dscfMEDIAN0.010gr/dscfCOUNT11CASES COUNT4CASESMH & Fug RBLC PM BACT Limits SummaryOther (non-BACT)-case-by-case PM gr/dscfEmission Limitspage 42 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-33: Material Handling (MH) and Fugitive (Fug)- PM FilterableControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUT-ANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASEBASISEMISSIONLIMIT 2EmissionLimit 2 UnitSTDEmissionLimitSTDLimitUnitBACTgr/dscfLimitsNon-BACTgr/dscfLimitsIN-0119AUBURN NUGGET5/31/2005COAL CAR UNLOADINGMH & Fug 165 T/H PM FILTERABLE ABAGHOUSE0.0052GR/DSCFBACT-PSD0.0052TX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SCREEN TO CONV TO STOCK,S22&23MH & Fug PM FILTERABLE NNONE INDICATED0.0021LB/HBACT-PSD 0.0013T/YRNATX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000STOCKPILE, S37MH & Fug PM FILTERABLE NNONE INDICATED0.43T/YRBACT-PSDNAMIN0.0052gr/dscf MINNAgr/dscfMAX0.0052gr/dscfMAXNAgr/dscfMEDIAN0.0052gr/dscfMEDIANNAgr/dscfCOUNT1CASES COUNT0CASESMH & Fug RBLC PM Filterable BACT Limits SummaryOther (non-BACT)-case-by-case PMFilterable gr/dscf Emission LimitsBACT-PSD PM Filterable gr/dscf steel Emission Limitspage 43 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-34: Material Handling (MH) and Fugitive (Fug)- PbControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT Control EquipmentEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSTN-0134PLANT 68/24/2001PHASE I SPENT DUST HANDLINGMH & Fug 80 T/H SAND PBPULSE-JET FABRIC FILTER BAGHOUSE0.0003LB/HBACT-PSDTN-0066WAUPACA FOUNDRY,INC.4/28/2000SPENT DUST HANDLINGMH & Fug 0 PBPULSE-JET FABRIC FILTER BAGHOUSECONTROL SYSTEM.0.0003LB/HBACT-PSDTN-0073WAUPACA FOUNDRY,INC.4/28/2000SPENT SAND/DUST HANDLINGMH & Fug 80 T/H PBPULSE-JET FABRIC FILTER BAGHOUSECONTROL SYSTEM0.0003LB/HBACT-PSDOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005BASIC OXYGEN FURNACES (2VESSELS), FUGITIVE EMISSIONSMH & Fug 375 t/h PB 0.077LB/HBACT-PSD 0.168T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000PELLETIZER SILO, 15AMH & Fug PBBAGHOUSE0.0009LB/HOther Case-by-Case 0.0034T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000RAILCAR LOADING FROMPELLETIZER SILO/BAGHOUSEDUSTMH & Fug PBNONE INDICATEDOther Case-by-CaseBACT-PSD Pb lb/t steel Emission LimitsMINNAlb/t steel MINNAlb/t steelMAXNAlb/t steel MAXNAlb/t steelMEDIANNAlb/t steel MEDIANNAlb/t steelCOUNTNACASES COUNTNACASESMH & Fug RBLC Pb BACT Limits SummaryOther (non-BACT)-case-by-case Pb lb/t steelEmission Limitspage 44 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-35: Slag Processing Fugitve Emissions (Fug-Slag)-PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT Control EquipmentEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSKY-0095RECMIX OF PA, INC.8/6/2004RAW SLAG HANDLINGFug-Slag 280000 t/yr PM10WATERING0.78T/YRBACT-PSDKY-0095RECMIX OF PA, INC.8/6/2004RAW SLAG HANDLING, HOPPERFug-Slag PM10ENCLOSURE TUNNEL0.78T/YRBACT-PSDKY-0095RECMIX OF PA, INC.8/6/2004SLAG SKULL HANDLINGFug-Slag 4200 t/yr PM10WATERING0.78T/YRBACT-PSDKY-0095RECMIX OF PA, INC.8/6/2004SLAG SKULL SCREENINGFug-Slag PM10HIGH MOISTURE CONTENT0.78T/YRBACT-PSDOH-0276CHARTER STEEL4/14/2003SLAG PROCESSING OPERATIONFug-Slag 250 T/H PM10ENCLOSURE WHERE PRACTICLE0.79LB/HBACT-PSD 0.56T/YRAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001SLAG PROCESSINGFug-Slag 886950 T/YR PM10WET SUPPRESSION1.2LB/HBACT-PSDAR-0078NUCOR STEEL,ARKANSAS9/9/1999SLAG PROCESSINGFug-Slag PM10KEEP MATERIAL SUFFICIENTLY DAMP1.8LB/HBACT-PSD 4.1T/YRAR-0077BLUEWATER PROJECT7/22/2004SLAG/MILL SCALE PROCESSINGFug-Slag PM10WATER APPLICATION AND LIMITEDDROP HEIGHTS3.5T/YRBACT-PSDTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SLAG SKUL POT DUMP, S34BFug-Slag PM10NONE INDICATED0.065LB/HOther Case-by-Case 0.29T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MOLTEN SLAG POT DUMP, S34AFug-Slag PM10NONE INDICATED1.19LB/HOther Case-by-Case 5.3T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SLAG RAW FEED, S1Fug-Slag PM10NONE INDICATED1.63LB/HOther Case-by-Case 0.98T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SLAG ROAD EMISSIONS, S38Fug-Slag PM10NONE INDICATED10.63T/YROther Case-by-CaseBACT-PSD PM10 lb/t steel Emission LimitsMINNAlb/t steel MINNAlb/t steelMAXNAlb/t steel MAXNAlb/t steelMEDIANNAlb/t steel MEDIANNAlb/t steelCOUNTNACASES COUNTNACASESFug-Slag RBLC PM10 BACT Limits SummaryOther (non-BACT)-case-by-case PM10 lb/t steelEmission Limitspage 45 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-36: Slag Processing Fugitve Emissions (Fug-Slag)-PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENTEMISSIONLIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0021QUANEXCORPORATION -MACSTEEL DIVISION2/18/1998SLAG PROCESSINGFug-Slag 68350 T/YR, SLAG PMTHROUGHPUT LIMIT ON SLAG, WATERSPRAYS ON TRANSFERPOINTS3.8T/YRBACT-PSD 0AR-0044ARKANSAS STEELASSOCIATES1/5/2001SLAG PROCESSINGFug-Slag PMWATER APPLICATION TO CONTROLFUGITIVE EMISSIONS.5.7LB/HBACT-PSD 8.3T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SLAG ROAD EMISSIONS, S38Fug-Slag PMNONE INDICATED21.26T/YRBACT-PSDAL-0202CORUS TUSCALOOSA6/3/2003SLAG RECLAMATIONOPERATIONSFug-Slag 100 T/H PMWET SUPPRESSIONBACT-PSDTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SLAG SKUL POT DUMP, S34BFug-Slag PMNONE INDICATED0.13LB/HOther Case-by-Case 0.59T/YRTX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000SLAG RAW FEED, S1Fug-Slag PMNONE INDICATED3.25LB/HOther Case-by-Case 1.95T/YRNC-0113NUCOR STEEL11/23/2004SLAG HANDLING PROCESSFug-Slag PMSLAG PROCESS THROUGHPUT LIMITEDTO 262,800 TONS PER 12 MONTHPERIOD. DROP HEIGHTS FROMCONVEYOR DISCHARGE LIMITED TO 15FEET WITH SECONDARY PILES BYMOBILE EQUIPMENT LIMITED TO 4 FEET.2.2LB*NC-0112NUCOR STEEL11/23/2004SLAG HANDLING PROCESSFug-Slag PMSLAG PROCESS THROUGHPUT LIMITEDTO 262,800 TONS PER 12 MONTHPERIOD. DROP HEIGHTS FROMCONVEYOR DISCHARGE LIMITED TO 15FEET WITH SECONDARY PILES BYMOBILE EQUIPMENT LIMITED TO 4 FEET.2.2LB/HBACT-PSD PM lb/t steel Emission LimitsMINNAlb/t steel MINNAlb/t steelMAXNAlb/t steel MAXNAlb/t steelMEDIANNAlb/t steel MEDIANNAlb/t steelCOUNTNACASES COUNTNACASESFug-Slag RBLC PM BACT Limits SummaryOther (non-BACT)-case-by-case PM lb/t steelEmission Limitspage 46 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-37: Cooling Towers (CT)Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAMEPERMITDATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT Control EquipmentEMISSION LIMIT1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSIN-0100ROCKPORT WORKS2/13/1997COOLING TOWERS (2), NONCONTACTCT PMDRIFT ELIMINATORS0.005% DRIFTBACT-PSDIN-0119AUBURN NUGGET5/31/2005COOLING TOWERCT 23450 GAL/M PM0.005% OF THROUGHPUTBACT-PSD*NC-0112NUCOR STEEL11/23/2004COOLING TOWERSCT PMMIST ELIMINATORS WITH A 0.008PERCENT DRIFT LOSS0.008PERCENTBACT-PSDWI-0094CHARTER STEELDIVISION2/26/1997COOLING TOWER, P06CT PMUSE OF A 3-PASS DRIFT ELIMINATOR TOREDUCE DRIFT OF WATER DROPLETSFROM THE COOLING TOWER AND TOKEEP THE AMOUNTS TOTAL DISSOLVEDSOLIDS (TDS) IN THE COOLING WATERTO LESS THAN 1.2% BY WEIGHT.1.3LB/HBACT-PSDAR-0078NUCOR STEEL,ARKANSAS9/9/1999COOLING TOWERCT PM103.6T/YRBACT-PSDAR-0077BLUEWATER PROJECT7/22/2004COOLING TOWERSCT PM10DRIFT/MIST ELIMINATORS6LB/HBACT-PSDIN-0119AUBURN NUGGET5/31/2005COOLING TOWERCT 23450 GAL/M VE20% OPACITYBACT-PSDIN-0108NUCOR STEEL11/21/2003COOLING TOWERSCT 192352 GAL/MIN VEMIST ELIMINATORS20% OPACITYBACT-PSD 20% OPACITYIN-0090NUCOR STEEL1/19/2001COOLING TOWER SYSTEMCT 12000 GAL/MIN PM10LIMIT IS DRIFT ELIMINATOR. NONUMERICAL LIMITBACT-PSDWI-0094CHARTER STEELDIVISION2/26/1997COOLING TOWER, P06CT VOCMAY NOT USE MORE THAN 157 POUNDSOF VOC PER MONTH, AS DETERMINED BYAN AVERAGE OVER ANY 12CONSECUTIVE MONTHS CONTAINED INCHEMICAL ADDITIVES CONSUMED IN THECOOLING TOWER. SYNTHETIC MINORLIMIT0.21LB/HOther Case-by-CaseNC-0113NUCOR STEEL11/23/2004COOLING TOWERSCT PMMIST ELIMINATORS WITH A 0.008PERCENT DRIFT LOSSBACT-PSD PM %drift Emission LimitsMIN 0.005 %drift MIN 0.008 %driftMAX 0.008 %drift MAX 0.008 %driftMEDIAN 0.007 %drift MEDIAN 0.008 %driftCOUNT3CASES COUNT1CASESCT RBLC PM BACT Limits SummaryOther (non-BACT)-case-by-case PM %drift Emission Limitspage 47 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-38A: Small Gas Fired Boilers and Heaters- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for StatiRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsIN-010811/21/2003 BOILER, NATURAL GAS, (2)NATURALGAS 34 MMBTU/H PM10COMPLIANCE IS BYUSING NATURAL GAS 0.0019 LB/MMBTUBACTPSD 0.0019 LB/MMBTU0.0019AZ-004712/1/2004 AUXILIARY BOILERNATURALGAS 38 MMBTU/H PM10 0.0033 LB/MMBTUBACTPSD 0.0033 LB/MMBTU0.0033OR-00403/12/2003 BOILER, AUXILIARY, NATURAL GASNATURALGAS 50000 LB/H PM10 0.0042 LB/MMBTUBACTPSD 0.0042 LB/MMBTU0.0042AL-017910/3/2001 30 MMBTU/HR AUXILIARY BOILERNATURALGAS 30 MMBTU/H PM10NATURAL GAS ASEXCLUSIVE FUEL 0.005 LB/MMBTUBACTPSD 0.2 LB/H 0.005 LB/MMBTU0.005TN-01534/3/2002 CCR STABILIZATION REBOILERNATURALGAS 54 MMBTU/H PM10 0.005 LB/MMBTUBACTPSD 0.005 LB/MMBTU0.005OH-02553/29/2001 BOILER, NATURAL GASNATURALGAS 85.2 MMBTU/H PM10 0.43 LB/HBACTPSD 1.87 T/YR 0.005 LB/MMBTU0.005OH-025111/29/2001 BOILER, NATURAL GASNATURALGAS 91.2 MMBTU/H PM10 0.46 LB/HBACTPSD 2.06 T/YR 0.005 LB/MMBTU0.005OH-02638/9/2001 AUXILIARY BOILERNATURALGAS 80 MMBTU/H PM10 0.41 LB/HBACTPSD 1.8 T/YR 0.0051 LB / MMBTU0.0051OK-00725/6/2002 AUXILIARY BOILERNATURALGAS 93 MMBUT/H PM10USE OF NATURALGAS/LOW ASH FUELAND EFFICIENTCOMBUSTION 0.0053 LB/MMBTUBACTPSD 0.0053 LB/MMBTU0.0053VA-02713/24/2003 BOILER NO. 1NATURALGAS 43.2 MMBTU/H PM10GOOD COMBUSTIONPRACTICES 0.32 LB/H N/A 0.007 LB/MMBTUVA-02619/6/2002 AUXILIARY BOILERNATURALGAS 80 MMBTU/H PM10GOOD COMBUSTIONPRACTICES. 0.58 LB/HBACTPSD 0.87 T/YR 0.007 LB/MMBTU0.007VA-025511/18/2002 BOILER, AUXILIARYNATURALGAS 99 MMBTU/H PM10CLEAN FUEL AND GOODCOMBUSTIONPRACTICES. 0.7 LB/HOtherCase-byCase 3.7 T/YR 0.007 LB/MMBTUOK-00465/17/2001 AUXILIARY BOILERNATURALGAS 20 MMBTU/H PM10 USE OF LOW ASH FUEL 0.0074 LB/MMBTUBACTPSD 0.0074 LB/MMBTU0.0074OK-005110/1/1999 AUXILIARY BOILERNATURALGAS PM10USE OF LOW ASH FUELAND EFFICIENTCOMBUSTION 0.0074 LB/MMBTUBACTPSD 0.0074 LB/MMBTU0.0074IN-00876/6/2001 AUXILARY BOILER, NATURAL GAS (2)NATURALGAS 46 MMBTU/H PM10GOOD COMBUSTION.LB/H LIMIT IS FOR EACHBOILER. 0.0075 LB/MMBTUBACTPSD 0.35 LB/H 0.0075 LB/MMBTU0.0075AR-00866/11/2004 VTD BOILERNATURALGAS 50 MMBTU/H PM10GOOD COMBUSTIONPRACTICE 0.4 LB/HBACTPSD 1.7 T/YR 0.0075 LB/MMBTU0.0075AL-01913/23/2004 BOILERS, NATURAL GAS, (3)NATURALGAS 50 MMBTU/H PM10 CLEAN FUEL 0.38 LB/HBACTPSD 0.0075 LB/MMBTU 0.0075 LB/MMBTU0.0075IA-006212/20/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H PM10 LOW ASH FUEL, NG 0.0075 LB/MMBTUOtherCase-byCase 0.0075 LB/MMBTUNC-00941/9/2002 BOILER, AUXILIARY, NATURAL GASNATURALGAS 83 MMBTU/H PM10GOOD COMBUSTIONAND DESIGN 0.62 LB/HBACTPSD 0.0075 LB/MMBTU0.0075TN-01534/3/2002 BOILER, NO. 9NATURALGAS 95 MMBTU/H PM10 0.0075 LB/MMBTUBACTPSD 0.0075 LB/MMBTU0.0075OK-00562/12/2002 AUXILIARY BOILERSNATURALGAS 0 PM10LOW ASH FUEL(NATURAL GAS) 0.0076 LB/MMBTUBACTPSD 0.0076 LB/MMBTU0.0076AR-00777/22/2004 BOILERSNATURALGAS 22 MMBTU/H PM10NATURAL GASCOMBUSTION ONLY 0.0076 LB/MMBTUBACTPSD 0.0076 LB/MMBTU0.0076OK-00745/1/2001 AUXILIARY BOILERNATURALGAS 27.5 MMBTU/H PM10GOOD COMBUSTIONPRACTICES ANDDESIGN 0.0076 LB/MMBTUBACTPSD 0.0076 LB/MMBTU0.0076AL-019210/18/2002 BOILERS, NATURAL GAS, (3)NATURALGAS 30 MMBTU/H PM10CLEAN FUEL, GOODCOMBUSTION 0.228 LB/HBACTPSD 0.0076 LB/MMBTU 0.0076 LB/MMBTU0.0076IN-010811/21/2003 BOILER, NATURAL GAS, (2)NATURALGAS 34 MMBTU/H PM10COMPLIANCE BY USINGNATURAL GAS 0.0076 LB/MMBTUBACTPSD 0.0076 LB/MMBTU0.0076OK-00448/16/2001 AUXILIARY BOILERS, (2)NATURALGAS 48 MMBTU/H PM10USE OF LOW ASH FUELAND EFFICIENTCOMBUSTION 0.72 LB/HBACTPSD 3.13 T/YR 0.0076 LB/MMBTU0.0076IA-00584/10/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H PM10 0.0076 LB/MMBTUBACTPSD 2.27 T/YR 0.0076 LB/MMBTU0.0076page 48 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-38A: Small Gas Fired Boilers and Heaters- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for StatiRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsWI-022710/13/2004 NATURAL GAS FIRED AUXILLIARY BOILERNATURALGAS 97.1 MMBTU/H PM10NATURAL GAS FUEL,GOOD COMBUSTIONPRACTICES 0.74 LB/HBACTPSD 0.0076 LB/MMBTU0.0076OH-02489/24/2002 BOILERNATURALGAS 99 MMBTU/H PM10 0.76 LB/HBACTPSD 0.0076 LB/MMBTU 0.0076 LB/MMBTU0.0076OH-026510/16/2001 BOILER, NATURAL GASNATURALGAS 49 MMBTU/H PM10 0.38 LB/HBACTPSD 0.15 T/YR 0.0077 LB/MMBTU0.0077TX-03641/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H PM10 NONE INDICATED 0.02 LB/HOtherCase-byCase 0.08 T/YR 0.008 LB/MMBTUTX-035412/19/2002 (2) STEAM BOILERS, X-426A AND X-426BNATURALGAS 15.8 MMBTU/H PM10 NONE INDICATED 0.12 LB/HOtherCase-byCase 0.53 T/YR 0.008 LB/MMBTUIN-00865/9/2001 AUXILARY BOILER, NATURAL GAS (2)NATURALGAS 35 MMBTU/H PM10GOOD COMBUSTION.LB/H LIMIT IS FOR EACHBOILER. 0.008 LB/MMBTUBACTPSD 0.28 LB/H 0.008 LB/MMBTU0.008TX-037811/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H PM10 NONE INDICATED 0.48 LB/H N/A 2.11 T/YR 0.008 LB/MMBTUTX-040811/22/2002 AUXILIARY BOILER, (2)NATURALGAS 6 MMBTU/H PM10 0.05 LB/HBACTPSD 0.2 T/YR 0.0083 LB/MMBTU0.0083AR-00762/17/2004 BOILER, HOT WATER, (2) SN-PBCDF-05, -06NATURALGAS 0.01 MMDSCF/H PM10 NATURAL GAS ONLY. 0.1 LB/HBACTPSD 0.0085 LB/MMBTU0.0085OK-007110/25/2001 AUXILIARY BOILERNATURALGAS 22 MMBTU/H PM10USE OF LOW ASHFUELS 0.009 LB/MMBTUBACTPSD 0.009 LB/MMBTU0.009NM-00446/27/2002 AUXILIARY BOILERS (AUX-1 AND AUX-2)NATURALGAS 33 MMBTU/H PM10NATURAL GAS ONLY,GOOD COMBUSTIONPRACTICE 0.3 LB/HBACTPSD 0.009 LB/MMBTU0.009NV-00396/1/2001 AUXILIARY BOILERSNATURALGAS 44.1 MMBTU/H PM10USE OF PIPELINEQUALITY NATURAL GASAND GOODCOMBUSTION CONTROL 0.4 LB/HBACTPSD 0.009 LB/MMBTU0.009CO-00415/6/1999 BOILER NO.2, TEST MINE HOT WATER (1)NATURALGAS 51.08 MMBTU PM10 COMBUSTION CONTROL 0.009 LB/MMBTUBACTPSD 0.02 T/YR 0.009 LB/MMBTU0.009IA-00486/1/1998 BOILER, BACKUP 77 MMBTU/H PM10 0.7 LB/HBACTPSD 0.009 LB/MMBTU0.009OK-004310/22/2001 AUXILIARY BOILERNATURALGAS 30 MMBTU/H PM10USE OF LOW ASH FUEL& EFFICIENTCOMBUSTION 0.01 LB/MMBTUBACTPSD 0.01 LB/MMBTU0.01OH-025212/28/2004 BOILERS (2)NATURALGAS 30.6 MMBTU/H PM10 0.31 LB/HBACTPSD 0.46T/ROLLING12-MONTHS 0.01 LB/MMBTU0.01OH-02548/14/2003 BOILERNATURALGAS 30.6 MMBTU/H PM10 0.31 LB/HBACTPSD 0.64T/ROLLING12-MONTHS 0.01 LB/MMBTU0.01OK-00903/21/2003 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H PM10USE OF LOW ASH FUELAND EFFICIENTCOMBUSTION 0.01 LB/MMBTUBACTPSD 0.01 LB/MMBTU0.01OK-00706/13/2002 AUXILIARY BOILERNATURALGAS 33 MMBTU/H PM10LOW ASH FUEL ANDEFFICIENT COMBUSTION 0.01 LB/MMBTUBACTPSD 0.01 LB/MMBTU0.01AR-00514/1/2002 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H PM10GOOD OPERATINGPRACTICE 0.01 LB/MMBTUBACTPSD 0.01 LB/MMBTU0.01AR-004012/29/2000 BOILERS, AUXILIARY 2NATURALGAS 44.1 MMBTU/H PM10CLEAN FUELS, PROPERCOMBUSTION. LB/HRLIMIT FOR EACHBOILER. 0.01 LB/MMBTUBACTPSD 0.5 LB/H 0.01 LB/MMBTU0.01NM-004212/29/2000 AUX-1 AUXILARY BOILERNATURALGAS 44.1 MMBTU/H PM10NATURAL GAS ONLY,PRE-FILTERING - LIMITINCLUDES BOTH FRONTEND AND BACK END OFSAMPLING TRAIN 0.4 LB/HBACTPSD 0.01 LB/MM BTU0.01page 49 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-38A: Small Gas Fired Boilers and Heaters- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for StatiRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsMN-005412/4/2003 BOILER, COMMERCIALNATURALGAS 70 MMBTU/H PM10 CLEAN FUELS 0.008 LB/MMBTUBACTPSD 0.01 LB/MMBTU0.01AL-01681/12/2001 BOILERNATURALGAS 83 MMBTU/H PM10 EFFICIENT COMBUSTION 0.01 LB/MMBTUBACTPSD 0.63 LB/H 0.01 LB/MMBTU0.01*LA-01122/13/1998 BOILER NO. 1NATURALGAS 95 MMBTU/H PM10GOOD DESIGN, PROPEROPERATING PRACTICES,AND USE CLEANNATURAL GAS AS FUEL. 0.95 LB/HBACTPSD 4.16 T/YR 0.01 LB/MMBTU0.01AR-00762/17/2004 BOILER, PROCESS STEAM, (2) SN-PBCDF-03, -04NATURALGAS 0.03 MMDSCF/H PM10 NATURAL GAS ONLY. 0.3 LB/HBACTPSD 0.0106 LB/MMBTU0.0106CA-07369/19/1996 300 HP BOILER USED AS A BACKUPPUCQUALITYNAT GAS 10 MMBTU/HR PM10 NO CONTROL 0.012 LB/MMBTU LAER 2.9 LB/DAY 0.012 LB/MMBTUAR-00708/23/2002 AUXILIARY BOILERNATURALGAS 33 MMBTU/H PM10GOOD COMBUSTIONPRACTICE 0.012 LB/MMBTUBACTPSD 0.012 LB/MMBTU0.012CA-079012/30/1996 NEBRASKA BOILER, MODEL NS-B-40NATURALGAS 31.2 MMBTU/HR PM10 NO CONTROL 0.0137 LB/MMBTU LAER 0.014 LB/MMBTU 0.0137 LB/MMBTUNJ-00422/5/1999 BOILER 1 (NATURAL GAS)NATURALGAS 84.4 MMBTU/H PM10 1.2 LB/HBACTPSD 0.014 LB/MMBTU0.014*AZ-00499/4/2003 AUXILIARY BOILER FOR GE TURBINENATURALGAS 41 MMBTU/H PM10 0.015 LB/MMBTUBACTPSD 0.015 LB/MMBTU0.015*AZ-00499/4/2003 AUXILIARY BOILER FOR SIEMENS TURBINESNATURALGAS 55.34 MMBTU/H PM10 0.015 LB/MMBTUBACTPSD 0.015 LB/MMBTU0.015OH-02582/15/2001 BOILERS (4)NATURALGAS 20.9 MMBTU/H PM10 0.04 LB/H N/A 0.18 T/YR 0.02 LB/MMBTUIN-011010/5/2001 BOILER, AUXILIARY, NATURAL GASNATURALGAS 35 MMBTU/H PM10CLEAN FUEL, GOODCOMBUSTIONPRACTICES 0.02 LB/MMBTUOtherCase-byCase 0.7 LB/H 0.02 LB/MMBTUAL-01692/5/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H PM10GOOD COMBUSTIONPRACTICES 0.02 LB/MMBTUBACTPSD 0.8 LB/H 0.02 LB/MMBTU0.02OH-025712/27/2001 AUXILIARY BOILERNATURALGAS 76 MMBTU/H PM10 1.52 LB/HBACTPSD 2.28 T/YR 0.02 LB/MMBTU0.02LA-01741/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H PM10 FIRED BY NATURAL GAS 3.33 LB/HBACTPSD 2.2 T/YR 0.05 LB/MMBTU0.05AR-00762/17/2004 BOILER, LABORATORY SN-PBCDF-16NATURALGAS 1.4 mmbtu/h PM10 NATURAL GAS ONLY. 0.1 LB/HBACTPSD 0.071 LB/MMBTU0.071PA-021012/14/2001 BOILER, (2)NATURALGAS 33.5 MMBTU/H PM10 0.4 LB/MMBTU N/A 0.4 LB/MMBTUIA-00545/20/1997 HIGH PRESSURE BOILER #1NATURALGAS 0.3 MMBTU/H PM10 0.18 LB/HBACTPSD 0.8 T/YR 0.6 LB/MMBTU0.6IA-00545/20/1997 BOILER #2 B2NATURALGAS 2.3 MMBTU/H PM10LOW NOX BURNER,FLUE GAS RECIRC. 1.39 LB/HBACTPSD 6.07 T/YR 0.6 LB/MMBTU0.6IA-00545/20/1997 BOILER #1NATURALGAS 2.3 MMBTU/H PM10LOW NOX BURNER ,FLUE GASRECIRCULATION 1.39 LB/HBACTPSD 6.07 T/YR 0.6 LB/MMBTU0.6IA-00545/20/1997 BOILER #3 B3NATURALGAS 2.3 MMBTU/HR PM10LOW NOX BURNER,FLUE GASRECIRCULATION 1.39 LB/HBACTPSD 6.07 T/YR 0.6 LB/MMBTU0.6*AK-00628/19/2005 NATCO TEG REBOILERNATURALGAS 1.34 MMBtu/hr PM10GOOD OPERATIONPRACTICESBACTPSD LB/MMBTUTX-038912/31/2002 BACK-UP BOILERNATURALGAS 13.4 MMBUT/H PM10 0.1 LB/HOtherCase-byCase 0.44 T/YROK-00411/19/2000 AUXILIARY BOILERNATURALGAS 22 MMBTU/H PM10 CLEAN FUEL 0.1 T/YRBACTPSDOH-02764/14/2003 BOILER FOR VACUUM OXYGEN DEGASSER VESSELNATURALGAS 25 MMBTU/H PM10 0.19 LB/HBACTPSD 0.83 T/YRVA-024312/1/2002 BOILER, NAT GAS & OILNATURALGAS 26.5 MMBTU/H PM10NO CONTROLS LISTED.EMISSION LIMITS IN T/YRONLY 0.9 T/YROtherCase-byCasepage 50 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-38A: Small Gas Fired Boilers and Heaters- PM10Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for StatiRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimits*WA-029210/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H PM10 7 LB/DOtherCase-byCaseAL-018110/23/2001 31.4 MMBTU/HR NATURAL GAS FIRED BOILERNATURALGAS 31.4 MMBTU/H PM10NATURAL GAS ISEXCLUSIVE FUEL. 0.009 LB/MMBTUBACTPSD 0.31 LB/HAL-018012/11/2001 35 MMBTU/HR NAT. GAS FIRED AUXILIARY BOILERNATURALGAS 35 MMBTU/H PM10NATURAL GAS ASEXCLUSIVE FUEL. 0.009 LB/MMBTUBACTPSD 0.31 LB/HAL-01857/12/2002 TWO (2) 40 MMBTU/H AUXILIARY BOILERSNATURALGAS 40 MMBTU/H PM10 NATURAL GAS ONLY 0.0075 LB/MMBTUBACTPSD 0.3 LB/HMD-00339/27/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H PM10EXCLUSIVE USE OFNATURAL GAS,ADVANCED DRY LOWNOX BURNERS; GOODCOMBUSTIONCONTROLS ANNUALFUEL USE LIMITBACTPSDVA-02713/24/2003 BOILER NO. 3NAT GASOR DISOIL 43.2 MMBTU PM10GOOD COMBUSTIONPRACTICES 2.75 T/YR N/AWI-02268/27/2004 NATURAL GAS FIRED BOILERNATURALGAS 46.2 MMBTU/H PM10 NATURAL GAS 0.8 LB/H N/AIA-00607/23/2002 AUXILIARY BOILER (48.5 MMBTU/H)NATUALGAS 48.69MILLIONCF/YR PM10 GCP 0.007 LB/MMBTUBACTPSDNV-00375/14/2004 AUXILIARY BOILERNATURALGAS 60 MMBTU/H PM10RESTRICTION OFOPERATION TONATURAL GAS 0.5 LB/H LAEROK-00548/21/2001 BOILERSNATURALGAS 62.77 MMBTU/H PM10NATURAL GAS FUEL,GOOD COMBUSTIONPRACTICE 0.63 LB/HBACTPSD 2.76 T/YRIN-009712/3/2001 BOILERS 1 & 2NATURALGAS 75 MMBTU/H PM10 794.13LB/MMCFNGOtherCase-byCaseTX-036311/13/2000 BOILER NO. 2 NAT GAS PM10 NONE INDICATED 0.12 LB/HOtherCase-byCase 0.27 T/YRTX-036311/13/2000 BOILER NO 3 NAT GAS PM10 NONE INDICATED 0.08 LB/HOtherCase-byCase 0.36 T/YRTX-030010/13/1998 GLYCOL REBOILER NAT GAS PM10FUEL IS LIMITED TOPIPELINE-QUALITY,SWEET NATURAL GASCONTAINING NO MORETHAN 5 GR S/100 DSCF 0.02 LB/HOtherCase-byCase 0.09 T/YRBACT-PSD PM10 lb/MMBtu Emission LimitsMIN0.0019lb/MMBtu MIN0.007lb/MMBtuMAX0.6lb/MMBtu MAX0.4lb/MMBtuMEDIAN0.0085lb/MMBtu MEDIAN0.008lb/MMBtuCOUNT59CASES COUNT11CASESRBLC PM10 BACT Limits SummaryOther (non-BACT) PM10 lb/MMBtu EmissionLimitspage 51 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-38B: Small Gas Fired Boilers and Heaters- PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitGA-00634/3/1996 BOILER, NATURAL GASNATURALGAS 60 MMBTU/H PMCOMPLETECOMBUSTION 0.005 LB/MMBTUBACTPSD 0 0.005 LB/MMBTUNJ-00463/7/1996BOILERS 4&5, COMBUSTION CONTROLS, OXYGENTRIM, ETCNATURALGAS 94 MMBTU/HTotalSuspendedParticulates N/A 0.49 LB/HBACTPSD 0.0052 LB/MMBTUIA-00607/23/2002 AUXILIARY BOILER (48.5 MMBTU/H)NATUALGAS 48.69MILLIONCF/YR PM GCP 0.007 LB/MMBTUOtherCase-byCase 0.007 LB/MMBTUTX-02744/3/2000 AUXILIARY BOILERNATURALGAS 54.01 MMBTU/H PMFUEL SPECIFICATIONSOF NO MORE THAN 2.5GRAINS TOTAL SULFURPER 100 DRY STANDARDCUBIC FEET ON ASHORT-TERM BASISAND 0.5 GRAIN TOTALSULFUR PER 100 DSCFON A ROLLING 12- 0.4 LB/H N/A 0.04 T/YR 0.007 LB/MMBTUIN-009712/3/2001 BOILERS 1 & 2NATURALGAS 75 MMBTU/H PM 7.6LB/MMSCFNATURALGASOtherCase-byCase 0.007 LB/MMBTUVA-02619/6/2002 AUXILIARY BOILERNATURALGAS 80 MMBTU/H PMGOOD COMBUSTIONPRACTICES. 0.58 LB/HBACTPSD 0.87 T/YR 0.007 LB/MMBTUMA-00299/29/1999 BOILER, AUXILIARYNATURALGAS 96 MMBTU/H PM NATURAL GAS FUEL 0.7 LB/HBACTPSD 0.007 LB/MMBTUCA-091911/23/1999 BOILER, FIRE TUBENATURALGAS 31.5 MMBTU/H PMNOBACTLIMITSWEREAPPLIED TO PM.DEFAULT EMISSIONFACTORS ARE THEBASIS OF THE PM LEVELLISTED HERE. 0.0071 LB/MMBTUOtherCase-byCase 0.0071 LB/MMBTUAK-00456/6/2000 DRILLING BOILER NO. 1NATURALGAS 100 HP PM NONE INDICATED 0.05 GR/DSCF N/A 0.034 LB/H 0.0071 LB/MMBTUAK-00382/5/1999 GLYCOL REBOILER, UNIT 13NATURALGAS 5 MMBTU/H PM 0.05 GR/DSCFOtherCase-byCase 0.0072 LB/MMBTUAK-00382/5/1999 RIG BOILER (NATURAL GAS), UNIT 206, 207NATURALGAS 6.3 MMBTU/H PMGOOD OPERATIONSPRACTICES 0.05 GR/DSCFOtherCase-byCase 0.0072 LB/MMBTUWI-02071/21/2004 BOILER, S52/B52, 11 MMBTU/HNATURALGAS 11 MMBTU/H PMNATURAL GAS /PROPANE; GOODCOMBUSTION CONTROL 0.0075 LB/MMBTUBACTPSD 0.08 LB/H 0.0075 LB/MMBTUIN-009512/7/2001 AUXILLIARY BOILERNATURALGAS 21 MMBTU/H PMNATURAL GAS AS SOLEFUEL 0.0075 LB/MMBTUBACTPSD 0.0075 LB/MMBTUWI-02071/21/2004 BOILER, S53 / B53, 34 MMBTU/HNATURALGAS 34 MMBTU/H PMNATURAL GAS /PROPANE; GOODCOMBUSTION CONTROL 0.0075 LB/MMBTUBACTPSD 0.26 LB/H 0.0075 LB/MMBTUWI-02071/21/2004 BOILER, S50/B50, 60 MMBTU/HNATURALGAS 60 MMBTU/H PMNATURAL GAS/PROPANE; GOODCOMBUSTION CONTROL 0.0075 LB/MMBTUBACTPSD 0.45 LB/H 0.0075 LB/MMBTUIA-006212/20/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H PM LOW ASH FUEL, NG 0.0075 LB/MMBTUOtherCase-byCase 0.0075 LB/MMBTUpage 52 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-38B: Small Gas Fired Boilers and Heaters- PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitWI-02071/21/2004 BOILER, S51/B51, 80 MMBTU/HNATURALGAS 80 MMBTU/H PMNATURAL GAS, GOODCOMBUSTION CONTROL 0.0075 LB/MMBTUBACTPSD 0.6 LB/H 0.0075 LB/MMBTUAL-01406/19/1997 BOILER, NATURAL GAS FIRED, 2NATURALGAS 11.7 MMBTU/H PM CLEAN FUEL 0.0076 LB/MMBTUBACTPSD 0.0076 LB/MMBTUAL-01396/19/1997 BOILER, NATURAL GAS FIRED, 2NATURALGAS 13.4 MMBTU/H PM CLEAN FUEL. 0.0076 LB/MMBTUBACTPSD 0.0076 LB/MMBTUMN-00537/15/2004 BOILER, NATURAL GAS (1)NATURALGAS 40 MMBTU/H PMCLEAN FUEL AND GOODCOMBUSTION. 0.008 LB/MMBTUBACTPSD 0.008 LB/MMBTUWV-00216/9/2004 BOILER, NATURAL GAS, 39.00 MMBTUNATURALGAS 365 MMSCF/YR PM 0.32 PPHBACTPSD 1.39 T/YR 0.008 LB/MMBTUGA-00983/24/2003 AUXILIARY BOILERNATURALGAS 83 MMBTU/H PM 0.0084 LB/MMBTUOtherCase-byCase 0.0084 LB/MMBTUIA-00486/1/1998 BOILER, BACKUP 77 MMBTU/H PM 0.7 LB/HBACTPSD 3 LB/MMCF 0.009 LB/MMBTUMA-00275/7/2000 AUXILIARY BOILERNATURALGAS 26.6 MMBTU/H PM NATURAL GAS FUEL 0.3 LB/HBACTPSD 0.01 LB/MMBTUGA-010110/23/2002 BOILER, AUXILIARYNATURALGAS 31.4 MMBTU/H PMGOOD COMBUSTIONPRACTICE, CLEAN FUEL 0.01 LB/MMBTUBACTPSD 0.01 LB/MMBTUMN-005412/4/2003 BOILER, COMMERCIALNATURALGAS 70 MMBTU/H PM CLEAN FUELS 0.008 LB/MMBTUBACTPSD 0.01 LB/MMBTUVA-02713/24/2003 BOILER NO. 1NATURALGAS 43.2 MMBTU/H PMGOOD COMBUSTIONPRACTICES 0.62 LB/H N/A 0.014 LB/MMBTUIN-00681/19/1996 BOILERS, NATURAL GASNATURALGAS 93.9 MMBTU/H PM 1.29 LB/HBACTPSD 0 0.014 LB/MMBTUWI-01818/2/2000 BOILERNATURALGAS 10 MMBTU/H PMBACT FOR PM ISDETERMINED TO BEGOOD COMBUSTIONCONTROL & THE USE OFNAT. GAS TO FUEL THEBOILER 0.016 LB/MMBTUBACTPSD 0.016 LB/MMBTULA-01741/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H PM FIRED BY NATURAL GAS 3.33 LB/HBACTPSD 2.2 T/YR 0.05 LB/MMBTUND-00187/9/1998 BOILER, NEBRASKA, NAT GASNATURALGAS 28 MMBTU/H PM 2.4 LB/HBACTPSD 0.1LB/MMBTU 0.1 LB/MMBTUKY-00685/29/1997 BOILER (NATURAL GAS)NATURALGAS 96 MMBTU/H PM FABRIC FILTER 0.1 LB/MMBTUBACTPSD 0.1 LB/MMBTUIN-00698/9/1996 BOILERS, NATURAL GAS FIRED (6)NATURALGAS 58 MMBTU/H PMLOW NOX BURNERS &FUEL SPEC: USE OFNATURAL GAS AS FUEL. 0.2 LB/MMBTUBACTPSD 0 0.2 LB/MMBTUKY-00877/12/2002 BOILER, NATURAL GAS, #4NATURALGAS 33.5 MMBTU/H PM 0.308 LB/MMBTUBACTPSD 0.308 LB/MMBTUIA-00545/20/1997 HIGH PRESSURE BOILER #1NATURALGAS 0.3 MMBTU/HTotalSuspendedParticulates 0.18 LB/HBACTPSD 0.8 T/YR 0.6 LB/MMBTUpage 53 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-38B: Small Gas Fired Boilers and Heaters- PMControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitIA-00545/20/1997 BOILER #2 B2NATURALGAS 2.3 MMBTU/HTotalSuspendedParticulatesLOW NOX BURNER,FLUE GAS RECIRC 1.39 LB/HBACTPSD 6.07 T/YR 0.6 LB/MMBTUIA-00545/20/1997 BOILER #1NATURALGAS 2.3 MMBTU/HTotalSuspendedParticulatesLOW NOX BURNER,FLUE GASRECIRCULATION 1.39 LB/HBACTPSD 6.07 T/YR 0.6 LB/MMBTUIA-00545/20/1997 BOILER #3 B3NATURALGAS 2.3 MMBTU/HRTotalSuspendedParticulatesLOW NOX BURNER,FLUE GAS RECIRC. 1.39 LB/HBACTPSD 6.07 T/YR 0.6 LB/MMBTUWY-00342/6/1998 BOILER, NATURAL GASNATURALGAS 100 MMBTU/H PMMINIMAL PARTICULATEEMISSIONS AND LOWEMITTING FUEL 5 LB/MMBTUBACTPSD 0 5 LB/MMBTUAL-01781/5/2001 TWO (2) 11.7 MMBTU/H BOILERSNATURALGAS 11.7 MMBTU/H PM 0.0076 LB/MMBTUBACTPSD 0.11 LB/HAL-01781/5/2001 TWO (2) 13.4 MMBTU/H BOILERSNATURALGAS 13.4 MMBTU/H PM 0.0076 LB/MMBTUBACTPSD 0.16 LB/HVA-024312/1/2002 BOILER, NAT GAS & OILNATURALGAS 26.5 MMBTU/H PMEMISSION LIMITS INT/YR ONLY 1.1 T/YROtherCase-byCaseVA-02713/24/2003 BOILER NO. 3NATGASOR DISOIL 43.2 MMBTU PMGOOD COMBUSTIONPRACTICES 3.37 T/YR N/AAK-00533/21/2000 LISTER BOILER, DR11 100 HP PM NONE INDICATED 0.05 GR/DSCF N/AAK-00533/21/2000 LISTER BOILER, DR12 100 HP PM NONE INDICATED 0.05 GR/DSCF N/ABACT-PSD PM lb/MMBtu Emission LimitsMIN0.005lb/MMBtu MIN0.007lb/MMBtuMAX5lb/MMBtu MAX0.014lb/MMBtuMEDIAN0.010lb/MMBtu MEDIAN0.00715lb/MMBtuCOUNT29CASES COUNT10CASESRBLC PM BACT Limits SummaryOther (non-BACT) PM lb/MMBtuEmission Limitspage 54 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-39: Small Gas Fired Boilers and Heaters- SO2Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitAZ-00329/1/1996 BOILERS, GENERATORS 0 SO2 FUEL SPEC: 0.055 WT% S OIL 5 TPYOtherCase-byCase 0 0TX-035412/19/2002 (2) STEAM BOILERS, X-426A AND X-426BNATURALGAS 15.8 MMBTU/H SO2FUEL GAS SHALL BE SWEETNATURAL GAS CONTAINING NOMORE THAN 5 GR S/100 DSCF. 0.01 LB/HOtherCase-byCase 0.04 T/YR 0.0006 LB/MMBTUIN-009512/7/2001 AUXILLIARY BOILERNATURALGAS 21 MMBTU/H SO2LOW SULFUR CONTENT NATURALGAS 0.0006 LB/MMBTUBACTPSD 0.0006 LB/MMBTUAR-00777/22/2004 BOILERSNATURALGAS 22 MMBTU/H SO2 NATURAL GAS COMBUSTION ONLY 0.0006 LB/MMBTUBACTPSD 0.0006 LB/MMBTUIN-010811/21/2003 BOILER, NATURAL GAS, (2)NATURALGAS 34 MMBTU/H SO2COMPLIANCE BY USING NATURALGAS 0.0006 LB/MMBTUBACTPSD 0.0006 LB/MMBTUIN-00865/9/2001 AUXILARY BOILER, NATURAL GAS (2)NATURALGAS 35 MMBTU/H SO2LOW SULFUR NATURAL GAS ONLY(LESS THAN 0.8% BY WEIGHT).LB/H LIMIT IS FOR EACH BOILER. 0.0006 LB/MMBTUBACTPSD 0.021 LB/H 0.0006 LB/MMBTUIN-00876/6/2001 AUXILARY BOILER, NATURAL GAS (2)NATURALGAS 46 MMBTU/H SO2NATURAL GAS AS FUEL. LIMIT ISFOR EACH BOILER. 0.0006 LB/MMBTUBACTPSD 0.028 LB/H 0.0006 LB/MMBTUAR-00866/11/2004 VTD BOILERNATURALGAS 50 MMBTU/H SO2GOOD COMBUSTION PRACTICE,NATURAL GAS COMBUSTION 0.1 LB/HBACTPSD 0.2 T/YR 0.0006 LB/MMBTUIA-006212/20/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H SO2 LOW SULFUR FUEL, NG 0.0006 LB/MMBTUOtherCase-byCase 0.0006 LB/MMBTUOH-02553/29/2001 BOILER, NATURAL GASNATURALGAS 85.2 MMBTU/H SO2LOW S NATURAL GAS, 2 GR/100SCF 0.05 LB/HBACTPSD 0.22 T/YR 0.0006 LB/MMBTUOH-025111/29/2001 BOILER, NATURAL GASNATURALGAS 91.2 MMBTU/H SO2 0.055 LB/H N/A 0.6 LB/MMCF 0.0006 LB/MMBTUIN-00681/19/1996 BOILERS, NATURAL GASNATURALGAS 93.9 MMBTU/H SO2 0.0558 LB/HBACTPSD 0 0.0006 LB/MMBTUCA-091911/23/1999 BOILER, FIRE TUBENATURALGAS 31.5 MMBTU/H SO2NO BACT LIMITS WERE APPLIEDTO SOX. DEFAULT EMISSIONFACTORS ARE THE BASIS OF THESOX LEVEL LISTED HERE. 0.0008 LB/MMBTUOtherCase-byCase 0.0008 LB/MMBTUOK-007110/25/2001 AUXILIARY BOILERNATURALGAS 22 MMBTU/H SO2USE OF PIPELINE QUALITYNATURAL GAS 0.001 LB/MMBTUBACTPSD 0.001 LB/MMBTUOH-025212/28/2004 BOILERS (2)NATURALGAS 30.6 MMBTU/H SO2THE MAXIMUM S CONTENT OF THENATURAL GAS SHALL NOT EXCEED2 GRAINS PER 100 CUBIC FEET. 0.031 LB/HBACTPSD 0.046T/ROLLING 12-MONTHS 0.001 LB/MMBTUOH-02548/14/2003 BOILERNATURALGAS 30.6 MMBTU/H SO2 0.031 LB/HBACTPSD 0.07T/ROLLING 12-MONTHS 0.001 LB/MMBTUOH-026510/16/2001 BOILER, NATURAL GASNATURALGAS 49 MMBTU/H SO2THE MAXIMUM SULFUR CONTENTOF THE NATURAL GAS SHALL NOTEXCEED 0.3 GRAINS PER 100STANDARD CUBIC FEET. 0.05 LB/HBACTPSD 0.02 T/YR 0.001 LB/MMBTUMN-005412/4/2003 BOILER, COMMERCIALNATURALGAS 70 MMBTU/H SO2 LOW SULFUR FUEL 0.001 LB/MMBTUBACTPSD 0.001 LB/MMBTUAL-01681/12/2001 BOILERNATURALGAS 83 MMBTU/H SO2 0.001 LB/MMBTUBACTPSD 0.13 LB/H 0.001 LB/MMBTUNJ-00422/5/1999 BOILER 1 (NATURAL GAS)NATURALGAS 84.4 MMBTU/H SO2 NONE LISTED 0.1 LB/HBACTPSD 0.001 LB/MMBTUVA-025511/18/2002 BOILER, AUXILIARYNATURALGAS 99 MMBTU/H SO2LOW SULFUR FUEL AND GOODCOMBUSTION PRACTICES. 0.1 LB/HOtherCase-byCase 0.44 T/YR 0.001 LB/MMBTUNJ-00451/14/1997 BOILERS - NAT GAS (3)NATURALGAS 99.5 MMBTU/H SO2 NONE 0.1 LB/HBACTPSD 0.001 LB/MMBTUAL-01406/19/1997 BOILER, NATURAL GAS FIRED, 2NATURALGAS 11.7 MMBTU/H SO2 CLEAN FUEL 0.014 LB/HBACTPSD 0.0012 LB/MMBTUAL-01396/19/1997 BOILER, NATURAL GAS FIRED, 2NATURALGAS 13.4 MMBTU/H SO2 CLEAN FUEL 0.016 LB/HBACTPSD 0.0012 LB/MMBTUpage 55 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-39: Small Gas Fired Boilers and Heaters- SO2Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitTX-040811/22/2002 AUXILIARY BOILER, (2)NATURALGAS 6 MMBTU/H SO2 0.01 LB/HBACTPSD 0.02 T/YR 0.0017 LB/MMBTUMA-00275/7/2000 AUXILIARY BOILERNATURALGAS 26.6 MMBTU/H SO2NATURAL GAS FUEL OF < .8GRAINS PER 100 SCF. 0.06 LB/HBACTPSD 0.0022 LB/MMBTUAZ-004712/1/2004 AUXILIARY BOILERNATURALGAS 38 MMBTU/H SO2 0.0023 LB/MMBTUBACTPSD 0.0023 LB/MMBTU*AZ-00499/4/2003 AUXILIARY BOILER FOR GE TURBINENATURALGAS 41 MMBTU/H SO2 0.0025 LB/MMBTUBACTPSD 0.0025 LB/MMBTU*AZ-00499/4/2003 AUXILIARY BOILER FOR SIEMENS TURBINESNATURALGAS 55.34 MMBTU/H SO2 0.0025 LB/MMBTUBACTPSD 0.0025 LB/MMBTUMA-00299/29/1999 BOILER, AUXILIARYNATURALGAS 96 MMBTU/H SO2NATURAL GAS FUEL WITH NOMORE THAN .8 GRAINS OF SULFURPER 100 CU FT. 0.3 LB/HBACTPSD 0.0029 LB/MMBTUNM-00446/27/2002 AUXILIARY BOILERS (AUX-1 AND AUX-2)NATURALGAS 33 MMBTU/H SO2NATURAL GAS, GOODCOMBUSTION PRACTICE 0.1 LB/HBACTPSD 0.003 LB/MMBTUAR-00762/17/2004BOILER, PROCESS STEAM, (2) SN-PBCDF-03,-04NATURALGAS 0.03 MMDSCF/H SO2 LOW-SULFUR NATURAL GAS ONLY. 0.1 LB/HBACTPSD 0.0035 LB/MMBTULA-01741/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H SO2 FIRING NATURAL GAS 0.26 LB/HBACTPSD 0.17 T/YR 0.004 LB/MMBTUOH-02489/24/2002 BOILERNATURALGAS 99 MMBTU/H SO2 0.56 LB/HBACTPSD 0.0057LB/MMBTU 0.0057 LB/MMBTUOK-00903/21/2003 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H SO2BACT IS USE OF PIPE-LINEQUALITY NATURAL GAS 0.2 LB/HBACTPSD 0.006 LB/MMBTUIN-011010/5/2001 BOILER, AUXILIARY, NATURAL GASNATURALGAS 35 MMBTU/H SO2 GOOD COMBUSTION PRACTICE 0.006 LB/MMBTUBACTPSD 0.21 LB/H 0.006 LB/MMBTUAL-01692/5/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H SO2 GOOD COMBUSTION PRACTICES 0.006 LB/MMBTUBACTPSD 0.24 LB/H 0.006 LB/MMBTUAR-004012/29/2000 BOILERS, AUXILIARY 2NATURALGAS 44.1 MMBTU/H SO2 LOW SULFUR FUELS 2 GR/DSCFBACTPSD 0.006 LB/MMBTUOH-025712/27/2001 AUXILIARY BOILERNATURALGAS 76 MMBTU/H SO2LOW SULFUR FUEL, NATURAL GASSULFUR LIMIT - 2 GR/100 SCF 0.5 LB/HBACTPSD 0.75 T/YR 0.006 LB/MMBTUOH-02638/9/2001 AUXILIARY BOILERNATURALGAS 80 MMBTU/H SO2 0.48 LB/HBACTPSD 2.1 T/YR 0.006 LB/MMBTUWI-022710/13/2004 NATURAL GAS FIRED AUXILLIARY BOILERNATURALGAS 97.1 MMBTU/H SO2 NATURAL GAS FUEL 0.06 LB/HBACTPSD 0.006 LB/MMBTUOK-005110/1/1999 AUXILIARY BOILERNATURALGAS SO2 USE OF NATURAL GAS 0.006 LB/MMBTUBACTPSD 0.006 LB/MMBTUTX-03641/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H SO2 NONE INDICATED 0.02 LB/HOtherCase-byCase 0.01 T/YR 0.008 LB/MMBTUAR-00762/17/2004 BOILER, HOT WATER, (2) SN-PBCDF-05, -06NATURALGAS 0.01 MMDSCF/H SO2 LOW-SULFUR NATURAL GAS ONLY. 0.1 LB/HBACTPSD 0.0085 LB/MMBTUNV-00396/1/2001 AUXILIARY BOILERSNATURALGAS 44.1 MMBTU/H SO2USE OF PIPELINE-QUALITYNATURAL GAS 0.4 LB/HBACTPSD 0.009 LB/MMBTUTX-02744/3/2000 AUXILIARY BOILERNATURALGAS 54.01 MMBTU/H SO2FUEL SPECIFICATIONS OF NOMORE THAN 2.5 GRAINS TOTALSULFUR PER 100 DRY STANDARDCUBIC FEET ON A SHORT-TERMBASIS AND 0.5 GRAIN TOTALSULFUR PER 100 DSCF ON AROLLING 12-MONTH AVERAGEBASIS. 0.77 LB/H N/A 0.07 T/YR 0.014 LB/MMBTUTX-037811/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H SO2 NONE INDICATED 0.95 LB/H N/A 4.17 T/YR 0.02 LB/MMBTUAK-00456/6/2000 DRILLING BOILER NO. 1NATURALGAS 100 HP SO2USE NATURAL GAS WITH AHYDROGEN SULFIDE CONTENTNOT TO EXCEED 200 PPM ANDFUEL OIL WITH A SULFURCONTENT NOT TO EXCEED 0.25%BY WEIGHT. 500 PPM N/A 0.15 LB/H 0.033 LB/MMBTUpage 56 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-39: Small Gas Fired Boilers and Heaters- SO2Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitVA-02713/24/2003 BOILER NO. 1NATURALGAS 43.2 MMBTU/H SO2CONTINUOUS EMISSIONMONITORING SYSTEM AND GOODCOMBUSTION PRACTICES. 2.19 LB/H N/A 0.05 LB/MMBTUAR-00762/17/2004 BOILER, LABORATORY SN-PBCDF-16NATURALGAS 1.4 mmbtu/h SO2 LOW-SULFUR NATURAL GAS ONLY. 0.1 LB/HBACTPSD 0.071 LB/MMBTUOK-00448/16/2001 AUXILIARY BOILERS, (2)NATURALGAS 48 MMBTU/H SO2USE OF PIPELINE NATURAL GASW/SULFUR CONTENT 2 GRAINSSULFUR/100 SCF 0.57 LB/HBACTPSD 2.47 T/YR 0.2 LB/MMBTUKY-00685/29/1997 BOILER (NATURAL GAS)NATURALGAS 96 MMBTU/H SO2THE SULFUR CONTENT OF NO.2FUEL SHALL NOT EXCEED 0.3%. 0.3 LB/MMBTUBACTPSD 40 T/YR 0.3 LB/MMBTUSC-00418/14/1996 BOILERS, (2)NATURALGAS 95 MMBTU/H SO2USE OF NATURAL GAS ASPRIMARY FUEL, AND <= 0.5%SULFUR FUEL AS BACK UP 0.5 LB/MMBTUBACTPSD 34LB/H EA.BOILER 0.5 LB/MMBTUIA-00545/20/1997 BOILER #1NATURALGAS 2.3 MMBTU/H SO2SO2 LIMITS SET TO STAY BELOWPSD SIGNIFICANCE 9.46 T/YROtherCase-byCase 0.9 LB/MMBTUKY-00877/12/2002 BOILER, NATURAL GAS, #4NATURALGAS 33.5 MMBTU/H SO2CLEAN FUEL: FUEL OIL LIMITED TO< 0.5% S BY WT 1.057 LB/MMBTUBACTPSD 1.057 LB/MMBTU*AK-00628/19/2005 NATCO TEG REBOILERNATURALGAS 1.34 MMBtu/hr SO2LIMIT SULFUR CONTENT OF FUELCOMBUSTED 250 PPMVBACTPSD 1.28 LB/MMBTUAK-00382/5/1999 GLYCOL REBOILER, UNIT 13NATURALGAS 5 MMBTU/H SO2HYDROGEN SULFIDE CONTENT OFNATURAL GAS FUEL SHALL NOTEXCEED 50 PPMV. 500 PPMOtherCase-byCase 2.55 LB/MMBTUAK-00382/5/1999 RIG BOILER (NATURAL GAS), UNIT 206, 207NATURALGAS 6.3 MMBTU/H SO2HYDROGEN SULFIDE CONTENT OFNATURAL GAS FUEL SHALL NOTEXCEED 50 PPMV 500 PPMOtherCase-byCase 2.55 LB/MMBTUPA-021012/14/2001 BOILER, (2)NATURALGAS 33.5 MMBTU/H SO2 LOW SULFUR FUEL 4 LB/MMBTU N/A 4 LB/MMBTUTX-038912/31/2002 BACK-UP BOILERNATURALGAS 13.4 MMBUT/H SO2 0.01 LB/HOtherCase-byCase 0.05 T/YROH-02764/14/2003BOILER FOR VACUUM OXYGEN DEGASSERVESSELNATURALGAS 25 MMBTU/H SO2 0.01 LB/H 0.06 T/YRVA-024312/1/2002 BOILER, NAT GAS & OILNATURALGAS 26.5 MMBTU/H SO2 EMISSION LIMITS IN T/YR ONLY 16 T/YROtherCase-byCase*WA-029210/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H SO2 0.07 LB/HBACTPSD 1PPM @3% O2OK-004310/22/2001 AUXILIARY BOILERNATURALGAS 30 MMBTU/H SO2 USE OF NATURAL GAS 150 PPMBACTPSDAL-018110/23/2001 31.4 MMBTU/HR NATURAL GAS FIRED BOILERNATURALGAS 31.4 MMBTU/H SO2 NATURAL GAS IS EXCLUSIVE FUEL. 0.0057 LB/MMBTUBACTPSD 0.2 LB/HAR-00514/1/2002 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H SO2 FUELS LIMIT: < 2 GR/100 DSCFBACTPSDAL-018012/11/200135 MMBTU/HR NAT. GAS FIRED AUXILIARYBOILERNATURALGAS 35 MMBTU/H SO2 NATURAL GAS 0.0057 LB/MMBTUBACTPSD 0.2 LB/HMN-00537/15/2004 BOILER, NATURAL GAS (1)NATURALGAS 40 MMBTU/H SO2LOW SULFUR FUEL 0.8 GR/SCF,CALENDAR YEAR AVERAGEBACTPSDVA-02713/24/2003 BOILER NO. 3NAT GASOR DISOIL 43.2 MMBTU SO2CONTINUOUS EMISSIONMONITORING SYSTEM AND GOODCOMBUSTION PRACTICES. 4.76 T/YR N/AWI-02268/27/2004 NATURAL GAS FIRED BOILERNATURALGAS 46.2 MMBTU/H SO2 NATURAL GAS FUEL ONLY 0.05 LB/H N/ANV-00375/14/2004 AUXILIARY BOILERNATURALGAS 60 MMBTU/H SO2USE OF LOW-SULFUR NATURALGAS 0.04 LB/HBACTPSDpage 57 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-39: Small Gas Fired Boilers and Heaters- SO2Control Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitNJ-00463/7/1996BOILERS 4&5, COMBUSTION CONTROLS,OXYGEN TRIM, ETCNATURALGAS 94 MMBTU/H SO2 0 LB/HBACTPSDAK-00533/21/2000 LISTER BOILER, DR11 100 HP SO2USE ONLY FUEL GAS WITH AHYDROGEN SULFIDE CONTENTNOT TO EXCEED 200 PPM, ANDUSE ONLY DISTILLATE FUEL OILWITH A SULFUR CONTENT NOT TOEXCEED 0.15% 500 PPM N/AAK-00533/21/2000 LISTER BOILER, DR12 100 HP SO2USE ONLY FUEL GAS WITH A H2SCONTENT NOT TO EXCEED 200PPM, AND USE ONLY DISTILLATEFUEL OIL WITH A S CONTENT NOTTO EXCEED 0.15% 500 PPM N/ATX-036311/13/2000 BOILER NO. 2 NAT GAS SO2 NONE INDICATED 0.04 LB/HCase-byCase 0.09 T/YRTX-036311/13/2000 BOILER NO 3 NAT GAS SO2 NONE INDICATED 0.03 LB/H N/A 0.12 T/YRTX-030010/13/1998 GLYCOL REBOILER NAT GAS SO2FUEL IS LIMITED TO PIPELINEQUALITY, SWEET NATURAL GASCONTAINING NO MORE THAN 5 GRS/100 DSCF 0.01 LB/HOtherCase-byCase 0.01 T/YROK-00745/1/2001 AUXILIARY BOILERNATURALGAS 27.5 MMBTU/H SO2USE OF NATURAL GAS WITH LOWSULFUR CONTENT 2GR/100SCFBACTPSDBACT-PSD SO2 lb/MMBtu Emission LimitsMIN 0.0006 lb/MMBtu MIN 0.0006 lb/MMBtuMAX 1.28 lb/MMBtu MAX 4 lb/MMBtuMEDIAN 0.0025 lb/MMBtu MEDIAN 0.017 lb/MMBtuCOUNT44CASES COUNT14CASESRBLC SO2 BACT Limits SummaryOther (non-BACT) SO2 lb/MMBtuEmission Limitspage 58 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40A: Small Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for Statistical AnalysisRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsNon-BACTlb/MMBtuLimits*AK-00628/19/2005 NATCO TEG REBOILERNATURALGAS 1.34 MMBtu/hr NOxCONVENTIONAL BURNERTECHNOLOGY 0.08 LB/MMBTUBACTPSD 0.08 LB/MMBTU0.08OH-025212/28/2004 BOILERS (2)NATURALGAS 30.6 MMBTU/H NOx 1.07 LB/HBACTPSD 1.6T/ROLLING12-MONTHS 0.035 LB/MMBTU0.035AZ-004712/1/2004 AUXILIARY BOILERNATURALGAS 38 MMBTU/H NOx LOW NOX BURNERS 0.37 LB/MMBTUBACTPSD 0.37 LB/MMBTU0.37AL-021211/22/2004 BOILER, NATURAL GAS (2)NATURALGAS 24.5 mmbtu/h NOx LOW NOX BURNERS 0.35 LB/MMBTUBACTPSD 0.35 LB/MMBTU0.35WI-022710/13/2004NATURAL GAS FIREDAUXILLIARY BOILERNATURALGAS 97.1 MMBTU/H NOxNATURAL GAS FUEL,COMBUSTIONOPTIMIZATION (BASED ONCAPACITY FACTOR DURINGOZONE SEASONEXCEEDING 20%) 13.7 LB/H N/A 0.141 LB/MMBTU0.141WI-02268/27/2004 NATURAL GAS FIRED BOILERNATURALGAS 46.2 MMBTU/H NOxBURNER DESIGN, NATURALGAS FUELED 1.67 LB/H N/A 0.036 LB/MMBTU0.036AR-00777/22/2004 BOILERSNATURALGAS 22 MMBTU/H NOx LOW NOX BURNERS 0.08 LB/MMBTUBACTPSD 0.08 LB/MMBTU0.08MN-00537/15/2004 BOILER, NATURAL GAS (1)NATURALGAS 40 MMBTU/H NOx LOW NOX BURNER; FGR. 0.04 LB/MMBTUBACTPSD 0.04 LB/MMBTU0.04*NE-00236/22/2004 AUXILIARY BOILER (OIL)NATURALGAS 73.3 MMBTU/H NOxOPERATION LIMITED TO 500HOURS PER YEAR. 0.1 LB/MMBTUBACTPSD 0.1 LB/MMBTU0.1WV-00216/9/2004BOILER, NATURAL GAS, 39.00MMBTUNATURALGAS 365 MMSCF/YR NOxLOW-NOX BURNERS/FLUEGAS RECIRCULATION 2.08 PPHBACT-PSD 9.13 T/YR 0.05 LB/MMBTU0.05NV-00375/14/2004 AUXILIARY BOILERNATURALGAS 60 MMBTU/H NOxLOW NOX BURNER (WITHEITHER INTERNAL OREXTERNAL FLUE GASRECIRCULATION) 0.035 LB/MMBTUBACTPSD 9.6 TONS/YR 0.035 LB/MMBTU0.035ID-00154/5/2004 BOILER, 64 MMBTU/HNATURALGAS 64 MMBTU/H NOx LOW-NOX BURNER 2.88 LB/H RACT 12.63 T/YR 0.045 LB/MMBTU0.045AL-01913/23/2004 BOILERS, NATURAL GAS, (3)NATURALGAS 50 MMBTU/H NOxNATURAL GAS ONLY; LOWNOX BURNERS 1.75 LB/HBACTPSD 0.035 LB/MMBTU 0.035 LB/MMBTU0.035AR-00762/17/2004BOILER, HOT WATER, (2) SNPBCDF-05, -06NATURALGAS 0.01 MMDSCF/H NOxLOW-NOX BURNERSWITHOUT FLUE GASRECIRCULATION. 0.6 LB/HBACTPSD 0.051 LB/MMBTU0.051AR-00762/17/2004BOILER, PROCESS STEAM,(2) SN-PBCDF-03, -04NATURALGAS 0.03 MMDSCF/H NOxLOW-NOX BURNERSWITHOUT FLUE GASRECIRCULATION. 1.5 LB/HBACTPSD 0.0528 LB/MMBTU0.0528AR-00762/17/2004BOILER, LABORATORY SNPBCDF-16NATURALGAS 1.4 mmbtu/h NOxLOW-NOX BURNERSWITHOUT FLUE GASRECIRCULATION. 0.2 LB/HBACTPSD 0.143 LB/MMBTU0.143WI-02071/21/2004BOILER, S52/B52, 11MMBTU/HNATURALGAS 11 MMBTU/H NOxNATURAL GAS / PROPANE;LOW NOX BURNER 0.04 LB/MMBTUBACTPSD 0.04 LB/MMBTU0.04WI-02071/21/2004BOILER, S53 / B53, 34MMBTU/HNATURALGAS 34 MMBTU/H NOxNATURAL GAS / PROPANE;LOW NOX BURNER 0.04 LB/MMBTUBACTPSD 0.04 LB/MMBTU0.04WI-02071/21/2004BOILER, S50/B50, 60MMBTU/HNATURALGAS 60 MMBTU/H NOx LOW NOX BURNER 0.04 LB/MMBTUBACTPSD 0.04 LB/MMBTU0.04WI-02071/21/2004BOILER, S51/B51, 80MMBTU/HNATURALGAS 80 MMBTU/H NOxNAT. GAS / PROPANE, LOWNOX BURNER 0.04 LB/MMBTUBACTPSD 0.04 LB/MMTU0.04OR-003912/30/2003BOILERS, AUXILIARY,NATURAL GAS, (2)NATURALGAS 80 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION 0.035 LB/MMBTUBACTPSD 0.035 LB/MMBTU0.035MN-005412/4/2003 BOILER, COMMERCIALNATURALGAS 70 MMBTU/H NOxDRY LOW NOX AND FLUEGAS RECIRCULATION 0.036 LB/MMBTU 0.036 LB/MMBTU0.036IN-010811/21/2003 BOILER, NATURAL GAS, (2)NATURALGAS 34 MMBTU/H NOxLOW NOX BURNERS,NATURAL GAS 0.035 LB/MMBTUBACTPSD 0.035 LB/MMBTU0.035MI-03559/16/2003 BOILER, GAS-FIREDNATURALGAS 98.51 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION. 0.08 LB/MMBTUBACTPSD 0.08 LB/MMBTU0.08*AZ-00499/4/2003AUXILIARY BOILER FOR GETURBINENATURALGAS 41 MMBTU/H NOx LOW NOX BURNERS 0.027 LB/MMBTUBACTPSD 0.027 LB/MMBTU0.027*AZ-00499/4/2003AUXILIARY BOILER FORSIEMENS TURBINESNATURALGAS 55.34 MMBTU/H NOx LOW NOX BURNERS 0.036 LB/MMBTUBACTPSD 0.036 LB/MMBTU0.036OH-02548/14/2003 BOILERNATURALGAS 30.6 MMBTU/H NOx 1.08 LB/HBACTPSD 2.3T/ROLLING12-MONTHS 0.035 LB/MMBTU0.035page 59 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40A: Small Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for Statistical AnalysisRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsNon-BACTlb/MMBtuLimitsOH-02764/14/2003BOILER FOR VACUUMOXYGEN DEGASSER VESSELNATURALGAS 25 MMBTU/H NOx LOW NOX BURNER 2.45 LB/HBACTPSD 10.7 T/YRWA-03163/27/2003 BOILER, NATURAL GASNATURALGAS 4.19 MMBTU/H NOxGOOD COMBUSTIONPRACTICE 34PPMDV @3% O2BACTPSD 4 LB/D 0.04 LB/MMBTU0.04GA-00983/24/2003 AUXILIARY BOILERNATURALGAS 83 MMBTU/H NOx 0.055 LB/MMBTUOtherCase-byCase 0.055 LB/MMBTU0.055VA-02713/24/2003 BOILER NO. 1NATURALGAS 43.2 MMBTU/H NOxFLUE GAS RECIRCULATIONWITH LOW NOX BURNERS.CONTINUOUS EMISSIONMONITORING SYSTEM.GOOD COMBUSTIONPRACTICES. 6.17 LB/HOtherCase-byCase 0.14 LB/MMBTU0.14VA-02713/24/2003 BOILER NO. 3NAT GASOR DISOIL 43.2 MMBTU NOxFLUE GAS RECIRCULATIONWITH LOW NOX BURNER.CONTINUOUS EMISSIONMONITORING SYSTEM ANDGOOD COMBUSTIONPRACTICES. 40.31 T/YROtherCase-byCaseOK-00903/21/2003 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H NOx LOW-NOX BURNERS 0.05 LB/MMBTUBACTPSD 0.05 LB/MMBTU0.05OR-00403/12/2003BOILER, AUXILIARY,NATURAL GASNATURALGAS 50000 LB/H NOx 30PPMVD @3% O2BACTPSDTX-03641/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H NOx NONE INDICATED 0.29 LB/HOtherCase-byCase 1.07 T/YR 0.116 LB/MMBTU0.116PA-02161/13/2003 BOILER, DRAP LINENATURALGAS 33.5 MMBTU/H NOx ULTRA LOW NOX BURNER 30PPM @ 3%O2OtherCase-byCase 0.04 LB/MMBTU0.04WA-02911/3/2003 BOILER, AUXILIARYNATURALGAS 55.3 MMBTU/H NOx LNB PLUS FGR 30PPMDV @3% O2OtherCase-byCase 12.7 LB/H 0.23 LB/MMBTU0.23TX-038912/31/2002 BACK-UP BOILERNATURALGAS 13.4 MMBUT/H NOx 1.4 LB/HOtherCase-byCase 6.12 T/YRIA-006212/20/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H NOx DLN 0.049 LB/MMBTUOtherCase-byCase 0.049 LB/MMBTU0.049TX-035412/19/2002(2) STEAM BOILERS, X-426AAND X-426BNATURALGAS 15.8 MMBTU/H NOx LOW NOX BURNERS 2.05 LB/HOtherCase-byCase 9 T/YR 0.13 LB/MMBTU0.13VA-024312/1/2002 BOILER, NAT GAS & OILNATURALGAS 26.5 MMBTU/H NOxEMISSION LIMITS IN T/YRONLY 12.8 T/YROtherCase-byCaseTX-040811/22/2002 AUXILIARY BOILER, (2)NATURALGAS 6 MMBTU/H NOx 0.59 LB/HBACTPSD 2.58 T/YR 0.098 LB/MMBTU0.098VA-026011/21/2002 AUXILIARY BOILER, (2)NATURALGAS 40 MMBTU/H NOxLOW NOX BURNERS ANDCLEAN FUEL. 3.2 LB/HBACTPSD 4.8 T/YR 0.08 LB/MMBTU0.08VA-025511/18/2002 BOILER, AUXILIARYNATURALGAS 99 MMBTU/H NOxLOW NOX BURNERS ANDLOW NOX FUEL. 0.036 LB/MMBTUOtherCase-byCase 18 T/YR 0.036 LB/MMBTU0.036GA-010110/23/2002 BOILER, AUXILIARYNATURALGAS 31.4 MMBTU/H NOxDRY LOW NOX BURNERS,FLUE GAS RECIRCULATION 30PPM @ 3%O2BACTPSD 0.037 LB/MMBTU0.037AL-019210/18/2002 BOILERS, NATURAL GAS, (3)NATURALGAS 30 MMBTU/H NOxLOW NOX BURNERS, CLEANFUEL, GOOD COMBUSTION 1.05 LB/HBACTPSD 0.035 LB/MMBTU 0.035 LB/MMBTU0.035CA-102310/8/2002 BOILER, 39 MMBTU/HNATURALGAS 39 MMBTU/H NOxULTRA-LOW NOX BURNERWITH FGR 9PPMVD @3% O2 N/AOH-02489/24/2002 BOILERNATURALGAS 99 MMBTU/H NOx LOW NOX BURNERS 4.95 LB/HBACTPSD 0.05 LB/MMBTU 0.05 LB/MMBTU0.05VA-02619/6/2002 AUXILIARY BOILERNATURALGAS 80 MMBTU/H NOxLOW NOX BURNERS ANDGOOD COMBUSTIONPRACTICES. 3.82 LB/HBACTPSD 5.73 T/YR 0.05 LB/MMBTU0.05*WA-02978/30/2002 BOILERNATURALGAS 4.19 MMBTU/H NOxGOOD COMBUSTIONPRACTICE 34PPM @ 3%O2BACTPSD 4 LB/Dpage 60 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40A: Small Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for Statistical AnalysisRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsNon-BACTlb/MMBtuLimitsAR-00708/23/2002 AUXILIARY BOILERNATURALGAS 33 MMBTU/H NOxLOW NOX OPTION (LOWNOX BURNER AND/OR FLUEGAS RECIRCULATION) 0.04 LB/MMBTUBACTPSD 0.04 LB/MMBTU0.04IA-00607/23/2002AUXILIARY BOILER (48.5MMBTU/H)NATUALGAS 48.69MILLIONCF/YR NOx GCP 0.034 LB/MMBTUBACTPSD 0.034 LB/MMBTU0.034AL-01857/12/2002TWO (2) 40 MMBTU/HAUXILIARY BOILERSNATURALGAS 40 MMBTU/H NOx LOW NOX BURNERS 0.05 LB/MMBTUBACTPSD 2 LB/HTX-04377/5/2002 BOILERS, AUXILIARYNATURALGAS 40 mmbtu/h NOxLOW NOX BURNERS, CLEANFUEL. BOILER WILLOPERATE A MAXIMUM OF3000 H/YRBACTPSDNM-00446/27/2002AUXILIARY BOILERS (AUX-1AND AUX-2)NATURALGAS 33 MMBTU/H NOxCLEAN FUEL, GOODCOMBUSITON PRACTICE 1.2 LB/HBACTPSD 0.036 LB/MMBTU0.036OK-00706/13/2002 AUXILIARY BOILERNATURALGAS 33 MMBTU/H NOx LOW NOX BURNERS 0.035 LB/MMBTUBACTPSD 0.035 LB/MMBTU0.035OK-00725/6/2002 AUXILIARY BOILERNATURALGAS 93 MMBUT/H NOx LOW NOX BURNERS 0.075 LB/MMBTUBACTPSD 0.075 LB/MMBTU0.075IA-00584/10/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H NOx 0.05 LB/MMBTUBACTPSD 16.4 T/YR 0.05 LB/MMBTU0.05TN-01534/3/2002CCR STABILIZATIONREBOILERNATURALGAS 54 MMBTU/H NOx 0.06 LB/MMBTUBACTPSD 0.06 LB/MMBTU0.06TN-01534/3/2002 BOILER, NO. 9NATURALGAS 95 MMBTU/H NOx 0.084 LB/MMBTUBACTPSD 0.084 LB/MMBTU0.084AR-00514/1/2002 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H NOx 0.035 LB/MMBTUBACTPSD 0.035 LB/MMBTU0.035OK-00552/12/2002 AUXILIARY BOILERNATURALGAS 31 MMBTU/H NOx COMBUSTION CONTROL 0.01 LB/MMBTUOtherCase-byCase 0.01 LB/MMBTU0.01OK-00562/12/2002 AUXILIARY BOILERSNATURALGAS 0 NOxGOOD COMBUSTIONPRACTICES AND DESIGN 0.1 LB/MMBTUBACTPSD 0.1 LB/MMBTU0.1LA-01741/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H NOx LOW-NOX BURNERS 61.34 LB/HOtherCase-byCase 40.47 T/YR 0.1 LB/MMBTU0.1NC-00941/9/2002BOILER, AUXILIARY,NATURAL GASNATURALGAS 83 MMBTU/H NOx LOW NOX BURNERS 4.07 LB/HBACTPSD 0.049 LB/MMBTU0.049OH-025712/27/2001 AUXILIARY BOILERNATURALGAS 76 MMBTU/H NOxLOW NOX BURNERSINSTALLED 6.69 LB/HBACTPSD 10.03 T/YR 0.08 LB/MMBTU0.08PA-021012/14/2001 BOILER, (2)NATURALGAS 33.5 MMBTU/H NOx LO-NOX BURNERS 30PPMDV @3% O2 N/A 0.036 LB/MMBTU0.036AL-018012/11/200135 MMBTU/HR NAT. GASFIRED AUXILIARY BOILERNATURALGAS 35 MMBTU/H NOx LOW NOX BURNERS 0.108 LB/MMBTUBACTPSD 3.77 LB/HIN-009512/7/2001 AUXILLIARY BOILERNATURALGAS 21 MMBTU/H NOx LOW NOX BURNERS 0.049 LB/MMBTUBACTPSD 0.049 LB/MMBTU0.049OH-025111/29/2001 BOILER, NATURAL GASNATURALGAS 91.2 MMBTU/H NOxUSE OF LOW-NOXBURNERS. 3.21 LB/H N/A 22.7 T/YR 0.0352 LB/MMBTU0.0352TX-037811/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H NOx ULTRA LOW-NOX BURNERS 0.9 LB/HOtherCase-byCase 3.94 T/YR 0.015 LB/MMBTU0.015OK-007110/25/2001 AUXILIARY BOILERNATURALGAS 22 MMBTU/H NOxNATURAL GAS FUEL ANDGOOD COMBUSTIONCONTROL 0.036 LB/MMBTUBACTPSD 0.036 LB/MMBTU0.036*WA-029210/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H NOxFGR AND LOW-NOXBURNERS 1.03 LB/HBACTPSD 30PPM @ 3%O2AL-018110/23/200131.4 MMBTU/HR NATURALGAS FIRED BOILERNATURALGAS 31.4 MMBTU/H NOx LOW NOX BURNERS 0.108 LB/MMBTUBACTPSD 3.77 LB/HOK-004310/22/2001 AUXILIARY BOILERNATURALGAS 30 MMBTU/H NOx LOW NOX BURNERS 0.05 LB/MMBTUBACTPSD 0.05 LB/MMBTU0.05OH-026510/16/2001 BOILER, NATURAL GASNATURALGAS 49 MMBTU/H NOx 4.9 LB/HBACTPSD 1.96 T/YR 0.1 LB/MMBTU0.1IN-011010/5/2001BOILER, AUXILIARY,NATURAL GASNATURALGAS 35 MMBTU/H NOxCLEAN FUEL, LOW NOXBURNERS 0.08 LB/MMBTUBACTPSD 2.8 LB/H 0.08 LB/MMBTU0.08AL-017910/3/200130 MMBTU/HR AUXILIARYBOILERNATURALGAS 30 MMBTU/H NOx LOW NOX COMBUSTION 0.096 LB/MMBTUBACTPSD 2.9 LB/H 0.096 LB/MMBTU0.096page 61 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40A: Small Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for Statistical AnalysisRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsNon-BACTlb/MMBtuLimitsMD-00339/27/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H NOxEXCLUSIVE USE OFNATURAL GAS, ADVANCEDDRY LOW-NOX BURNERS;GOOD COMBUSTIONCONTROLS HEAT INPUT TOTHE AUXILIARY BOILERS (2)SHALL BE LIMITED TO210,240 MMBTU FOR ANYCONSECUTIVE 12-MONTHPERIOD LAERCA-10999/4/2001BOILER: 5 TO < 33.5MMBTU/HRNATURALGAS 21.46 MMBTU/H NOx ULTRA LOW-NOX BURNER 9PPMD @3% O2BACTPSDWV-00138/30/2001 BOILERNATURALGAS 54.4 MMBTU/H NOxLOW NOX BURNERS ANDFLUE-GAS RECIRCULATION 0.035 LB/MMBTUBACTPSD 0.035 LB/MMBTU0.035WV-00138/30/2001 BOILERS, 3NATURALGAS 65.78 MMBTU/H NOxLOW-NOX BURNERS ANDFLUE-GAS RECIRCULATION 0.035 LB/MMBTUBACTPSD 0.035 LB/MMBTU0.035OK-00548/21/2001 BOILERSNATURALGAS 62.77 MMBTU/H NOx LOW NOX BURNERS 0.035 LB/MMBTUBACTPSD 2.48 LB/H 0.035 LB/MMBTU0.035OK-00448/16/2001 AUXILIARY BOILERS, (2)NATURALGAS 48 MMBTU/H NOxDRY LOW NOX BURNERS,OPERATES IN PRE-MIXMODE. 9.41 LB/HBACTPSD 41.22 T/YR 0.1 LB/MMBTU0.1OH-02638/9/2001 AUXILIARY BOILERNATURALGAS 80 MMBTU/H NOx LOW NOX BURNERS 2.72 LB/HBACTPSD 11.9 T/YR 0.034 LB/MMBTU0.034IN-00876/6/2001AUXILARY BOILER, NATURALGAS (2)NATURALGAS 46 MMBTU/H NOxGOOD COMBUSTION. LOWNOX BURNERS. LIMIT ISFOR EACH BOILER. 0.049 LB/MMBTUBACTPSD 2.28 LB/H 0.049 LB/MMBTU0.049NV-00396/1/2001 AUXILIARY BOILERSNATURALGAS 44.1 MMBTU/H NOxGOOD COMBUSTIONCONTROL 30PPMVD@3% O2BACTPSD 5.2 LB/H 0.118 LB/MMBTU0.118OK-00465/17/2001 AUXILIARY BOILERNATURALGAS 20 MMBTU/H NOx LOW NOX BURNERS 0.049 LB/MMBTUBACTPSD 0.049 LB/MMBTU0.049IN-00865/9/2001AUXILARY BOILER, NATURALGAS (2)NATURALGAS 35 MMBTU/H NOxLOW NOX BURNERS. GOODCOMBUSTION. NATURALGAS. LB/H LIMIT IS FOREACH BOILER. 0.049 LB/MMBTUBACTPSD 1.72 LB/H 0.049 LB/MMBTU0.049OK-00745/1/2001 AUXILIARY BOILERNATURALGAS 27.5 MMBTU/H NOx LOW NOX BURNERS 0.1 LB/MMBTUBACTPSD 0.1 LB/MMBTU0.1MS-00454/2/2001 BOILERNATURALGAS 35 MMBTU NOx LOW NOX BURNERS 0.12 LB/MMBTUBACTPSD 0.12 LB/MMBTU0.12OH-02553/29/2001 BOILER, NATURAL GASNATURALGAS 85.2 MMBTU/H NOx 3.07 LB/HBACTPSD 13.4 T/YR 0.036 LB/MMBTU0.036OH-02582/15/2001 BOILERS (4)NATURALGAS 20.9 MMBTU/H NOx LOW NOX BURNERS. 0.69 LB/H N/A 3.02 T/YR 0.033 LB/MMBTU0.033AL-01692/5/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H NOx LOW NOX BURNERS 0.08 LB/MMBTUBACTPSD 3.2 LB/H 0.08 LB/MMBTU0.08AL-01681/12/2001 BOILERNATURALGAS 83 MMBTU/H NOx LOW NOX BURNERS 0.05 LB/MMBTUBACTPSD 4.18 LB/H 0.05 LB/MMBTU0.05AL-01781/5/2001TWO (2) 11.7 MMBTU/HBOILERSNATURALGAS 11.7 MMBTU/H NOx LOW NOX BURNERS 0.036 LB/MMBTUBACTPSD 0.53 LB/HAL-01781/5/2001TWO (2) 13.4 MMBTU/HBOILERSNATURALGAS 13.4 MMBTU/H NOx LOW NOX BURNERS 0.036 LB/MMBTUBACTPSD 0.75 LB/HNM-004212/29/2000 AUX-1 AUXILARY BOILERNATURALGAS 44.1 MMBTU/H NOxDRY LOW NOX BURNERS,NATURAL GASCOMBUSTION, AND GOODENGINEERING PRACTICE. 1.5 LB/HBACTPSD 0.03 LB/MMBTU0.03AR-004012/29/2000 BOILERS, AUXILIARY 2NATURALGAS 44.1 MMBTU/H NOxLOW NOX COMBUSTER &PROPER OPERATION. LB/HRLIMIT FOR EACH BOILER. 0.12 LB/MMBTUBACTPSD 5.3 LB/H 0.12 LB/MMBTU0.12TX-036311/13/2000 BOILER NO. 2 NAT GAS NOx NONE INDICATED 3.4 LB/HOtherCase-byCase 7.45 T/YRTX-036311/13/2000 BOILER NO 3 NAT GAS NOx NONE INDICATED 2.29 LB/HOtherCase-byCase 10.01 T/YRWI-01818/2/2000 BOILERNATURALGAS 10 MMBTU/H NOxNATURAL GAS FUEL, LOW -NOX BURNER(LNB`S) ANDFLU GAS RECIRCULATION(FGR). 30PPMVD AT3%OXYGENBACTPSD 0.035 LB/MMBTU 0.035 LB/MMBTU0.035page 62 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40A: Small Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for Statistical AnalysisRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsNon-BACTlb/MMBtuLimitsWY-00567/25/2000BOILER (AUXILLARY), TRAINIIINATURALGAS 76.7 MMBTU/H NOx LOW NOX BURNER 9.5 T/YRBACTPSD 9.2 LB/HR 0.12 LB/MMBTU0.12CA-09467/12/2000 BOILERNATURALGAS 21 MMBTU/H NOxSELECTIVE CATALYTICREDUCTION 7 PPMVD LAER 0.009 LB/MMBTU0.009CA-11007/12/2000BOILER: 5 TO < 33.5MMBTU/HRNATURALGAS 21 MMBTU/H NOx SCR 7PPMVD@3% O2BACTPSDMA-00275/7/2000 AUXILIARY BOILERNATURALGAS 26.6 MMBTU/H NOxSCR, DRY LOW NOXCOMBUSTOR 1.1 LB/H LAER 0.04 LB/MMBTU0.04CA-10205/1/2000 BOILER 4.2 MMBTU/HNATURALGAS 4.2 MMBTU/H NOxSCONOX CATALYTICABSORPTION SYSTEM 2PPMVD @3% O2BACTPSDCA-09434/6/2000 BOILERNATURALGAS 6.3 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION 12 PPMVD LAER 0.015 LB/MMBTU0.015TX-02744/3/2000 AUXILIARY BOILERNATURALGAS 54.01 MMBTU/H NOx NONE INDICATED 5.4 LB/HBACTPSD 0.47 T/YR 0.1 LB/MMBTU0.1CA-09453/17/2000 BOILERNATURALGAS 16.3 MMBTU/H NOx ULTRA LOW NOX BURNER 12PPM @ 3%O2 LAER 127 LB/MO 0.015 LB/MMBTU0.015CA-10053/16/2000 BOILER, 5.05 MMBTU/HNATURALGAS 5.05 MMBTU/H NOxLOW NOX BURNER ANDFLUE GAS RECIRCULATION 20PPMV @3% O2BACTPSD 0.015 LB/MMBTU0.015CA-09403/15/2000 BOILER, PORTABLENATURALGAS 28.8 MMBTU/H NOx 9 PPMVD LAER 0.011 LB/MMBTU0.011CA-09473/15/2000 BOILERNATURALGAS 7.5 MMBTU/H NOx LOW NOX BURNERS 12 PPMVD LAER 0.015 LB/MMBTU0.015CA-09443/10/2000 BOILERNATURALGAS 16.3 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION 12 PPMVD LAER 0.015 LB/MMBTU0.015AL-01422/29/2000BOILERS, NATURAL GASFIREDNATURALGAS 10 MMBTU/H NOxNATURAL GAS FUEL ONLY,LOW NOX BURNERS 0.35 LB/HBACTPSD 0.035 LB/MMBTU 0.035 LB/MMBTU0.035PA-01652/24/2000 BOILERS, (3)NATURALGAS 90 MMBTU/H NOx LOW NOX BURNERS 0.1 LB/MMBTUBACTPSD 0.1 LB/MMBTU0.1CA-09422/15/2000 BOILER, NATURAL GASNATURALGAS 6 MMBTU/H NOx LOW NOX BURNERS 12 PPMVD LAER 0.015 LB/MMBTU0.015CA-09411/28/2000 BOILER, NATURAL GASNATURALGAS 16.3 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION 15 PPMVD LAER 0.018 LB/MMBTU0.018OK-00411/19/2000 AUXILIARY BOILERNATURALGAS 22 MMBTU/H NOx COMBUSTION CONTROL 0.035 LB/MMBTUBACTPSD 0.035 LB/MMBTU0.035CA-100612/16/1999 BOILER, 20.9 MMBTU/HNATURALGAS 20.9 MMBTU/H NOx LOW NOX BURNER 9PPMVD@3%O2BACTPSD 0.01 LB/MMBTU0.01CA-093912/16/1999 BOILERNATURALGAS 20.9 MMBTU/H NOx LOW NOX BURNERS 9 PPMVD LAER 0.011 LB/MMBTU0.011CA-102112/7/1999 BOILER: 16.5 MMBTU/HNATURALGAS 16.5 MMBTU/H NOxSELCTIVE CATALYTICREDUTION, AMMONIA SLIP 5PPMVD @ 3%O2 7PPMVD@3% O2BACTPSDCA-093812/2/1999 BOILER, (3)NATURALGAS 33.9 MMBTU/H NOxHONEYCOMB TYPECATALYST BED WITHANHYDROUS AMMONIAINJECTION GRID (SCR) 7 PPMVD LAER 0.0085 LB/MMBTU0.0085CA-091812/2/1999CLAYTON WATER-TUBEBOILERNATURALGAS 4.29 MMBTU/H NOxULTRA LOW-NOX BURNERSYSTEM 12PPMVD @3% O2BACTPSD 0.015 LB/MMBTU0.015CA-091911/23/1999 BOILER, FIRE TUBENATURALGAS 31.5 MMBTU/H NOxCOEN LOW-NOX BURNER,PEERLESS MFG. COMPANYSELECTIVE CATALYTICREDUCTION SYSTEM WITHNH3 INJECTION 7PPMVD @3% O2BACTPSD 0.0085 LB/MMBTU0.0085OK-005110/1/1999 AUXILIARY BOILERNATURALGAS NOx LOW NOX BURNERS 0.049 LB/MMBTUBACTPSD 0.049 LB/MMBTU0.049MA-00299/29/1999 BOILER, AUXILIARYNATURALGAS 96 MMBTU/H NOx SCR 3.4 LB/HBACTPSD 0.035 LB/MMBTU0.035CA-09489/9/1999 BOILER, (2)NATURALGAS 8.18 MMBTU/H NOx LOW NOX BURNERS 15 PPMVD LAER 0.018 LB/MMBTU0.018CO-00415/6/1999BOILER NO.2, TEST MINEHOT WATER (1)NATURALGAS 51.08 MMBTU NOxLOW NOX COMBUSTIONSYSTEM. NO ADD-ONCOSTS. COSTS PART OFOPERATION. 0.05 LB/MMBTUBACTPSD 0.05 LB/MMBTU0.05page 63 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40A: Small Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for Statistical AnalysisRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsNon-BACTlb/MMBtuLimitsCO-00405/6/1999INDUSTRIAL BOILER,NATURAL GASNATURALGAS 80.8 MMBTU/H NOxLOW NOX COMBUSTIONSYSTEM. CAPITAL COSTSARE INCLUDED INEQUIPMENT COSTS;ANNUALIZED COSTS AREINCLUDED IN OPERATIONAND MAINTENANCE 0.05 LB/MMBTUBACTPSD 0.05 LB/MMBTU0.05NJ-00422/5/1999 BOILER 1 (NATURAL GAS)NATURALGAS 84.4 MMBTU/H NOx 33.8 LB/HBACTPSD 0.4 LB/MMBTU 0.4 LB/MMBTU0.4MS-004110/27/1998 BOILER, NATURAL GASNATURALGAS 99 MMBTU/H NOxLOW NOX BURNER ANDFLUE GAS RECIRCULATION.EMISSION LIMIT BASIS ISPSD AND NSPS. 0.042 LB/MMBTUBACTPSD 0.042 LB/MMBTU0.042TX-030010/13/1998 GLYCOL REBOILER NAT GAS NOx NONE INDICATED 0.55 LB/HOtherCase-byCase 2.41 T/YRIN-01048/14/1998BOILERS, REFINERY &HYDROGEN PLANTREFORMERNATURALGAS 10 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION 0.0365 LB/MMBTUBACTPSD 0.0365 LB/MMBTU0.0365ND-00187/9/1998BOILER, NEBRASKA, NATGASNATURALGAS 28 MMBTU/H NOx 5.8 LB/HBACTPSD 0.21 LB/MMBTU0.21IA-00486/1/1998 BOILER, BACKUP 77 MMBTU/H NOx 13.6 LB/HOtherCase-byCase 0.18 LB/MMBTU0.18WY-00424/3/1998BOILER, AUXILIARY,NATURAL GAS 22.89 MMBTU/H NOx 2.3 LB/HOtherCase-byCase 0 0*LA-01122/13/1998 BOILER NO. 1NATURALGAS 95 MMBTU/H NOx LOW NOX BURNERS 4.75 LB/HBACTPSD 20.81 T/YR 0.05 LB/MMBTU0.05WY-00342/6/1998 BOILER, NATURAL GASNATURALGAS 100 MMBTU/H NOxLOW NOX" BURNERSYSTEM" 0.038 LB/MMBTU LAER 0 0PA-014911/26/1997 HEAT RECOVERY BOILERNGSUPPLEMENT 24000LB/HRSTEAM NOx 0.1 LB/MMBTUOtherCase-byCase 5.03 LB/HR 0.1 LB/MMBTU0.1AL-01406/19/1997BOILER, NATURAL GASFIRED, 2NATURALGAS 11.7 MMBTU/H NOxCLEAN FUEL, LOW NOXBRUNERS 0.03 LB/MMBTUBACTPSD 0.7 LB/H 0.03 LB/MMBTU0.03AL-01396/19/1997BOILER, NATURAL GASFIRED, 2NATURALGAS 13.4 MMBTU/H NOxLOW NOX BURNERS, CLEANFUEL 0.03 LB/MMBTUBACTPSD 0.8 LB/H 0.03 LB/MMBTU0.03KY-00685/29/1997 BOILER (NATURAL GAS)NATURALGAS 96 MMBTU/H NOx N/A 0.1 LB/MMBTUBACTPSD 0.1 LB/MMBTU0.1IA-00545/20/1997 BOILER #2 B2NATURALGAS 2.3 MMBTU/H NOxLOW NOX BURNER FLUEGAS RECIRC. ADDITIONALEMISSION LIMIT: 70 PPM 6.8 LB/HBACTPSD 11.79 T/YR 3 LB/MMBTU3IA-00545/20/1997 BOILER #1NATURALGAS 2.3 MMBTU/H NOxLOW NOX BURNER, FLUEGAS RECIRC. 6.81 LB/HBACTPSD 11.79 T/YR 3 LB/MMBTU3IA-00545/20/1997 BOILER #3 B3NATURALGAS 2.3 MMBTU/HR NOxLOW NOX BURNER, FLUEGAS RECIRC. ADDITIONALEMISSION LIMIT: 70 PPM 6.81 LB/HBACTPSD 11.79 T/YR 3 LB/MMBTU3IA-00545/20/1997 HIGH PRESSURE BOILER #1NATURALGAS 0.3 MMBTU/H NOxADDITIONAL EMISSIONLIMIT: 130 PPM 1.66 LB/HBACTPSD 5.96 T/YR 5.5 LB/MMBTU5.5AR-00193/4/1997BOILER,COGENERATION/WASTEHEAT RECOVERYNATURALGAS 68 MMBTU/H NOx LOW NOX COMBUSTORS 25PPM @15% O2BACTPSD 0 0 LB/MMBTUIN-01002/13/1997BOILERS (2), NATURAL GASFIRED, BH NO. 2NATURALGAS 76 MMBTU/H NOx LOW NOX BURNERS 6.08 LB/HBACTPSD 0.04 LB/MMBTU0.04IN-01002/13/1997BOILERS (3), NATURAL GASFIRED, BH NO. 1NATURALGAS 76 MMBTU/H NOx LOW NOX BURNERS 9.12 LB/HBACTPSD 0.04 LB/MMBTU0.04CA-08021/27/1997PVI INDUSTRIES MODEL 3500BOILERNATURALGAS 2.8 MMBTU/HR NOxOPERATION LIMITED TO80% UTILIZATION.RECORDKEEPINGREQUIRED FORCOMPLIANCE VERIFICATION 0NONUMERICLIMIT LAER 0 0CA-07751/15/1997CLAYTON INDUSTRIESMODEL SEG-204-2-LNBBOILERNATURALGAS 8.1 MMBTU/HR NOxPREMIXED LEAN BURNCOMBUSTIONTECHNOLOGY 0.012 MMBTU/HR LAER 0 0NJ-00451/14/1997 BOILERS - NAT GAS (3)NATURALGAS 99.5 MMBTU/H NOx ULTRA LOW-NOX BURNERS 1.1 LB/HOtherCase-byCase 0.011 LB/MMBTU 0.011 LB/MMBTU0.011page 64 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40A: Small Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleUsed for Statistical AnalysisRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitBACTlb/MMBtuLimitsNon-BACTlb/MMBtuLimitsCA-079012/30/1996NEBRASKA BOILER, MODELNS-B-40NATURALGAS 31.2 MMBTU/HR NOxLOW-NOX BURNER, FLUEGAS RECIRCULATION (FGR) 0.036 LB/MMBTU LAER 0.052 LB/MMBTU 0.036 LB/MMBTU0.036IN-007310/31/1996BOILERS, NATURAL GASFIRED 67.5 MMBTU/H NOx 81 LB/MMCFBACT-PSD 0 0CA-072210/24/1996 TWO HOT-WATER BOILERSPROPANE(LPG) 8.4MMBTU/HR/UNIT NOxLOW EMISSIONSFLAMELESS BURNER 15PPMVD AT3%OXYGENOtherCase-byCase 0.15 LB/HR/UNIT 0CA-07369/19/1996300 HP BOILER USED AS ABACKUPPUCQUALITYNAT GAS 10 MMBTU/HR NOx NO CONTROL 0.106 LB/MMBTU LAER 25 LB/DAY 0.106 LB/MMBTU0.106AZ-00329/1/1996 BOILERS (10) 54 MMBTU NOxLOW NOX BURNERS < 50PPM NOX 49 TPYOtherCase-byCase 0 0SC-00418/14/1996 BOILERS, (2)NATURALGAS 95 MMBTU/H NOxLOW NOX BURNER ANDFLUE GAS RECIRCULATION 24LB/H EA.BOILERBACTPSD 0 0IN-00698/9/1996BOILERS, NATURAL GASFIRED (6)NATURALGAS 58 MMBTU/H NOxLOW NOX BURNERS & FUELSPEC: USE OF NATURALGAS AS FUEL 0.1 LB/MMBTUBACTPSD 0 0.1 LB/MMBTU0.1GA-00634/3/1996 BOILER, NATURAL GASNATURALGAS 60 MMBTU/H NOxDRY LOW NOX BURNERWITH FGR 0.1 LB/MMBTUBACTPSD 0 0.1 LB/MMBTU0.1NJ-00463/7/1996BOILERS 4&5, COMBUSTIONCONTROLS, OXYGEN TRIM,ETCNATURALGAS 94 MMBTU/H NOx LOW NOX BURNER 4.76 LB/HBACTPSD 0.0506 LB/MMBTU0.0506AZ-00282/1/1996 BOILER, GAS-FIREDNATURALGAS 42 MMBTU/HR NOxFLUE GAS RECIRCULATION(FGR) NOX NOT TO EXCEED30 PPM 49 TPYBACTPSD 0 0IN-00681/19/1996 BOILERS, NATURAL GASNATURALGAS 93.9 MMBTU/H NOx LOW-NOX BURNER 6.94 LB/HBACTPSD 0 0.07 LB/MMBTU0.07BACT-PSD NOx lb/MMBtu Emission LimitsMIN0.0085lb/MMBtu MIN0.0085lb/MMBtuMAX5.5lb/MMBtu MAX0.23lb/MMBtuMEDIAN0.050lb/MMBtu MEDIAN0.036lb/MMBtuCOUNT97CASES COUNT35CASESRBLC NOx BACT Limits SummaryOther (non-BACT) NOx lb/MMBtu Emission Limitspage 65 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40B: Large Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitWY-0035 10/13/1997BOILER, NATURAL GASNATURALGAS431.6 MMBTU/H NOxLOW NOX" BURNERS WITH16% FLUE GASRECIRCULATION"0.05LB/MMBTU BACT-PSD21.58LB/H0.05LB/MMBTUAZ-0046 4/14/2005ATMOSPHERIC CRUDE CHARGEHEATERNATURALGAS ORREFINERYFUEL GAS346 MMBTU/H NOxLOW NOX BURNERS ANDSELECTIVE CATALYTICREDUCTION0.0125LB/MMBTU BACT-PSD0.0125LB/MMBTUAZ-0046 4/14/2005BUTANE CONVERSION UNITDEHYDROGENATION REACTORCHARGE HEATERREFINERYFUEL GASORNATURALGAS311 MMBTU/H NOxLOW NOX BURNERS ANDSELECTIVE CATALYTICREDUCTION0.0125LB/MMBTU BACT-PSD0.0125LB/MMBTUAZ-0046 4/14/2005BUTANE CONVERSION UNITDEHYDROGENATION REACTORINTERHEATERREFINERYFULE GASORNATURALGAS328 MMBTU/H NOxLOW NOX BURNERS ANDSELECTIVE CATALYTICREDUCTION0.0125LB/MMBTU BACT-PSD0.0125LB/MMBTUAZ-0046 4/14/2005STEAM BOILERS NOS. 1 AND 2NATURALGAS419 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION0.0125LB/MMBTU BACT-PSD0.0125LB/MMBTUWA-0301 4/20/2005BOILER, NATURAL GASNATURALGAS363 MMBTU/H NOxULNB + FGR10.1LB/H BACT-PSD0.028LB/MMBTUAL-0160 6/7/2000BOILER, NAT GASNATURALGAS378 MMBTU/H NOxLOW NOX BURNERS WITHFLUE GAS RECIRCULATION.0.036LB/MMBTU BACT-PSD0.036LB/MMBTUOR-0024 1/27/1998AUXILLIARY BOILERNATURALGAS400 MMBTU/H NOxLOW NOX BURNER ANDFLUE GAS RECIRCULATION30PPMDV @3%O2BACT-PSD14.4LB/H0.036LB/MMBTULA-0177 9/8/2005NATURAL GAS-FIRED BOILERNATURALGAS363 MMBTU/H NOxLOW NOX BURNERS WITHFLUE GAS RECIRCULATION14.53LB/H BACT-PSD63.64T/YR0.04LB/MMBTUSC-0091 7/3/2003BOILER, NATURAL GASNATURALGAS550 MMBTU/H NOxLOW NOX BURNERS, FLUEGAS RECIRCULATION0.04LB/MMBTU BACT-PSD0.04LB/MMBTUSC-0071 4/9/2001BOILERS, AUXILIARY, NATURALGAS, (2)NATURALGAS350 MMBTU/H NOxLOW NOX BURNER WITHFGR ALONG WITH HAVINGGOOD COMBUSTIONPRACTICES0.04LB/MMBTU BACT-PSD0.04LB/MMBTUTX-0419 3/22/2000BOILER, AUXILIARY, (3)NATURALGAS380 MMBTU/H NOxGOOD COMBUSTIONPRACTICE22.8LB/H BACT-PSD0.04LB/MMBTU*LA-0171 12/22/1998BOILER, HIGH PRESSURE, B-76001NATURALGAS418 MMBTU/H NOxULTRA LOW-NOX BURNERS11.5LB/H BACT-PSD25.2T/YR0.04LB/MMBTUNE-0024 6/22/2004BOILER D (NO. 21)NATURALGAS276.67 MMBTU/H NOxLOW NOX BURNERS ANDINDUCED FLUE GASRECIRCULATION AT 16%.0.05LB/MMBTUOther Case-by-Case0.05LB/MMBTUAL-0199 11/15/2002BOILER, 300 MMBTU/H, NATURALGASNATURALGAS300 MMBTU/H NOxLOW NOX BURNERS0.05LB/MMBTU BACT-PSD15LB/H0.05LB/MMBTUTX-0373 10/24/2002F BOILER STACK, EYFBLRST NAT GAS370 MMBTU/H NOxUSING ONLY GASEOUSFUELS, DRY LOW NOXCOMBUSTORS & FLUE GASRECIRCULATIONTECHNOLOGY25.9LB/H BACT-PSD97.2T/YR0.05LB/MMBTUNE-0013 9/30/1999BOILERNATURALGAS ONLY276.67 MMBTU/H NOxLOW NOX BURNERS,INDUCED FUEL GASRECIRCULATION WITH 110%OF TOTAL EXHAUST FLOW0.05LB/MMBTU BACT-PSD0.05LB/MMBTUIL-0060 12/24/1998BOILER (11), GAS FIREDNATURALGAS350 MMBTU/H NOxLOW-NOX BURNERS; FUELSELECTION0.05LB/MMBTU BACT-PSD0 0.05LB/MMBTUTX-0323 12/22/1998EXIST STEAM BOILER, PHASE 1,2&3, STK-801NAT GAS352.2 MMBTU/H NOxNONE INDICATED17.61LB/HOther Case-by-Case24.75T/YR0.05LB/MMBTUTX-0237 9/8/1998HEATERS, FRESH FEEDCRACKING, (8)NATURALGAS445.41 MMBTU/H NOxLOW NOX BURNERS35.63LB/H BACT-PSD122.91T/YR0.05LB/MMBTUTX-0237 9/8/1998BOILER, SUPPLEMENTAL, (2)NATURALGAS416 MMBTU/H NOxPARTIAL FLUE GASRECIRCULATION (FGR)24.96LB/H BACT-PSD91.1T/YR0.05LB/MMBTULA-0115 11/3/1997BOILERNATURALGAS300 MMBTU/H NOxLOW NOX BURNER ANDINTERNAL FLUE GASRECIRCULATION (FGR)0.05MMBTU/H BACT-PSD0 0.05LB/MMBTUGA-0084 6/16/1997BOILER (NATURAL GAS)NATURALGAS352 MMBTU/H NOxLOW NOX BURNER, FLUEGAS RECIRCULATION0.05LB/MMBTU-NAT GASBACT-PSD0.05LB/MMBTU-NAT GASpage 66 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-40B: Large Gas Fired Boilers and Heaters- NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit 2STDEmissionLimitSTD LimitUnitAL-0085 5/10/1996POWER BOILER, NATURAL GASNATURALGAS346.4 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION(FGR)0.05LB/MMBTU BACT-PSD17.32LB/H0.05LB/MMBTU*WI-0076 10/28/1993BOILER, NATURAL GASNATURALGAS330 MMBTU/H NOxLOW NOX BURNER, FLUEGAS RECIRCULATION0.05LB/MMBTU BACT-PSD0 0.05LB/MMBTUTX-0293 6/16/1999(2) AUX PACKAGE BOILERS,EPN103 &104NAT GAS405 MMBTU/H NOxFIRED ONLY WITH PIPELINEQUALITY NATURAL GAS11.2T/YR BACT-PSD21.9LB/H0.054LB/MMBTUTX-0419 3/22/2000BOILER, AUXILIARY, (3) PROCESSGASNATURALGAS380 mmbtu/h NOxGOOD COMBUSTIONPRACTICE0.06LB/MMBTU BACT-PSD0.06LB/MMBTULA-0124 11/23/1999TEMPORARY BOILER NO.1 ANDNO.2 (EACH)NATURALGAS356 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION.21.36LB/H BACT-PSD74.85T/YR0.06LB/MMBTUTX-0310 1/6/1999BOILER, B108 NAT GAS264 MMBTU/H NOxNONE INDICATED15.88LB/HOther Case-by-Case69.55T/YR0.06LB/MMBTUTX-0371 2/4/2000(3) AUXILIARY BOILERS 1-3, AB1-3 NAT GAS315 MMBTU/H NOxNONE INDICATED18.84LB/H BACT-PSD0.06LB/MMBTUOH-0271 7/27/2004BOILER (1)NATURALGAS281 MMBTU/H NOxLOW NOX BURNERS WITHFLUE GAS RECIRCULATION539.52LB/D BACT-PSD98.5T/YR0.08LB/MMBTUMT-0028 11/6/2001BOILER, NATURAL GASNATURALGAS358 MMBTU/H NOxFLUE GAS RECIRCULATIONAND LOW NOX BURNERS29.7LB/HOther Case-by-Case0.08LB/MMBTU0.08LB/MMBTU*LA-0171 12/22/1998CTU HEATER, NO.3, H-1101NATURALGAS264 MMBTU/H NOxULTRA LOW-NOX BURNERS19LB/H BACT-PSD79.9T/YR0.08LB/MMBTUTX-0237 9/8/1998FURNACE, RECYCLE ETHANECRACKINGNATURALGAS342.5 MMBTU/H NOxLOW NOX BURNERS27.4LB/H BACT-PSD94.52T/YR0.08LB/MMBTULA-0105 10/16/1996UTILITY BOILERNATURALGAS320 MMBTU/H NOxLOW NOX BURNERS0.08LB/MMBTU BACT-PSD25.56LB/H0.08LB/MMBTUTX-0416 11/24/1999BOILER, PHENOL/ACETONE PLANTNATURALGAS357 MMBTU/H NOxGOOD COMBUSTIONPRACTICE30.24LB/H BACT-PSD132.47T/YR0.085LB/MMBTUIA-0045 5/29/1998BOILER, NATURAL GASNATURALGAS278 MMBTU/H NOxLOW NOX BURNER WITHSTEAM INJECTION0.1LB/MMBTU BACT-PSD27.8LB/H0.1LB/MMBTUMS-0029 9/10/1996BOILER, NATURAL GAS400 MMBTU/H NOxLOW NOX BURNERS WITHFLUE GAS RECIRCULATION(FGR)0.1LB/MMBTU BACT-PSD0 0.1LB/MMBTUTX-0373 10/24/2002C BOILER STACK, EY003ST NAT GAS320 MMBTU/H NOxNONE INDICATED38.4LB/HOther Case-by-Case168.2T/YR0.12LB/MMBTUAL-0160 6/7/2000BOILER, BACKUP OILNATURALGAS378 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION0.15LB/MMBTU BACT-PSD0.15LB/MMBTUOR-0037 12/29/2000AUXILIARY BOILER NAT GAS400 MMBTU/H NOxLOW NOX BURNERS ANDFLUE GAS RECIRCULATION60PPMVD @3% O2Other Case-by-Case80PPMVD @ 3%O20.2LB/MMBTUOR-0032 10/13/1998AUXILIARY BOILERSNATURALGAS720 MMBTU/H NOx 0.2LB/MMBTU BACT-PSD0.2LB/MMBTUBACT-PSD PM lb/MMBtu Emission LimitsMIN0.0125lb/MMBtu MIN0.05lb/MMBtuMAX0.2lb/MMBtu MAX0.2lb/MMBtuMEDIAN0.05lb/MMBtu MEDIAN0.07lb/MMBtuCOUNT36CASES COUNT6CASESRBLC NOxBACT Limits SummaryOther (non-BACT) PM lb/MMBtu EmissionLimitspage 67 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitAR-00193/4/1997 BOILER, COGENERATION/WASTE HEAT RECOVERYNATURALGAS 68 MMBTU/H COGOOD COMBUSTIONPRACTICES 10.6 LB/HBACTPSD 0 0OH-02582/15/2001 BOILERS (4)NATURALGAS 20.9 MMBTU/H CO 0.23 LB/H N/A 1.01 T/YR 0.011IA-006212/20/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H CO CATALYTIC OXIDATION 0.0164 LB/MMBTUOtherCase-byCase 0.0164NM-004212/29/2000 AUX-1 AUXILARY BOILERNATURALGAS 44.1 MMBTU/H COGOOD COMBUSTIONCONTROL, NATURAL GASCOMBUSTION 6.6 LB/HBACTPSD 0.022OR-00403/12/2003 BOILER, AUXILIARY, NATURAL GASNATURALGAS 50000 LB/H CO 0.035 LB/MMBTUBACTPSD 0.035ND-00187/9/1998 BOILER, NEBRASKA, NAT GASNATURALGAS 28 MMBTU/H CO 1 LB/HBACTPSD 0.036NV-00396/1/2001 AUXILIARY BOILERSNATURALGAS 44.1 MMBTU/H CO GOOD COMBUSTION CONTROL 100PPMVD@3%O2BACTPSD 1.6 LB/H 0.036WI-02268/27/2004 NATURAL GAS FIRED BOILERNATURALGAS 46.2 MMBTU/H CO BOILER DESIGN 1.67 LB/H N/A 0.036NJ-00422/5/1999 BOILER 1 (NATURAL GAS)NATURALGAS 84.4 MMBTU/H CO NONE LISTED 3 LB/HBACTPSD 37PPMVD@ 7% O2 0.036NJ-00451/14/1997 BOILERS - NAT GAS (3)NATURALGAS 99.5 MMBTU/H CO NONE 3.6 LB/HBACTPSD 0.036LB/MMBTU 0.036CA-09422/15/2000 BOILER, NATURAL GASNATURALGAS 6 MMBTU/H CO 50 PPMVD LAER 0.037CA-09453/17/2000 BOILERNATURALGAS 16.3 MMBTU/H CO 50PPM @ 3%O2 LAER 322 LB/MO 0.037CA-09411/28/2000 BOILER, NATURAL GASNATURALGAS 16.3 MMBTU/H CO FLUE GAS RECIRCULATION 50 PPMVD LAER 0.037CA-09467/12/2000 BOILERNATURALGAS 21 MMBTU/H CO 50 PPMVD LAER 0.037CA-09403/15/2000 BOILER, PORTABLENATURALGAS 28.8 MMBTU/H CO GOOD COMBUSTION PRACTICE 50 PPMVD LAER 0.037*WA-029210/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H CO 50PPM @ 3%O2BACTPSD 1.07 LB/H 0.037OH-025212/28/2004 BOILERS (2)NATURALGAS 30.6 MMBTU/H CO 1.13 LB/HBACTPSD 1.69T/ROLLING 12-MONTHS 0.037GA-010110/23/2002 BOILER, AUXILIARYNATURALGAS 31.4 MMBTU/H CO GOOD COMBUSTION PRACTICE 0.037 LB/MMBTUBACTPSD 0.037CA-091911/23/1999 BOILER, FIRE TUBENATURALGAS 31.5 MMBTU/H COGOOD COMBUSTIONPRATICES. 50PPMVD @3% O2BACTPSD 0.037OK-00706/13/2002 AUXILIARY BOILERNATURALGAS 33 MMBTU/H COBOILER DESIGN AND GOODOPERATING PRACTICES 0.037 LB/MMBTUBACTPSD 0.037CA-093812/2/1999 BOILER, (3)NATURALGAS 33.9 MMBTU/H CO GOOD COMBUSTION PRACTICE 50 PPMVD LAER 0.037OR-003912/30/2003 BOILERS, AUXILIARY, NATURAL GAS, (2)NATURALGAS 80 MMBTU/H CO GOOD COMBUSTION 0.037 LB/MMBTUBACTPSD 0.037AR-00708/23/2002 AUXILIARY BOILERNATURALGAS 33 MMBTU/H CO GOOD COMBUSTION PRACTICE 0.04 LB/MMBTUBACTPSD 0.04GA-00634/3/1996 BOILER, NATURAL GASNATURALGAS 60 MMBTU/H CO COMPLETE COMBUSTION 0.05 LB/MMBTUBACTPSD 0 0.05CA-10053/16/2000 BOILER, 5.05 MMBTU/HNATURALGAS 5.05 MMBTU/H CO 50PPMV @ 3%O2BACTPSD 0.06MN-005412/4/2003 BOILER, COMMERCIALNATURALGAS 70 MMBTU/H CO GOOD COMBUSTION 0.06 LB/MMBTUBACTPSD 0.06*LA-01122/13/1998 BOILER NO. 1NATURALGAS 95 MMBTU/H COGOOD DESIGN, PROPEROPERATING PRACTICES AND2% EXCESS O2 5.7 LB/HBACTPSD 24.97 T/YR 0.06IN-010811/21/2003 BOILER, NATURAL GAS, (2)NATURALGAS 34 MMBTU/H COGOOD COMBUSTIONPRACTICES, NATURAL GAS 0.061 LB/MMBTUBACTPSD 0.061CA-100612/16/1999 BOILER, 20.9 MMBTU/HNATURALGAS 20.9 MMBTU/H CO 100PPMVD @3% O2BACTPSD 0.07page 68 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -CONM-00446/27/2002 AUXILIARY BOILERS (AUX-1 AND AUX-2)NATURALGAS 33 MMBTU/H CODRY LOW NOX (DLN)TECHNOLOGY, GOODCOMBUSTION PRACTICES 4.9 LB/HBACTPSD 0.07OK-00725/6/2002 AUXILIARY BOILERNATURALGAS 93 MMBUT/H COBOILER DESIGN AND GOODOPERATING PRACTICES 0.07 LB/MMBTUBACTPSD 0.07AL-017910/3/2001 30 MMBTU/HR AUXILIARY BOILERNATURALGAS 30 MMBTU/H CO EFFICIENT COMBUSTION 0.073 LB/MMBTUBACTPSD 2.2 LB/H 0.073VA-026011/21/2002 AUXILIARY BOILER, (2)NATURALGAS 40 MMBTU/H COGOOD COMBUSTION ANDDESIGN. CLEAN FUEL. 2.9 LB/HBACTPSD 4.38 T/YR 0.073IA-00607/23/2002 AUXILIARY BOILER (48.5 MMBTU/H)NATUALGAS 48.69MILLIONCF/YR CO GCP 0.073 LB/MMBTUBACTPSD 0.073CA-09434/6/2000 BOILERNATURALGAS 6.3 MMBTU/H CO 100 PPMVD LAER 0.074CA-09473/15/2000 BOILERNATURALGAS 7.5 MMBTU/H CO 100 PPMVD LAER 0.074CA-09489/9/1999 BOILER, (2)NATURALGAS 8.18 MMBTU/H CO 100 PPMVD LAER 0.074CA-09443/10/2000 BOILERNATURALGAS 16.3 MMBTU/H CO 100 PPMVD LAER 0.074CA-093912/16/1999 BOILERNATURALGAS 20.9 MMBTU/H COGOOD COMBUSTIONPRACTICES 10 PPMVD LAER 0.074OH-02553/29/2001 BOILER, NATURAL GASNATURALGAS 85.2 MMBTU/H CO 6.3 LB/HBACTPSD 27.6 T/YR 0.074CA-091812/2/1999 CLAYTON WATER-TUBE BOILERNATURALGAS 4.29 MMBTU/H COULTRA LOW-NOX BURNERSYSTEM 100PPMVD @3% O2BACTPSD 0.075NJ-00463/7/1996BOILERS 4&5, COMBUSTION CONTROLS, OXYGENTRIM, ETCNATURALGAS 94 MMBTU/H CO N/A 7.28 LB/HBACTPSD 0.0774WI-02071/21/2004 BOILER, S52/B52, 11 MMBTU/HNATURALGAS 11 MMBTU/H CONATURAL GAS / PROPANE ;GOOD COMBUSTION CONTROL 0.08 LB/MMBTUBACTPSD 0.08TX-035412/19/2002 (2) STEAM BOILERS, X-426A AND X-426BNATURALGAS 15.8 MMBTU/H CO NONE INDICATED 1.33 LB/HOtherCase-byCase 5.81 T/YR 0.08PA-02161/13/2003 BOILER, DRAP LINENATURALGAS 33.5 MMBTU/H CO 2.75 LB/HOtherCase-byCase 12.08 T/H 0.08WI-02071/21/2004 BOILER, S53 / B53, 34 MMBTU/HNATURALGAS 34 MMBTU/H CONATURAL GAS / PROPANE;GOOD COMBUSTION CONTROL 0.08 LB/MMBTUBACTPSD 0.08AZ-004712/1/2004 AUXILIARY BOILERNATURALGAS 38 MMBTU/H CO 0.08 LB/MMBTUBACTPSD 0.08AL-01692/5/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H COGOOD COMBUSTIONPRACTICES 0.08 LB/MMBTUBACTPSD 3.2 LB/H 0.08VA-02713/24/2003 BOILER NO. 1NATURALGAS 43.2 MMBTU/H COCONTINUOUS EMISSIONMONITORING SYSTEM ANDGOOD COMBUSTIONPRACTICES. 3.56 LB/H N/A 0.08TX-02744/3/2000 AUXILIARY BOILERNATURALGAS 54.01 MMBTU/H CO NONE INDICATED 4.45 LB/H N/A 0.39 T/YR 0.08TX-037811/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H CO NONE INDICATED 4.84 LB/HOtherCase-byCase 21.19 T/YR 0.08NV-00375/14/2004 AUXILIARY BOILERNATURALGAS 60 MMBTU/H COEFFECTIVE COMBUSTIONSYSTEM DESIGN, 10:1TURNDOWN CAPABILITY, ANDLNB TECHNOLOGY 0.08 LB/MMBTU LAER 4.8 LB/H 0.08WI-02071/21/2004 BOILER, S50/B50, 60 MMBTU/HNATURALGAS 60 MMBTU/H CONATURAL GAS / PROPANE;GOOD COMBUSTION CONTROL 0.08 LB/MMBTUBACTPSD 0.08WI-02071/21/2004 BOILER, S51/B51, 80 MMBTU/HNATURALGAS 80 MMBTU/H CONAT. GAS / PROPANE, GOODCOMBUSTION CONTROL 0.08 LB/MMBTUBACTPSD 0.08VA-02619/6/2002 AUXILIARY BOILERNATURALGAS 80 MMBTU/H COGOOD COMBUSTIONPRACTICES. 6.42 LB/HBACTPSD 9.63 T/YR 0.08MA-00299/29/1999 BOILER, AUXILIARYNATURALGAS 96 MMBTU/H CO OXIDATION CATALYST 7.7 LB/HBACTPSD 100PPM @15% O2 0.08WI-022710/13/2004 NATURAL GAS FIRED AUXILLIARY BOILERNATURALGAS 97.1 MMBTU/H CONATURAL GAS FUEL, GOODCOMBUSTION PRACTICES 7.77 LB/HBACTPSD 0.08page 69 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -COIN-009512/7/2001 AUXILLIARY BOILERNATURALGAS 21 MMBTU/H COGOOD COMBUSTIONPRACTICES 0.082 LB/MMBTUBACTPSD 0.082IN-011010/5/2001 BOILER, AUXILIARY, NATURAL GASNATURALGAS 35 MMBTU/H COCLEAN FUEL, GOODCOMBUSTION PRACTICE 0.082 LB/MMBTUBACTPSD 2.87 LB/H 0.082IN-00876/6/2001 AUXILARY BOILER, NATURAL GAS (2)NATURALGAS 46 MMBTU/H COGOOD COMBUSTION. LIMIT ISFOR EACH BOILER. 0.082 LB/MMBTUBACTPSD 3.8 LB/H 0.082OH-025712/27/2001 AUXILIARY BOILERNATURALGAS 76 MMBTU/H CO 6.86 LB/HBACTPSD 10.28 T/YR 0.082NC-00941/9/2002 BOILER, AUXILIARY, NATURAL GASNATURALGAS 83 MMBTU/H COGOOD C OMBUSTIONPRACTICES AND DESIGN 6.84 LB/HBACTPSD 0.082OK-005110/1/1999 AUXILIARY BOILERNATURALGAS COBOILER DESIGN & GOODOPERATING PRACTICES 0.082 LB/MMBTUBACTPSD 0.082AR-00866/11/2004 VTD BOILERNATURALGAS 50 MMBTU/H CO GOOD COMBUSTION PRACTICE 4.2 LB/HBACTPSD 18.1 T/YR 0.0824TX-040811/22/2002 AUXILIARY BOILER, (2)NATURALGAS 6 MMBTU/H CO 0.5 LB/HBACTPSD 2.16 T/YR 0.083WA-02911/3/2003 BOILER, AUXILIARYNATURALGAS 55.3 MMBTU/H CO 111PPMDV @3% O2OtherCase-byCase 4.6 LB/H 0.083OK-00562/12/2002 AUXILIARY BOILERSNATURALGAS 0 COGOOD COMBUSTIONPRACTICES & DESIGN 0.084 LB/MMBTUBACTPSD 0.084OK-00745/1/2001 AUXILIARY BOILERNATURALGAS 27.5 MMBTU/H COGOOD OPERATING PRACTICESAND DESIGN 0.084 LB/MMBTUBACTPSD 0.084AL-019210/18/2002 BOILERS, NATURAL GAS, (3)NATURALGAS 30 MMBTU/H COCLEAN FUEL, GOODCOMBUSTION PRACTICES. 2.52 LB/HBACTPSD 0.084LB/MMBTU 0.084OK-00552/12/2002 AUXILIARY BOILERNATURALGAS 31 MMBTU/H CO COMBUSTION CONTROL 0.084 LB/MMBTUBACTPSD 0.084MN-00537/15/2004 BOILER, NATURAL GAS (1)NATURALGAS 40 MMBTU/H CO GOOD COMBUSTION. 0.084 LB/MMBTUBACTPSD 0.084OK-00448/16/2001 AUXILIARY BOILERS, (2)NATURALGAS 48 MMBTU/H CO COMBUSTION CONTROL 7.91 LB/HBACTPSD 34.64 T/YR 0.084OH-026510/16/2001 BOILER, NATURAL GASNATURALGAS 49 MMBTU/H CO 4.12 LB/HBACTPSD 1.65 T/YR 0.084IA-00584/10/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H CO 0.084 LB/MMBTUOtherCase-byCase 25.1 T/YR 0.084OH-02489/24/2002 BOILERNATURALGAS 99 MMBTU/H CO 8.32 LB/HBACTPSD 0.084LB/MMBTU 0.084OK-004310/22/2001 AUXILIARY BOILERNATURALGAS 30 MMBTU/H COBOILER DESIGN & GOODOPERATING PRACTICES 0.085 LB/MMBTUBACTPSD 0.085OK-00903/21/2003 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H COBOILER DESIGN AND GOODOPERATING PRACTICES 0.085 LB/MMBTUBACTPSD 0.085AL-01681/12/2001 BOILERNATURALGAS 83 MMBTU/H CO EFFICIENT COMBUSTION 0.085 LB/MMBTUBACTPSD 7.02 LB/H 0.085CA-079012/30/1996 NEBRASKA BOILER, MODEL NS-B-40NATURALGAS 31.2 MMBTU/HR CO GOOD COMBUSTION 0.089 LB/MMBTU LAER 0 0.089*AZ-00499/4/2003 AUXILIARY BOILER FOR GE TURBINENATURALGAS 41 MMBTU/H CO 0.09 LB/MMBTUBACTPSD 0.09AL-01913/23/2004 BOILERS, NATURAL GAS, (3)NATURALGAS 50 MMBTU/H CO CLEAN FUEL 4.5 LB/HBACTPSD 0.09LB/MMBTU 0.09CO-00415/6/1999 BOILER NO.2, TEST MINE HOT WATER (1)NATURALGAS 51.08 MMBTU CO GOOD COMBUSTION 0.09 LB/MMBTUBACTPSD 0.2 T/YR 0.09CO-00405/6/1999 INDUSTRIAL BOILER, NATURAL GASNATURALGAS 80.8 MMBTU/H COGOOD COMBUSTIONMANAGEMENT. CAPITAL ANDANNUALIZED COSTS AREINCLUDED IN OPERATION ANDMAINTENANCE 0.09 LB/MMBTUBACTPSD 0.09TN-01534/3/2002 BOILER, NO. 9NATURALGAS 95 MMBTU/H CO 0.09 LB/MMBTUBACTPSD 0.09WV-00216/9/2004 BOILER, NATURAL GAS, 39.00 MMBTUNATURALGAS 365 MMSCF/YR CO 3.5 PPHBACTPSD 15.34 T/YR 0.09GA-00983/24/2003 AUXILIARY BOILERNATURALGAS 83 MMBTU/H CO 0.093 LB/MMBTUOtherCase-byCase 0.093OH-02638/9/2001 AUXILIARY BOILERNATURALGAS 80 MMBTU/H CO 7.84 LB/HBACTPSD 34.3 T/YR 0.098page 70 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -COTX-03641/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H CO NONE INDICATED 0.25 LB/HOtherCase-byCase 0.9 T/YR 0.1TN-01534/3/2002 CCR STABILIZATION REBOILERNATURALGAS 54 MMBTU/H CO 0.1 LB/MMBTUBACTPSD 0.1PA-014911/26/1997 HEAT RECOVERY BOILERNGSUPPLEMENT 24000LB/HRSTEAM CO 0.1 LB/MMBTUOtherCase-byCase 5.03 LB/HR 0.1OH-02548/14/2003 BOILERNATURALGAS 30.6 MMBTU/H CO 3.34 LB/HBACTPSD 7T/ROLLING 12-MONTHS 0.109OH-025111/29/2001 BOILER, NATURAL GASNATURALGAS 91.2 MMBTU/H CO 12.2 LB/H N/A 53.4 LB/H 0.13*AZ-00499/4/2003 AUXILIARY BOILER FOR SIEMENS TURBINESNATURALGAS 55.34 MMBTU/H CO 0.14 LB/MMBTUBACTPSD 0.14*AK-00628/19/2005 NATCO TEG REBOILERNATURALGAS 1.34 MMBtu/hr COGOOD OPERATIONALPRACTICES 0.15 LB/MMBTUBACTPSD 0.15MA-00275/7/2000 AUXILIARY BOILERNATURALGAS 26.6 MMBTU/H CO OXIDATION CATALYST 4 LB/HBACTPSD 0.15AR-00514/1/2002 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H CO GOOD OPERATING PRACTICE 0.15 LB/MMBTUBACTPSD 0.15AR-004012/29/2000 BOILERS, AUXILIARY 2NATURALGAS 44.1 MMBTU/H COPROPER COMBUSTIONPROCEDURES. LB/HR LIMITFOR EACH BOILER. 0.15 LB/MMBTUBACTPSD 6.7 LB/H 0.15VA-025511/18/2002 BOILER, AUXILIARYNATURALGAS 99 MMBTU/H COGOOD COMBUSTIONPRACTICES. 14.9 LB/HOtherCase-byCase 74 T/YR 0.15WY-00567/25/2000 BOILER (AUXILLARY), TRAIN IIINATURALGAS 76.7 MMBTU/H CO 13.4 T/YRBACTPSD 13 LB/H 0.17PA-01652/24/2000 BOILERS, (3)NATURALGAS 90 MMBTU/H CO LOW NOX BURNERS 0.173 LB/MMBTUBACTPSD 0.173IN-00681/19/1996 BOILERS, NATURAL GASNATURALGAS 93.9 MMBTU/H CO LOW-NOX BURNER 19.2 LB/HBACTPSD 0 0.2PA-021012/14/2001 BOILER, (2)NATURALGAS 33.5 MMBTU/H CO GOOD COMBUSTION PRACTICE 400PPMDV @3% O2OtherCase-byCase 0.3OK-007110/25/2001 AUXILIARY BOILERNATURALGAS 22 MMBTU/H CO USE OF NATURAL GAS FUEL 0.37 LB/MMBTUBACTPSD 0.37LA-01741/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H COGOOD EQUIPMENT DESIGNAND PROPER COMBUSTIONTECHNIQUES 36.8 LB/HBACTPSD 24.28 T/YR 0.56VA-02713/24/2003 BOILER NO. 3NAT GASOR DIS OIL 43.2 MMBTU COCONTINUOUS EMISSIONMONITORING SYSTEM ANDGOOD COMBUSTIONPRACTICES. 30.21 T/YR N/A 0.7IN-00865/9/2001 AUXILARY BOILER, NATURAL GAS (2)NATURALGAS 35 MMBTU/H COGOOD COMBUSTION. LB/HLIMIT IS FOR EACH BOILER. 0.824 LB/MMBTUBACTPSD 2.88 LB/H 0.824AR-00777/22/2004 BOILERSNATURALGAS 22 MMBTU/H CO GOOD COMBUSTION PRACTICE 0.84 LB/MMBTUBACTPSD 0.84IA-00545/20/1997 HIGH PRESSURE BOILER #1NATURALGAS 0.3 MMBTU/H CO 1.3 LB/HBACTPSD 5.7 T/YR 4.3IA-00545/20/1997 BOILER #2 B2NATURALGAS 2.3 MMBTU/H COLOW NOX BURNER , FLUE GASRECIRC. 9.9 LB/HBACTPSD 43.36 T/YR 4.3IA-00545/20/1997 BOILER #1NATURALGAS 2.3 MMBTU/H COLOW NOX BURNER, FLEE GASRECIRC. 9.9 LB/HBACTPSD 43.36 T/YR 4.3IA-00545/20/1997 BOILER #3 B3NATURALGAS 2.3 MMBTU/HR COLOW NOX BURNER, FLUE GASRECIRC. 9.9 LB/HBACTPSD 43.36 T/YR 4.3IN-01048/14/1998BOILERS, REFINERY & HYDROGEN PLANTREFORMERNATURALGAS 10 MMBTU/H CO COMBUSTION CONTROL 0.074 MMBTU/HBACTPSD 0.074CA-072210/24/1996 TWO HOT-WATER BOILERSPROPANE(LPG) 8.4MMBTU/HR/UNIT COLOW EMISSIONS FLAMELESSBURNER 50PPMVD AT3% OXYGENOtherCase-byCase 0.31LB/HR/UNIT 0page 71 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -COWI-01818/2/2000 BOILERNATURALGAS 10 MMBTU/H COBACT FOR CO IS DETERMINEDTO BE GOOD COMBUSTIONCONTROL AND THE USE OFNATURAL GAS TO FUEL THEBOILER. NO EMISSION RATELIMIT.BACTPSDTX-038912/31/2002 BACK-UP BOILERNATURALGAS 13.4 MMBUT/H CO 1.11 LB/HOtherCase-byCase 4.85 T/YRCA-102112/7/1999 BOILER: 16.5 MMBTU/HNATURALGAS 16.5 MMBTU/H CO 50PPMVD @3% O2BACTPSDCA-11007/12/2000 BOILER: 5 TO < 33.5 MMBTU/HRNATURALGAS 21 MMBTU/H CO SCR 50PPMVD@3%O2BACTPSDCA-10999/4/2001 BOILER: 5 TO < 33.5 MMBTU/HRNATURALGAS 21.46 MMBTU/H CO ULTRA LOW-NOX BURNER 100PPMD @ 3%O2BACTPSDOH-02764/14/2003 BOILER FOR VACUUM OXYGEN DEGASSER VESSELNATURALGAS 25 MMBTU/H CO 2.06 LB/HBACTPSD 9.02 T/YRVA-024312/1/2002 BOILER, NAT GAS & OIL ` 26.5 MMBTU/H CO EMISSION LIMITS IN T/YR ONLY 9.4 T/YROtherCase-byCaseAL-018110/23/2001 31.4 MMBTU/HR NATURAL GAS FIRED BOILERNATURALGAS 31.4 MMBTU/H CO EFFICIENT COMBUSTION. 0.135 LB/MMBTUBACTPSD 4.71 LB/HAL-018012/11/2001 35 MMBTU/HR NAT. GAS FIRED AUXILIARY BOILERNATURALGAS 35 MMBTU/H CO GOOD COMBUSTION 0.135 LB/MMBTUBACTPSD 4.71 LB/HCA-102310/8/2002 BOILER, 39 MMBTU/HNATURALGAS 39 MMBTU/H CO 100PPMVD @3% 02 N/AAL-01857/12/2002 TWO (2) 40 MMBTU/H AUXILIARY BOILERSNATURALGAS 40 MMBTU/H COGOOD COMBUSTIONPRACTICES 0.082 LB/MMBTUBACTPSD 3.3 LB/HMD-00339/27/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H COEXCLUSIVE USE OF NATURALGAS, ADVANCED DRY LOWNOX BURNERS; GOODCOMBUSTION CONTROLSHEAT INPUT TO THE AUXILIARYBOILERS (2) SHALL BE LIMITEDTO 210,240 MMBTU FOR ANYCONSECUTIVE 12-MONTHPERIODBACTPSDOK-00548/21/2001 BOILERSNATURALGAS 62.77 MMBTU/H COGOODCOMBUSTION/MAINTENANCE 10.81 T/YRBACTPSD 4.39 LB/HTX-036311/13/2000 BOILER NO. 2 NAT GAS CO NONE INDICATED 0.85 LB/HOtherCase-byCase 1.86 T/YRTX-036311/13/2000 BOILER NO 3 NAT GAS CO NONE INDICATED 0.57 LB/HOtherCase-byCase 2.5 T/YRTX-030010/13/1998 GLYCOL REBOILER NAT GAS CO NONE INDICATED 0.14 LB/HOtherCase-byCase 0.61 T/YRBACT-PSD CO lb/MMBtu Emission LimitsMIN 0.022 lb/MMBtu MIN 0.011 lb/MMBtuMAX 4.3 lb/MMBtu MAX 0.7 lb/MMBtuMEDIAN 0.082 lb/MMBtu MEDIAN 0.08 lb/MMBtuCOUNT81CASES COUNT30CASESRBLC CO BACT Limits SummaryOther (non-BACT) CO lb/MMBtuEmission Limitspage 72 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-42: Small Gas Fired Boilers and Heaters - VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitWA-027911/16/1996 NATURAL GAS FIRED BOILERSNATURALGAS 800 HP VOC FUEL SPEC: NATURAL GAS 50.7 LB/DBACTPSD 0 0NJ-00422/5/1999 BOILER 1 (NATURAL GAS)NATURALGAS 84.4 MMBTU/H VOC NONE LISTED 0.2 LB/HBACTPSD 4.4PPMVD@ 7% O2 0.002LB/MMBTUIN-010811/21/2003 BOILER, NATURAL GAS, (2)NATURALGAS 34 MMBTU/H VOCCOMPLIANCE BY USINGNATURAL GAS 0.0026 LB/MMBTUBACTPSD 0.0026LB/MMBTUNJ-00451/14/1997 BOILERS - NAT GAS (3)NATURALGAS 99.5 MMBTU/H VOC NONE 0.33 LB/HBACTPSD 0.0033LB/MMBTU 0.0033LB/MMBTUAL-017910/3/2001 30 MMBTU/HR AUXILIARY BOILERNATURALGAS 30 MMBTU/H VOC EFFICIENT COMBUSTION 0.004 LB/MMBTUBACTPSD 0.1 LB/H 0.004LB/MMBTUVA-025511/18/2002 BOILER, AUXILIARYNATURALGAS 99 MMBTU/H VOCGOOD COMBUSTIONPRACTICES. 0.4 LB/HOtherCase-byCase 2 T/YR 0.004LB/MMBTUOH-02553/29/2001 BOILER, NATURAL GASNATURALGAS 85.2 MMBTU/H VOC 0.35 LB/HBACTPSD 0.0041LB/MMBTU 0.0041LB/MMBTUOK-00465/17/2001 AUXILIARY BOILERNATURALGAS 20 MMBTU/H VOC 0.005 LB/MMBTUBACTPSD 0.005LB/MMBTUOH-02582/15/2001 BOILERS (4)NATURALGAS 20.9 MMBTU/H VOC 0.11 LB/H N/A 0.005LB/MMBTU 0.005LB/MMBTUGA-00634/3/1996 BOILER, NATURAL GASNATURALGAS 60 MMBTU/H VOC COMPLETE COMBUSTION 0.005 LB/MMBTUBACTPSD 0 0.005LB/MMBTUIN-009512/7/2001 AUXILLIARY BOILERNATURALGAS 21 MMBTU/H VOCGOOD COMBUSTIONPRACTICES 0.0054 LB/MMBTUBACTPSD 0.0054LB/MMBTUIN-00865/9/2001 AUXILARY BOILER, NATURAL GAS (2)NATURALGAS 35 MMBTU/H VOCGOOD COMBUSTION. LB/HLIMIT IS FOR EACH BOILER. 0.0054 LB/MMBTUBACTPSD 0.19 LB/H 0.0054LB/MMBTUIN-00876/6/2001 AUXILARY BOILER, NATURAL GAS (2)NATURALGAS 46 MMBTU/H VOCGOOD COMBUSTION. LIMIT ISFOR EACH BOILER. 0.0054 LB/MMBTUBACTPSD 0.25 LB/H 0.0054LB/MMBTUNC-00941/9/2002 BOILER, AUXILIARY, NATURAL GASNATURALGAS 83 MMBTU/H VOCGOOD COMBUSTIONPRACTICES AND DESIGN 0.45 LB/HBACTPSD 0.0054LB/MMBTUOK-005110/1/1999 AUXILIARY BOILERNATURALGAS VOCBOILER DESIGN AND GOODOPERATING PRACTICES 0.0054 LB/MMBTUBACTPSD 0.0054LB/MMBTUOK-00562/12/2002 AUXILIARY BOILERSNATURALGAS 0 VOCGOOD COMBUSTIONPRACTICES AND DESIGN 0.0055 LB/MMBTUBACTPSD 0.0055LB/MMBTUOK-00448/16/2001 AUXILIARY BOILERS, (2)NATURALGAS 48 MMBTU/H VOC COMBUSTION CONTROL 0.52 LB/HBACTPSD 2.27 T/YR 0.0055LB/MMBTUWI-022710/13/2004 NATURAL GAS FIRED AUXILLIARY BOILERNATURALGAS 97.1 MMBTU/H VOCNATURAL GAS FUEL, GOODCOMBUSTION PRACTICES 0.53 LB/HBACTPSD 0.0055LB/MMBTUOH-02489/24/2002 BOILERNATURALGAS 99 MMBTU/H VOC 0.545 LB/HBACTPSD 0.0055LB/MMBTU 0.0055LB/MMBTUOH-026510/16/2001 BOILER, NATURAL GASNATURALGAS 49 MMBTU/H VOC 0.29 LB/HBACTPSD 0.118 T/YR 0.006LB/MMBTUAL-01681/12/2001 BOILERNATURALGAS 83 MMBTU/H VOC EFFICIENT COMBUSTION 0.006 LB/MMBTUBACTPSD 0.46 LB/H 0.006LB/MMBTUIN-00681/19/1996 BOILERS, NATURAL GASNATURALGAS 93.9 MMBTU/H VOC 0.55 LB/HBACTPSD 0 0.006LB/MMBTUNJ-00463/7/1996BOILERS 4&5, COMBUSTION CONTROLS, OXYGENTRIM, ETCNATURALGAS 94 MMBTU/H VOC N/A 0.79 LB/HBACTPSD 0.0084LB/MMBTU*AZ-00499/4/2003 AUXILIARY BOILER FOR SIEMENS TURBINESNATURALGAS 55.34 MMBTU/H VOC 0.01 LB/MMBTUBACTPSD 0.01LB/MMBTUOH-025712/27/2001 AUXILIARY BOILERNATURALGAS 76 MMBTU/H VOC 0.92 LB/HBACTPSD 1.37 T/YR 0.011LB/MMBTUMA-00275/7/2000 AUXILIARY BOILERNATURALGAS 26.6 MMBTU/H VOCCOMBUSTION CONTROLS,OXIDATION CATALYST. 0.4 LB/HBACTPSD 0.016LB/MMBTUOK-004310/22/2001 AUXILIARY BOILERNATURALGAS 30 MMBTU/H VOC 0.016 LB/MMBTUBACTPSD 0.016LB/MMBTUpage 73 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-42: Small Gas Fired Boilers and Heaters - VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitOH-025212/28/2004 BOILERS (2)NATURALGAS 30.6 MMBTU/H VOC 0.49 LB/HBACTPSD 0.74T/ROLLING 12-MONTHS 0.016LB/MMBTUOH-02548/14/2003 BOILERNATURALGAS 30.6 MMBTU/H VOC 0.49 LB/HBACTPSD 1.1T/ROLLING 12-MONTHS 0.016LB/MMBTUAR-00514/1/2002 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H VOC GOOD OPERATING PRACTICE 0.016 LB/MMBTUBACTPSD 0.016LB/MMBTUAR-004012/29/2000 BOILERS, AUXILIARY 2NATURALGAS 44.1 MMBTU/H VOCCLEAN FUELS, PROPERCOMBUSTION. LB/HR LIMIT FOREACH BOILER. 0.016 LB/MMBTUBACTPSD 0.8 LB/H 0.016LB/MMBTUNM-004212/29/2000 AUX-1 AUXILARY BOILERNATURALGAS 44.1 MMBTU/H VOC GOOD COMBUSTION DESIGN 0.7 LB/HBACTPSD 0.016LB/MMBTUNV-00396/1/2001 AUXILIARY BOILERSNATURALGAS 44.1 MMBTU/H VOC GOOD COMBUSTION CONTROL 0.8 LB/HBACTPSD 0.018LB/MMBTUAL-01692/5/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H VOCGOOD COMBUSTIONPRACTICES 0.02 LB/MMBTUBACTPSD 0.8 LB/H 0.02LB/MMBTUMA-00299/29/1999 BOILER, AUXILIARYNATURALGAS 96 MMBTU/H VOC EMISSION OFFSET 0.8 LB/H LAER 0.08LB/MMBTUIA-00545/20/1997 HIGH PRESSURE BOILER #1NATURALGAS 0.3 MMBTU/H VOC 0.25 LB/HBACTPSD 1.1 T/YR 0.8LB/MMBTUIA-00545/20/1997 BOILER #2 B2NATURALGAS 2.3 MMBTU/H VOCLOW NOX BURNER, FLUE GASRECIRC. ADDITIONAL EMISSIONLIMIT: 70 PPM 2.37 LB/HBACTPSD 4.11 T/YR 1LB/MMBTUIA-00545/20/1997 BOILER #1NATURALGAS 2.3 MMBTU/H VOCLOW NOX BURNER, FLUE GASRECIRC. 2.37 LB/HBACTPSD 411 T/YR 1LB/MMBTUIA-00545/20/1997 BOILER #3 B3NATURALGAS 2.3 MMBTU/HR VOCLOW NOX BURNER FLUE GASRECIRCULATION 2.37 LB/HBACTPSD 4.11 T/YR 1LB/MMBTUTX-03641/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H VOC NONE INDICATED 0.02 LB/HOtherCase-byCase 0.06 T/YRTX-040811/22/2002 AUXILIARY BOILER, (2)NATURALGAS 6 MMBTU/H VOC 0.01 LB/HBACTPSD 0.05 T/YRWI-01818/2/2000 BOILERNATURALGAS 10 MMBTU/H VOCBACT FOR VOC ISDETERMINED TO BE USE OFNATURAL GAS TO FUELBOILER. NO EMISSION RATELIMIT.BACTPSDWI-02071/21/2004 BOILER, S52/B52, 11 MMBTU/HNATURALGAS 11 MMBTU/H VOCNATURAL GAS / PROPANE;GOOD COMBUSTION CONTROL 0.0054 LB/MMBTUBACTPSDTX-038912/31/2002 BACK-UP BOILERNATURALGAS 13.4 MMBUT/H VOC 0.08 LB/HOtherCase-byCase 0.35 T/YRTX-035412/19/2002 (2) STEAM BOILERS, X-426A AND X-426BNATURALGAS 15.8 MMBTU/H VOC NONE INDICATED. 0.09 LB/HOtherCase-byCase 0.38 T/YRAR-00777/22/2004 BOILERSNATURALGAS 22 MMBTU/H VOCNATURAL GAS COMBUSTIONONLY 0.0055 LB/MMBTUBACTPSDOK-00411/19/2000 AUXILIARY BOILERNATURALGAS 22 MMBTU/H VOC COMBUSTION CONTROLS 0.2 T/YRBACTPSDOH-02764/14/2003 BOILER FOR VACUUM OXYGEN DEGASSER VESSELNATURALGAS 25 MMBTU/H VOC 0.13 LB/HBACTPSD 0.59 T/YROK-00745/1/2001 AUXILIARY BOILERNATURALGAS 27.5 MMBTU/H VOCGOOD COMBUSTIONPRACTICES AND DESIGN 0.0055 LB/MMBTUBACTPSD*WA-029210/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H VOC 0.16 LB/HBACTPSDpage 74 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-42: Small Gas Fired Boilers and Heaters - VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitOK-00552/12/2002 AUXILIARY BOILERNATURALGAS 31 MMBTU/H VOC COMBUSTION CONTROL 0.0055 LB/MMBTUOtherCase-byCaseGA-010110/23/2002 BOILER, AUXILIARYNATURALGAS 31.4 MMBTU/H VOC GOOD COMBUSTION PRACTICE 0.0127 LB/MMBTUBACTPSDAL-018110/23/2001 31.4 MMBTU/HR NATURAL GAS FIRED BOILERNATURALGAS 31.4 MMBTU/H VOC EFFICIENT COMBUSTION. 0.0104 LB/MMBTUBACTPSD 0.5 LB/HOK-00903/21/2003 BOILER, AUXILIARYNATURALGAS 33 MMBTU/H VOCBOILER DESIGN AND GOODOPERATING PRACTICES 0.016 LB/MMBTUBACTPSDAR-00708/23/2002 AUXILIARY BOILERNATURALGAS 33 MMBTU/H VOC GOOD COMBUSTION PRACTICE 0.018 LB/MMBTUBACTPSDNM-00446/27/2002 AUXILIARY BOILERS (AUX-1 AND AUX-2)NATURALGAS 33 MMBTU/H VOCCLEAN FUELS, GOODCOMBUSTION PRACTICE 0.5 LB/HBACTPSDOK-00706/13/2002 AUXILIARY BOILERNATURALGAS 33 MMBTU/H VOCBOILER DESIGN AND GOODCOMBUSTION PRACTICES 0.016 LB/MMBTUBACTPSDWI-02071/21/2004 BOILER, S53 / B53, 34 MMBTU/HNATURALGAS 34 MMBTU/H VOCNATURAL GAS / PROPANE;GOOD COMBUSTION CONTROL 0.0054 LB/MMBTUBACTPSDAL-018012/11/2001 35 MMBTU/HR NAT. GAS FIRED AUXILIARY BOILERNATURALGAS 35 MMBTU/H VOC GOOD COMBUSTION 0.014 LB/MMBTUBACTPSD 0.5 LB/HIN-011010/5/2001 BOILER, AUXILIARY, NATURAL GASNATURALGAS 35 MMBTU/H VOCCLEAN FUEL, GOODCOMBUSTION PRACTICE 0.011 LB/MMBTUBACTPSD 0.39 LB/HAZ-004712/1/2004 AUXILIARY BOILERNATURALGAS 38 MMBTU/H VOC 0.0033 LB/MMBTUBACTPSDMN-00537/15/2004 BOILER, NATURAL GAS (1)NATURALGAS 40 MMBTU/H VOC GOOD COMBUSTION. 0.006 LB/MMBTUBACTPSDAL-01857/12/2002 TWO (2) 40 MMBTU/H AUXILIARY BOILERSNATURALGAS 40 MMBTU/H VOCGOOD COMBUSTIONPRACTICES 0.0054 LB/MMBTUBACTPSD 0.2 LB/HTX-04377/5/2002 BOILERS, AUXILIARYNATURALGAS 40 mmbtu/h VOCGOOD COMBUSTIONPRACTICES PROPER DESIGN,CLEAN FUEL 0.02 LB/MMBTUBACTPSDMD-00339/27/2001 AUXILIARY BOILERNATURALGAS 40 MMBTU/H VOCEXCLUSIVE USE OF NATURALGAS, ADVANCED DRY LOWNOX BURNERS; GOODCOMBUSTION CONTROLSHEAT INPUT TO THE AUXILIARYBOILERS (2) SHALL BE LIMITEDTO 210,240 MMBTU FOR ANYCONSECUTIVE 12-MONTHPERIOD LAER*AZ-00499/4/2003 AUXILIARY BOILER FOR GE TURBINENATURALGAS 41 MMBTU/H VOC 0.01 LB/MMBTUBACTPSDVA-02713/24/2003 BOILER NO. 3NAT GASOR DISOIL 43.2 MMBTU VOCGOOD COMBUSTIONPRACTICES. 1.97 T/YR N/AVA-02713/24/2003 BOILER NO. 1NATURALGAS 43.2 MMBTU/H VOCGOOD COMBUSTIONPRACTICES. 0.23 LB/H N/AIA-00607/23/2002 AUXILIARY BOILER (48.5 MMBTU/H)NATUALGAS 48.69MILLIONCF/YR VOC GCP 0.005 LB/MMBTUBACTPSDTX-02744/3/2000 AUXILIARY BOILERNATURALGAS 54.01 MMBTU/H VOC NONE INDICATED. 0.29 LB/H N/A 0.03 T/YRTX-037811/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H VOC NONE INDICATED 0.35 LB/HOtherCase-byCase 1.53 T/YRpage 75 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-42: Small Gas Fired Boilers and Heaters - VOCControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLCIDPermit Date Process Fuel ThroughputThroughputUnit Pollutant Control Desc.EmissionLimit 1EmissionLimit 1 UnitCase-bycasebasisEmissionLimit 2EmissionLimit Unit2STDEmissionLimitSTD LimitUnitNV-00375/14/2004 AUXILIARY BOILERNATURALGAS 60 MMBTU/H VOCEFFECTIVE COMBUSTIONSYSTEM DESIGN, 10:1TURNDOWN CAPABILITY ANDLOW NOX BURNERTECHNOLOGY 0.4 LB/H LAERWI-02071/21/2004 BOILER, S50/B50, 60 MMBTU/HNATURALGAS 60 MMBTU/H VOCNATURAL GAS / PROPANE,GOOD COMBUSTIONCONTROLS 0.0054 LB/MMBTUBACTPSDOK-00548/21/2001 BOILERSNATURALGAS 62.77 MMBTU/H VOCGOODCOMBUSTION/MAINTENANCE 4.38 T/YRBACTPSDIA-006212/20/2002 AUXILIARY BOILERNATURALGAS 68 MMBTU/H VOC CATALYTIC OXIDATION 0.0054 LB/MMBTUOtherCase-byCaseMN-005412/4/2003 BOILER, COMMERCIALNATURALGAS 70 MMBTU/H VOC GOOD COMBUSTION 0.007 LB/MMBTUBACTPSDWI-02071/21/2004 BOILER, S51/B51, 80 MMBTU/HNATURALGAS 80 MMBTU/H VOCNAT. GAS / PROPANE; GOODCOMBUSTION CONTROL 0.0054 LB/MMBTUBACTPSDVA-02619/6/2002 AUXILIARY BOILERNATURALGAS 80 MMBTU/H VOCGOOD COMBUSTIONPRACTICES. 0.42 LB/HBACTPSD 0.63 T/YROH-02638/9/2001 AUXILIARY BOILERNATURALGAS 80 MMBTU/H VOC 0.44 LB/HBACTPSD 1.9 T/YRGA-00983/24/2003 AUXILIARY BOILERNATURALGAS 83 MMBTU/H VOC 0.004 LB/MMBTUOtherCase-byCaseOH-025111/29/2001 BOILER, NATURAL GASNATURALGAS 91.2 MMBTU/H VOC 0.65 LB/HBACTPSD 5.17 T/YROK-00725/6/2002 AUXILIARY BOILERNATURALGAS 93 MMBUT/H VOCBOILER DESIGN AND GOODOPERATING PRACTICES 0.0075 LB/MMBTUBACTPSDTX-036311/13/2000 BOILER NO. 2 NAT GAS VOC NONE INDICATED 0.07 LB/HOtherCase-byCase 0.15 T/YRTX-036311/13/2000 BOILER NO 3 NAT GAS VOC NONE INDICATED 0.05 LB/HOtherCase-byCase 0.2 T/YRTX-030010/13/1998 GLYCOL REBOILER NAT GAS VOC NONE INDICATED 0.01 LB/HOtherCase-byCase 0.04 T/YRBACT-PSD VOC lb/MMBtu Emission LimitsMIN0.002lb/MMBtu MIN0.004lb/MMBtuMAX1.0lb/MMBtu MAX0.08lb/MMBtuMEDIAN0.006lb/MMBtu MEDIAN0.005lb/MMBtuCOUNT35CASES COUNT3CASESRBLC VOC BACT Limits SummaryOther (non-BACT) VOC lb/MMBtuEmission Limitspage 76 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-43: Electric Arc Furnace (EAF) and Melt Shop (MS) - SOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMIT DATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSTN-0155NUCOR STEELCORPORATION11/6/2000ELECTRIC ARC FURNACEEAF 150 T/H SO2LIMIT HIGH-SULFUR STEELPRODUCTION TO 125,000TON/YR; MAINTENANCE OF ALOG OF IRON PYRITE USAGEDURING HIGH-SULFUR STEELPRODUCTION, PROPERLYDESIGNED EAF; SCRAPMANAGEMENT PLAN0.16LB/TBACT-PSD 3.5PPMVAR-0077BLUEWATER PROJECT7/22/2004ELECTRIC ARC FURNACE (EAF)EAF 350 t/h SO2LOW SULFUR COKE AND SCRAPMANAGEMENT0.2LB/TBACT-PSDTX-0417NUCOR CORP.1/15/2003ELECTRIC ARC FURNACEEAF SO2LOW SULFUR FUEL0.35LB/TBACT-PSDSC-0072SMI STEEL - SOUTHCAROLINA11/26/2001EAFEAF 850000 T/YR SO2SCRAP MANAGEMENT PLAN0.35LB/TBACT-PSDAL-0129IPSCO STEEL INC10/16/1998FURNACE, ELECTRIC ARCEAF 200 T/H SO20.7LB/TBACT-PSD 140LB/H0AR-0030ARKANSAS STEELASSOCIATES9/24/1998ELECTRIC ARC FURNACEEAF 50 T/H SO2DES WITH NO ADD-INCONTROLS (EXISTING)0.7LB/TBACT-PSD 35LB/HMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF 560000 T/YR SO21LB/T STEELPRODUCEDBACT-PSD 280T/YRAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001FURNACE, ELECTRIC ARCEAF 225 T/H SO2LOW SULFUR COKE/SCRAPMANAGEMENT.1.5LB/TBACT-PSDNY-0094NUCOR AUBURN STEEL6/22/2004EAFEAF 110 t/h SO225.3LB/HBACT-PSD 0.25LB/TIN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF 200 T/YR SO2SULFUR CONTENT OF DIRECTREDUCED IRON, CHARGECARBON, AND INJECTIONCARBON50LB/HBACT-PSD 0.25LB/T*AR-0086NUCOR-YAMATO STEELCOMPANY,BLYTHEVILLE MILL6/11/2004EAF #1 BAGHOUSE, SN-01EAF 450 T/H STEEL SO2LOW SULFUR COKE USAGE90LB/HBACT-PSD 394.2T/YR0.2LB/T STEELAL-0202CORUS TUSCALOOSA6/3/2003ELECTRIC ARC FURNACEEAF 160 T/H SO299.2LB/HBACT-PSD 0.62LB/TAL-0197NUCOR STEELDECATUR, LLC7/11/2002ELECTRIC ARC FURNACE, (2)EAF 440 T/H SO2220LB/HBACT-PSD 0.5LB/TOH-0276CHARTER STEEL4/14/2003ELECTRIC ARC FURNACEEAF 110 T/H MELT SO2PRODUCTION LIMITS. SEE NOTE22LB/H71.06T/YR0.2LB/TSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONSSSO20.2LB/T OF STEELBACT-PSD 30LB/HIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H SO2SCRAP MANAGEMENT PLAN.COMPLIANCE METHOD: SO2CEM.0.25LB/TBACT-PSD 125LB/HIN-0109BETA STEEL CORP.5/30/2003STEEL FURNACE MELTSHOPMS 1100000 T/YR SO20.33LB/TBACT-PSD 49.87LB/HNC-0064NUCOR STEEL4/20/1999STEEL PLANT, MELT SHOP(EAF,LMS,CSC)MS 250 T/H SO2SCRAP STEEL MANAGEMENTPLAN0.35LB/TBACT-PSD 383.2T/YRVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H SO20.7LB/TBACT-PSD 150.5LB/H0IL-0068KEYSTONE STEEL &WIRE COMPANY6/1/2000FURNACE, EAF & LMFMS 1200000 T/Y SO2USE OF LOW SULFURINJECTION COKE (0.65% ORLESS). WORK PRACTICES2LB/T STEELPRODUCEDBACT-PSDAR-0033NUCOR YAMATO STEELCOMPANY3/28/20002 ELECTRIC ARCFURNACES,MELTSHOP, TUNDISHMS 450 T/H SO2LOW SULFUR COKE AND SCRAPMANAGEMENT67.5LB/HBACT-PSD 0.15LB/T*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS SO2SCRAP MANAGEMENT0.35LB/T STEEL383.25T/YRNC-0113NUCOR STEEL11/23/2004MELT SHOPMS SO2SCRAP MANAGEMENT0.35LB/T STEEL383.25TONSBACT-PSD SO2 and SOx lb/t steel Emission LimitsMIN0.15lb/t steelMAX2.00lb/t steelMEDIAN0.35lb/t steel12th PERCENTILE0.20lb/t steelCOUNT23CASESMS and EAF RBLC SO2 and SOx BACT Limits Summarypage 77 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-44: Electric Arc Furnace (EAF) and Melt Shop (MS) - NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMIT DATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANTCONTROLEQUIPMENT EMISSION LIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMITTX-0417NUCOR CORP.1/15/2003ELECTRIC ARC FURNACEEAF NOXOXY-FUEL BURNERSAND GOODENGINEERINGPRACTICES0.3LB/TBACT-PSDAR-0077BLUEWATER PROJECT7/22/2004ELECTRIC ARC FURNACE (EAF)EAF 350 t/h NOXLOW NOX BURNERS0.35LB/TBACT-PSDOH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 9, P907EAF 165 T/H NOXLOOKED AT SCR,SNCR, AND FGR ALLINFEASIBLE0.35LB/TBACT-PSD 33LB/HAR-0055NUCOR YAMATOSTEEL (ARMOREL)10/10/2001FURNACE, ELECTRIC ARCEAF 225 T/H NOXLOW NOX BURNER.0.38LB/TBACT-PSDIN-0073QUALITECH STEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/H NOX 0.5LB/TBACT-PSD 0SC-0072SMI STEEL - SOUTHCAROLINA11/26/2001EAFEAF 850000 T/YR NOXLOW NOX OXY-FUEL"BURNERS MOUNTEDIN EAF"0.51LB/TBACT-PSDMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF 560000 T/YR NOX 0.53LB/T STEELPRODUCEDBACT-PSD 148.4T/YRTN-0155NUCOR STEELCORPORATION11/6/2000ELECTRIC ARC FURNACEEAF 150 T/H NOXTHE PROPEROPERATION OF THEEAF AND DECSYSTEMS, OXY-FUELNATURAL GASBURNERS IN THESHAFT, ELBOW BOXAND SIDEWALLS0.7LB/TBACT-PSD 21PPMVAR-0030ARKANSAS STEELASSOCIATES9/24/1998ELECTRIC ARC FURNACEEAF 50 T/H NOXDES WITH NO ADDON CONTROL(EXISTING)1LB/TBACT-PSD 50LB/HTN-0122HOEGANAESCORPORATION2/11/2000ELECTRIC ARC FURNACE (EAF)EAF 45 MVA/70.4 MMBNOXLOW NOX BURNERS11.04LB/HBACT-PSD 0.2LB/TNY-0094NUCOR AUBURNSTEEL6/22/2004EAFEAF 110 t/h NOX 27.32LB/HBACT-PSD 0.27LB/TAL-0202CORUS TUSCALOOSA6/3/2003ELECTRIC ARC FURNACEEAF 160 T/H NOX 56LB/HBACT-PSD 0.35LB/TIN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF 200 T/YR NOXLOW NOX/OXYFUELBURNERS ANDCOMBUSTIONCONTROLS.70LB/HBACT-PSD 0.35LB/TAL-0197NUCOR STEELDECATUR, LLC7/11/2002ELECTRIC ARC FURNACE, (2)EAF 440 T/H NOX 176LB/HBACT-PSD 0.4LB/TFL-0192AMERISTEELCORPORATION9/28/1999ELECTRIC ARC FURNACE ANDMELT SHOPMS 720000 T/YR NOXCOMBUSTIONPRACTICES.EMISSION LIMITUNITS: LB/T OFSTEEL (PRIMARY),LB/H 24 HR AVE(ALTERNATE).ADDITIONALEMISSION LIMIT:118.8 T/YR0.33LB/TBACT-PSD 330LB/HWI-0206SAUKVILLE PLANT12/19/2003MELT SHOP, P01, S01MS 137.5 T/D NOXDEC (DIRECTEVACUATIONCONTROL) AND LOWNOX SUPPLEMENTALBURNERS. ALSOREQUIRES CONTROLOF DEC AND EAFOPERATINGPARAMETERS.0.33LB/TBACT-PSDpage 78 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-44: Electric Arc Furnace (EAF) and Melt Shop (MS) - NOxControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMIT DATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANTCONTROLEQUIPMENT EMISSION LIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMITIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H NOXNATURAL GAS FIREDOXY FUEL BURNERS,COMPLIANCEMETHOD: NOXCONTINUOUSEMISSIONSMONITOR.0.35LB/TBACT-PSD 175.7LB/HIN-0109BETA STEEL CORP.5/30/2003STEEL FURNACE MELTSHOPMS 1100000 T/YR NOX 0.45LB/TBACT-PSD 68.58LB/HNC-0064NUCOR STEEL4/20/1999STEEL PLANT, MELT SHOP(EAF,LMS,CSC)MS 250 T/H NOX 0.51LB/TBACT-PSD 558.5T/YRWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR NOXLOW NOX BURNER0.51LB/TBACT-PSDVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H NO2LOW NOX BURNERS;WORK PRACTICES0.7LB/TBACT-PSD 150.5LB/HOK-0048GRIFFIN WHEEL CO10/18/1999ELECTRIC ARC FURNACE/LADLEMETALLURGY FURNACEMS NOX 0.2LB/T STEELBACT-PSDSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONS NOX 0.35LB/T STEELBACT-PSD 52.5LB/H*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS NOX 0.36LB/T STEELBACT-PSD 394.2T/YRIL-0068KEYSTONE STEEL &WIRE COMPANY6/1/2000FURNACE, EAF & LMFMS 1200000 T/Y NOXDEC, OXY/FUELBURNERS. WORKPRACTICES0.51LB/T STEELPRODUCEDBACT-PSDNC-0113NUCOR STEEL11/23/2004MELT SHOPMS NOX 0.36LB/T STEEL394.2TONSBACT-PSD NOx lb/t Steel Emission LimitsMIN0.200lb/t steelMAX1.000lb/t steelMEDIAN0.360lb/t steel12th PERCENTILE0.300lb/t steelCOUNT26CASESEAF and MS RBLC NOx BACT Limits Summarypage 79 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-45: Electric Arc Furnace (EAF) and Melt Shop (MS) - COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMIT DATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANTCONTROLEQUIPMENT EMISSION LIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSAR-0030 [a]ARKANSAS STEELASSOCIATES9/24/1998ELECTRIC ARC FURNACEEAF 50 T/H CODES WITH AIR GAPFOR COCOMBUSTION(EXISTING)0.6LB/TBACT-PSD 300LB/HKY-0094NORTH AMERICANSTAINLESS12/1/2003EAFEAF 154 t/batch CO 2LB/TBACT-PSD 265.76LB/HAL-0129IPSCO STEEL INC10/16/1998FURNACE, ELECTRIC ARCEAF 200 T/H CODEC WITH POSTCOMBUSTION2LB/TBACT-PSD 400LB/H0AR-0077BLUEWATER PROJECT7/22/2004ELECTRIC ARC FURNACE (EAF)EAF 350 t/h COAIR GAP2LB/TBACT-PSDTX-0417NUCOR CORP.1/15/2003ELECTRIC ARC FURNACEEAF COGOOD COMBUSTIONPRACTICE2LB/TBACT-PSDSC-0072SMI STEEL - SOUTHCAROLINA11/26/2001EAFEAF 850000 T/YR CODESTRUCTION OF COIN THE DUCT ELBOWAND WATER COOLEDDUCTWORK2LB/TBACT-PSDAR-0055NUCOR YAMATO STEEL(ARMOREL)10/10/2001FURNACE, ELECTRIC ARCEAF 225 T/H COOXIDATION WITHSIDE DRAFT AIR GAP2LB/TBACT-PSDTN-0155NUCOR STEELCORPORATION11/6/2000ELECTRIC ARC FURNACEEAF 150 T/H COPROPER OPERATIONOF EAF AND DIRECTEVACUATIONCONTROL SYSTEM,USE OF OXY-FUELFOR POSTCOMBUSTIONCONTROL; USE OFOXYGEN LANCING.4LB/TBACT-PSD 200PPMVIN-0073QUALITECH STEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/H COPOST COMBUSTIONUNDER HOOD BYOXYGEN INJECTIONAND OXY FUELBURNERS & FOURTHHOLE WITHADJUSTABLE GAP TOALLOW AIR INTOWATER COOLEDDUCTWORK FORCOMBUS4.7LB/TBACT-PSD 0 0OH-0246THE TIMKENCOMPANY/FAIRCRESTPLANT2/20/2003EAFEAF 200 T/H CO4TH HOLE4.8LB/TBACT-PSD 960LB/HPA-0178ELLWOOD QUALITYSTEELS CO.4/30/2001ELECTRIC ARC FURNACEEAF 53 T/BATCH CODIRECT EVACUATIONSYSTEM5LB/TBACT-PSD 1032.5T/YRMI-0376MACSTEEL DIVISION12/8/20032 ELECTRIC ARC FURNACESEAF 560000 T/YR CO 5LB/T STEELPRODUCEDBACT-PSD 1400T/YRAR-0044ARKANSAS STEELASSOCIATES1/5/2001FURNACE, ELECTIC ARCEAF 50 T/H CODIRECT SHELLEVACUATIONCONTROL (DEC)SYSTEM WITH AIRGAP FOR COCOMBUSTION.6LB/TBACT-PSD 420LB/HNC-0065AMERISTEEL CORP.4/29/1999STEEL PRODUCTION, ELECTRICARC FURNACEEAF 569400 T/YR COCONTROL: SEEPROCESSDESCRIPTION.EMISSION LIMIT INLB/TON STEELPRODUCED6LB/TBACT-PSDWV-0018ALLOY12/16/2002ELECTRIC ARC FURNACEEAF 18000 T/YR CODIRECT EVACUATIONCANOPY USED TOINTRODUCE AMBIENTAIR MIX WITHEXHAUST TOPROMOTE COCOMBUSTION.54LB/HBACT-PSD 25.22LB/T2.25LB/MW-HTN-0122HOEGANAESCORPORATION2/11/2000ELECTRIC ARC FURNACE (EAF)EAF 45 MVA/70.4 MMBCOCOMBUSTION AIRGAP BETWEEN THEWATER-COOLEDDUCT AND THEELBOW OFF152.9LB/HBACT-PSD 2.77LB/TNY-0094NUCOR AUBURN STEEL6/22/2004EAFEAF 110 t/h CODIRECT SHELLEVACUATION (DSE)CONTROLS TO LIMITCO EMISSIONS.202.4LB/HBACT-PSD 2LB/TAL-0202CORUS TUSCALOOSA6/3/2003ELECTRIC ARC FURNACEEAF 160 T/H CODIRECT EVACUATIONCANOPY320LB/HBACT-PSD 2LB/TIN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF 200 T/YR CODEC AIR GAP ANDPOST COMBUSTIONCHAMBER400LB/HBACT-PSD 2LB/T STEELAL-0197NUCOR STEELDECATUR, LLC7/11/2002ELECTRIC ARC FURNACE, (2)EAF 440 T/H CO 880LB/HBACT-PSD 2LB/TIL-0068KEYSTONE STEEL &WIRE COMPANY6/1/2000FURNACE, EAF & LMFMS 1200000 T/Y CODEC, OXY/FUELBURNERS,COMBUSTIONCHAMBER. WORKPRACTICES1.34LB/T STEELPRODUCEDBACT-PSD 1.34LB/TONSTEELPRODUCEIN-0108NUCOR STEEL11/21/2003EAF, AOD VESSELS,DESULFURIZATION, & OTHERPROCESSMS 502 T/H CODIRECT SHELLEVACUATION (DSE).COMPLIANCEMETHOD: CO CEM2LB/TBACT-PSD 1004LB/HSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONS CO 2.76LB/T OF STEELBACT-PSD 414LB/Hpage 80 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-45: Electric Arc Furnace (EAF) and Melt Shop (MS) - COControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMIT DATE PROCESS NAMEProcTypeTHROUGHPUT UNITSPOLLUTANTCONTROLEQUIPMENT EMISSION LIMIT 1 UNITSCASE-BY-CASEBASISEMISSIONLIMIT 2 UNITSSTDEMISSIONLIMIT UNITSFL-0192AMERISTEELCORPORATION9/28/1999ELECTRIC ARC FURNACE ANDMELT SHOPMS 720000 T/YR CODIRECT EVACUATIONCONTROL/ AIR GAPOXIDATION.EMISSION LIMITUNITS: LB/T OF STEEL(PRIMARY), LB/H 24HR AVE(ALTERNATE)ADDITIONAL EMISSION LIMIT:1080 T/YR3LB/TBACT-PSD 300LB/HWI-0206SAUKVILLE PLANT12/19/2003MELT SHOP, P01, S01MS 137.5 T/D CODEC (DIRECTEVACUATIONCONTROL) WITH ASECOND HOLE" TOINTRODUCE AIR FORSECONDARYCOMBUSTION ANDTHE CONTROL OFOPERATINGPARAMETERS ANDCARBON SOURCE TOENSURE PROPEROPERATION OF THEEMISSIONS UNITS"3.5LB/TBACT-PSDWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR CODIRECT EVACUATIONCONTROL (DEC)SYSTEM3.5LB/TBACT-PSDVA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H CODUCTING/EXTERNALCOMBUSTIONCHAMBER AT 12MMBTU/HR; WORKPRACTICES4LB/TBACT-PSD 860LB/H0NC-0064NUCOR STEEL4/20/1999STEEL PLANT, MELT SHOP(EAF,LMS,CSC)MS 250 T/H CODIRECT SHELLEVACUATION (DSE)PLUS COMBUSTIONCHAMBERFOLLOWINGCONSTEELCONVEYORPREHEATINGSECTION.4LB/TBACT-PSD 4380T/YRAR-0033NUCOR YAMATO STEELCOMPANY3/28/20002 ELECTRIC ARCFURNACES,MELTSHOP, TUNDISHMS 450 T/H COAIR GAP900LB/HBACT-PSD 2LB/TPA-0235KOPPEL STEEL CORP.11/26/2003MELT SHOPMS 598000 T/YR CO 1346T/YRBACT-PSD 5LB/T*OH-0285NORTH STAR BHPSTEEL, LTD8/5/2003ELECTRIC ARC FURNACE WITHTWO LADLE MELT FURNACESMS 315 T STEEL/H CODIRECT EVACUATIONCONTROL SYSTEMWITH AIR GAP, ANDCOOLED POSTCOMBUSTIONCHAMBER WITHBURNERS2362.5LB/HBACT-PSD 10347.8T/ROLLING12-MONTHS7.5LB/T*NC-0112NUCOR STEEL11/23/2004MELT SHOPMS CODIRECT SHELLEVACUATION (DSE)VIA THE CONSTEELPROCESS PLUSCOMBUSTIONCHAMBER (AIR GAP)2.3LB/T STEEL2518.5T/YRNC-0113NUCOR STEEL11/23/2004MELT SHOPMS CODIRECT SHELLEVACUATION (DSE)VIA THE CONSTEELPROCESS PLUSCOMBUSTIONCHAMBER (AIR GAP)2.3LB/T STEEL2518.5TONSBACT-PSD CO lb/t Steel Emission LimitsMIN0.60lb/t steelMAX25.22lb/t steelMEDIAN2.76lb/t steel12th PERCENTILE2.00lb/t steelCOUNT33CASESEAF and MS RBLC CO BACT Limits Summary[a] Billy Ferguson of Arkansas Steel Associates, said on 6/8/06 that they were having no problems meeting the limit0.6 LB/TON for their facility.page 81 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-46: Small Natural Gas Fired Boiler RBLC Opacity LimitsControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSIONLIMIT 2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACT %OpacityLimitsNon-BACT %OpacityLimitsAZ-0047WELLTON MOHAWKGENERATING STATION12/1/2004AUXILIARY BOILERSm GasBlrs & Htrs38 MMBTU/HVisibleEmissions(VE) N10 % OPACITY BACT-PSD 10 % OPACITY10OH-0254DUKE ENERGYWASHINGTON COUNTYLLC8/14/2003BOILERSm GasBlrs & Htrs30.6 MMBTU/HVisibleEmissions(VE) N20 % OPACITY BACT-PSD 20 % OPACITY20MS-0057SMEPA - SILVER CREEKGENERATING5/29/2003BOILERS, NATURAL GAS (3)Sm GasBlrs & Htrs5.4 MMBTU/HVisibleEmissions(VE) N40 % OPACITY Other Case-by-Case 40 % OPACITY40OH-0276CHARTER STEEL4/14/2003BOILER FOR VACUUM OXYGENDEGASSER VESSELSm GasBlrs & Htrs25 MMBTU/HVisibleEmissions(VE) N20 % OPACITY20 % OPACITY20GA-0098RINCON POWER PLANT3/24/2003AUXILIARY BOILERSm GasBlrs & Htrs83 MMBTU/HEmissions(VE) N10 % OPACITY Other Case-by-Case 10 % OPACITYWA-0291WALLULA POWERPLANT1/3/2003BOILER, AUXILIARYSm GasBlrs & Htrs55.3 MMBTU/HVisibleEmissions(VE) N10 % OPACITY Other Case-by-Case 10 % OPACITY10IN-0116ENERGY CO., INC.12/23/2002, ,NATURAL GAS Blrs & Htrs2.4 MMBTU/HEmissions N20 % OPACITY BACT-PSD 27 % OPACITY 20 % OPACITY20GA-0101MURRAY ENERGYFACILITY10/23/2002BOILER, AUXILIARYSm GasBlrs & Htrs31.4 MMBTU/HVisibleEmissions(VE) P GOOD COMBUSTION PRACTICE10 % OPACITY BACT-PSD 10 % OPACITY10AL-0192HONDAMANUFACTURING OFALABAMA, LLC10/18/2002BOILERS, NATURAL GAS, (3)Sm GasBlrs & Htrs30 MMBTU/HVisibleEmissions(VE) N10 % OPACITY BACT-PSD 10 % OPACITY10WI-0195SENA NIAGARA MILL10/18/2002PROCESS HEATER, PAPERMACHINE P51Sm GasBlrs & Htrs34.4 MMBTU/HVisibleEmissions(VE) PNATURAL GAS AS FUEL, GOODCOMBUSTION PRACTICE.20 % OPACITY Other Case-by-Case 20 % OPACITY20KY-0087QUEBECOR WORLDFRANKLIN7/12/2002BOILER, NATURAL GAS, #4Sm GasBlrs & Htrs33.5 MMBTU/HVisibleEmissions(VE) N20 % OPACITY BACT-PSD 20 % OPACITY20OH-0264NORTON ENERGYSTORAGE, LLC5/23/2002RECUPERATOR PRE-HEATERS(9)Sm GasBlrs & Htrs12.84 MMBTU/HVisibleEmissions(VE) N10 % OPACITY BACT-PSD 10 % OPACITY10OH-0264NORTON ENERGYSTORAGE, LLC5/23/2002FUEL SUPPLY HEATERS (9)Sm GasBlrs & Htrs11.45 MMBTU/HVisibleEmissions(VE) N10 % OPACITY BACT-PSD 10 % OPACITY10IA-0058GREATER DES MOINESENERGY CENTER4/10/2002AUXILIARY BOILERSm GasBlrs & Htrs68 MMBTU/HVisibleEmissions(VE) N0 % OPACITY BACT-PSD 0 % OPACITYIA-0058GREATER DES MOINESENERGY CENTER4/10/2002EFFICIENCY HEATERSm GasBlrs & HtrsVisibleEmissions(VE) N0 % OPACITY BACT-PSD 0 % OPACITYIA-0058GREATER DES MOINESENERGY CENTER4/10/2002DEW POINT HEATERSm GasBlrs & HtrsVisibleEmissions(VE) N0 % OPACITY BACT-PSD 0 % OPACITYOH-0257JACKSON COUNTYPOWER, LLC12/27/2001AUXILIARY BOILERSm GasBlrs & Htrs76 MMBTU/HVisibleEmissions(VE) N20 % OPACITY BACT-PSD 20 % OPACITY20MS-0058CHOCTAW GASGENERATION, LLC12/13/2001HEATER, FUEL GASSm GasBlrs & Htrs5.6 MMBTU/HVisibleEmissions(VE) N40 % OPACITY Other Case-by-Case 40 % OPACITY40OH-0251CENTRAL SOYACOMPANY INC.11/29/2001BOILER, NATURAL GASSm GasBlrs & Htrs91.2 MMBTU/HVisibleEmissions(VE) N20 % OPACITY BACT-PSD 20 % OPACITY20TX-0378LA PORTEPOLYPROPYLENEPLANT11/5/2001PACKAGE BOILER BO-4Sm GasBlrs & Htrs60 MMBTU/HVisibleEmissions(VE) N NONE INDICATED5 % OPACITY N/A 5 % OPACITY5PR-0007COGENERATION PLANT(AES-PRCP)10/29/2001LIMESTONE DRYERSm GasBlrs & Htrs13 MMBTU/HVisibleEmissions(VE) A ESP AND BAGHOUSES20 % OPACITY BACT-PSD 27 % OPACITY 20 % OPACITY20OH-0265DRESDEN ENERGY LLC10/16/2001BOILER, NATURAL GASSm GasBlrs & Htrs49 MMBTU/HVisibleEmissions(VE) N20 % OPACITY BACT-PSD 20 % OPACITY20IN-0110COGENTRIXLAWRENCE CO., LLC10/5/2001BOILER, AUXILIARY, NATURALGASSm GasBlrs & Htrs35 MMBTU/HVisibleEmissions(VE) PCLEAN FUEL, GOOD COMBUSTIONPRACTICES20 % OPACITY BACT-PSD 20 % OPACITY20OH-0263FREMONT ENERGYCENTER, LLC8/9/2001AUXILIARY BOILERSm GasBlrs & Htrs80 MMBTU/HVisibleEmissions(VE) N10 % OPACITY BACT-PSD 10 % OPACITY10AK-0047MILNE POINTPRODUCTION FACILITY7/13/2001HEATERS (2), H-5302A AND H5302BSm GasBlrs & Htrs35 MMBTU/HVisibleEmissions(VE) N20 % OPACITY N/A 20 % OPACITY20AK-0047MILNE POINTPRODUCTION FACILITY7/13/2001HEATERS (2), H-4510A AND H4510BSm GasBlrs & Htrs14.4 MMBTU/HVisibleEmissions(VE) N20 % OPACITY N/A 20 % OPACITY20AK-0047MILNE POINTPRODUCTION FACILITY7/13/2001HEATERS (2), H-5701A AND H5701BSm GasBlrs & Htrs29 MMBTU/HVisibleEmissions(VE) N20 % OPACITY N/A 20 % OPACITY20SC-0061COLUMBIA ENERGY LLC4/9/2001HOT WATER HEATERS (2)Sm GasBlrs & Htrs11 MMBTU/HVisibleEmissions(VE) P CLEAN FUEL20 % OPACITY N/A 20 % OPACITY20page 82 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-46: Small Natural Gas Fired Boiler RBLC Opacity LimitsControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSIONLIMIT 2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACT %OpacityLimitsNon-BACT %OpacityLimitsOH-0255PSEG WATERFORDENERGY LLC3/29/2001BOILER, NATURAL GASSm GasBlrs & Htrs85.2 MMBTU/HVisibleEmissions(VE) N20 % OPACITY N/A 20 % OPACITY20OH-0258PRO TEC COATINGCOMPANY2/15/2001BOILERS (4)Sm GasBlrs & Htrs20.9 MMBTU/HVisibleEmissions(VE) N20 % OPACITY N/A 20 % OPACITY20SC-0065BROAD RIVERINVESTORS - GAFFNEY12/21/2000HOT WATER HEATERS, NAT. GAS(2)Sm GasBlrs & Htrs11 MMBTU/HVisibleEmissions(VE) PGOOD COMBUSTION CONTROL, CLEANBURNING FUELS20 % OPACITY Other Case-by-Case 20 % OPACITY20BACT-PSD PM gr/dscf Emission LimitsMIN10% Opacity MIN5% OpacityMAX20% OpacityMAX40% OpacityMEDIAN20% OpacityMEDIAN20% OpacityCOUNT14CASES COUNT13CASESSmall Natural Gas Boler RBLC Opacity BACT Limits SummaryOther (non-BACT)-case-by-case PMgr/dscf Emission Limitspage 83 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-47: Melt Shop (MS) & EAF - RBLC Opacity LimitsControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSIONLIMIT 2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACT %OpacityLimitsNon-BACT %OpacityLimitsWI-0098CHARTER STEELDIVISION6/9/2000MELTING SHOP (ELECTRIC ARCFURNACE)MS 550000 T/YR VE PPROCESS CONTROL20% OPACITYN/A 20% OPACITY20MI-0275RAVENNA CASTINGCENTER, INC.4/14/2000IRON MELT SHOPMS 27 T/H VE AFABRIC FILTER5% OPACITYOther Case-by-Case 5% OPACITY5TN-0122HOEGANAESCORPORATION2/11/2000MELT SHOP OPERATIONSMS VE AFABRIC FILTER20% OPACITYOther Case-by-Case 20% OPACITY20FL-0192AMERISTEELCORPORATION9/28/1999MELT SHOPMS 720000 T/YR VE ABAGHOUSES6% OPACITYBACT-PSD 6% OPACITY6VA-0240CHAPARRAL STEELCOMPANY4/24/1998FURNACES, EAF & LRF,COMBINED MELTSHOPMS 215 T/H VE N3% OPACITYBACT-PSD 0 3% OPACITY3SC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998MELTSHOP #3MS 150 BILLET TONSVE ACLEANING MAIN BAGHOUSE WITH 3 FANSAND 2 REVERSE AIR FANS, CASTER10% OPACITYBACT-PSD 20% OPACITY6% OPACITY6TX-0332MIDLOTHIAN STEEL4/24/2000HOODS AMS OPACITY NNONE INDICATED10% OPACITYN/A 10% OPACITY10TX-0332CHAPPARRAL STEELMIDLOTHIAN STEELMILL4/24/2000MELTSHOP OVERHEAD CANOPYHOODS BMS OPACITY NNONE INDICATED10% OPACITYN/A 10% OPACITY10IN-0073QUALITECH STEELCORP.10/31/1996ELECTRIC ARC FURNACE (EAF)EAF 135 T/H VE ADIRECT SHELL EVAC; BAGHOUSE3% OPACBACT-PSD 0 3% OPAC3*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE (STACKEMISSIONS)EAF 70 T/H VE ABAGHOUSE AND DUST HANDLING SYSTEM3% OPACITYBACT-PSD 3% OPACITY3OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005ELECTRIC ARC FURNACEEAF 350 t/h VE N3% OPACITY0% OPACITY3% OPACITY3CO-0054CF & I STEEL L.P. DBAROCKY MOUNTAINSTEEL MILLS6/21/2004ELECTRIC ARC FURNACE (EAF)EAF 156 T/H VE ABAG FILTERS3% OPACITYOther Case-by-Case 3% OPACITY3FL-0192AMERISTEELCORPORATION9/28/1999ELECTRIC ARC FURNACEEAF 720000 T/YR VE ABAGHOUSES3% OPACITYBACT-PSD 3% OPACITY3IN-0080STEEL DYNAMICS, INC.7/7/1999FURNACE, ELECTRIC ARC (EAF)EAF 200 T/YR VE ABAGHOUSE3% OPACITYBACT-PSD 3% OPACITY3*OH-0294NUCOR STEEL MARION,INC.8/18/2005ELECTRIC ARC FURNACE(FUGITIVE EMISSIONS)EAF 70 T/H VE AUSE OF SEGMENTED CANOPY HOOD,SCAVENGER DUCTING, CROSS-DRAFTPARTITIONING AND CLOSED ROOFMONITORS.6% OPACITY0% OPACITYOH-0276CHARTER STEEL4/14/2003ELECTRIC ARC FURNACEEAF 110 T/H MELT VE ABAGHOUSE6% OPACITY3% OPACITY3OH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 7, P905EAF 85 T/H VE ABAGHOUSE6% OPACITYN/A 6% OPACITY6OH-0245REPUBLICTECHNOLOGIESINTERNATIONAL1/27/1999ELECTRIC ARC FURNACE (EAF)NO. 9, P907EAF 165 T/H VE ABAGHOUSE6% OPACITYN/A 6% OPACITY6VA-0240CHAPARRAL STEELCOMPANY4/24/1998ELECTRIC ARC FURNACE, ES1EAF 215 T/H VE BMELT SHOP EVACUATION PLUS BAGHOUSE6% OPACITYBACT-PSD 0 6% OPACITY6SC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998ELECTRIC ARC FURNACE (EAF)EAF 160 TONS VE ADIRECT SHELL EVACUATION SYSTEM,OVERHEAD CANOPY, DUCTED TO MAINBAGHOUSE.6% OPACITYBACT-PSD 6% OPACITY6UT-0061NUCOR STEELCORPORATION8/29/1997ELECTRIC ARC FURNACES (#1 )EAF 65 T (EACH) OPACITY N3% OPACITYBACT-PSD3BACT-PSD PM gr/dscf Emission LimitsMIN3% Opacity MIN3% OpacityMAX6% OpacityMAX20% OpacityMEDIAN3% OpacityMEDIAN6% OpacityCOUNT10CASES COUNT10CASESEAF & Melt Shop RBLC Opacity BACT Limits SummaryOther (non-BACT)-case-by-case PMgr/dscf Emission Limitspage 84 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-47: LMF - RBLC Opacity LimitsControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSIONLIMIT 2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACT %OpacityLimitsNon-BACT %OpacityLimitsOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005LADLE METALLURGY FURNACELMF 350 t/h VE ABAGHOUSE3% OPACITY0% OPACITY3% OPACITY3IN-0108NUCOR STEEL11/21/2003LADLE METALLURGY FURNACES(2)LMF 502 T/H VE ABAGHOUSE3% OPACITYBACT-PSD 3% OPACITY3OH-0276CHARTER STEEL4/14/2003LADLE METALLURGY FURNACELMF 110 T/H VE ABAGHOUSERACT 3% OPACITY3TN-0122HOEGANAESCORPORATION2/11/2000LADLE METALLURGY FACILITY(LMF)LMF 110650 LB MOLTEN VE NNONE INDICATED10% OPACITYOther Case-by-Case 10% OPACITY10OH-0245TECHNOLOGIESINTERNATIONAL1/27/1999LADLE METALLURGY FACILITY(LMF), P123LMF VE ABAGHOUSE5% OPACITYN/A 5% OPACITYSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998LADLE METALLURGICALFURNACE (LMF)LMF VE ABAGHOUSE20% OPACITYBACT-PSD 20% OPACITY20BACT-PSD PM gr/dscf Emission LimitsMIN3% Opacity MIN3% OpacityMAX20% OpacityMAX10% OpacityMEDIAN12% OpacityMEDIAN3% OpacityCOUNT2CASES COUNT3CASESLMF RBLC Opacity BACT Limits SummaryOther (non-BACT)-case-by-case PMgr/dscf Emission Limitspage 85 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-46: Material Handling (MH) and Fugitive (Fug)- RBLC Opacity LimitsControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSIONLIMIT 2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACT %OpacityLimitsNon-BACT %OpacityLimitsIN-0073QUALITECH STEELCORP.10/31/1996MATL. CRUSHING, HANDLING, &STORAGEMH & Fug 5 LB/H PM10 PWORK PRACTICES; VE AVERAGE ASCALCULATED BY METHOD 9.3% OPACBACT-PSD3MN-0061ERIE NUGGET6/26/2005COAL & FLUX UNLOADINGMH & Fug 4000000 DSCF OPACITY AFF10% OPACITYBACT-PSD 10% OPACITY10MN-0061ERIE NUGGET6/26/2005RAIL LOADOUTMH & Fug 4000000 DSCF OPACITY AFF10% OPACITYBACT-PSD 10% OPACITY10MN-0061ERIE NUGGET6/26/2005MATERIAL TRANSFEROPERATIONSMH & Fug 6000000 DSCF/H OPACITY AFF10% OPACITYBACT-PSD 10% OPACITY10MN-0061ERIE NUGGET6/26/2005FUGITIVES FROM STORAGEPILESMH & Fug OPACITY PFUGITIVE DUST CONTROL PLAN.5% OPACITYBACT-PSD 5% OPACITY5MN-0061ERIE NUGGET6/26/2005FUGITIVES FROM PAVED ROADSMH & Fug OPACITY PFUGITIVE DUST CONTROL PLAN.5% OPACITYBACT-PSD 5% OPACITYSC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998DUST HANDLING SYSTEMMH & Fug OPACITY ABAGHOUSE10% OPACITYBACT-PSD 10% OPACITY10SC-0075DARLINGTON COUNTY1/8/1998EAF FLUX/ALLOY SYSTEMMH & Fug OPACITY ABAGHOUSE, BIN VENT FILTER20% OPACITYBACT-PSD 20% OPACITY20SC-0075NUCOR STEELDARLINGTON COUNTY1/8/1998LMF FLUX/ALLOY SYSTEMMH & Fug OPACITY ABIN VENT FILTERS20% OPACITYBACT-PSD 20% OPACITY20UT-0061NUCOR STEELCORPORATION8/29/1997ROADS (PAVED)MH & Fug OPACITY PSWEPT OR WATER FLUSHED10% OPACITYBACT-PSD10UT-0061NUCOR STEELCORPORATION8/29/1997ROADS (UNPAVED)MH & Fug OPACITY PWATER SPRAYED OR CHEMICALLYTREATED20% OPACITYOther Case-by-Case20UT-0061NUCOR STEELCORPORATION8/29/1997FUGITIVES / STOCK PILES /TRANSFER POINTSMH & Fug OPACITY AFABRIC FILTERS10% OPACITYBACT-PSD10IN-0119AUBURN NUGGET5/31/2005COAL CAR UNLOADINGMH & Fug 165 T/H VE N3% OPACITYBACT-PSD 3% OPACITY3IN-0119AUBURN NUGGET5/31/2005ROADSMH & Fug VE PFOLLOW FUGITIVE DUST PLAN10% OPACITYBACT-PSD10OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR BOFMH & Fug VE ATHREE BAGHOUSES0% OPACITY0% OPACITYOH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR EAFMH & Fug 2.5 MM t/yr VE ABAGHOUSE AND VENT FILTERS10% OPACITY0% OPACITY10% OPACITY10OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005MATERIAL HANDLING FOR LMFMH & Fug 2.5 mm t/yr VE ABIN VENT FILTERS0% OPACITY0% OPACITY10% OPACITY10OH-0292WHEELINGPITTSBURGH STEELCORPORATION1/6/2005BASIC OXYGEN FURNACES (2VESSELS), FUGITIVE EMISSIONSMH & Fug 375 t/h VE N20% OPACITYBACT-PSD 20% OPACITY20IN-0108NUCOR STEEL11/21/2003EAF DUST TREATMENTMH & Fug 100000 LB/H VE ASCRUBBER, COMPLIANCE BY SCRUBBERMONITORING10% OPACITYBACT-PSD 10% OPACITY10IN-0108NUCOR STEEL11/21/2003EAF DUST HANDLINGMH & Fug 100000 LB/H VE PBIN VENTS10% OPACITYBACT-PSD 10% OPACITY10OH-0276CHARTER STEEL4/14/2003SILOS CARBON, LIME, AND DUSTMH & Fug 50 T/H VE ABIN VENT10% OPACITY10% OPACITY10OH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001LOAD IN AND LOAD OUT OFCOKE/COAL STORAGE PILESMH & Fug VE ALOAD-IN COAL, COKE, AND COKE BREEZEW/ STACKING TUBE; LOAD-IN COALW/WATER SPRAYS/DUST SUPPRESSANT;LOAD-OUT COAL UNDER PILE GRAVITYFEED AND WATER SPRAY; LOAD-OUT COKEW/ UNDER PILE GRAVITY FEED.0% OPACITYBACT-PSD 0% OPACITYOH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001COAL HANDLING, CONVEYING,AND TRANSFERMH & Fug 6602850 T/YR VE PRAIL CAR BOTTOM DUMPING ANDENCLOSED; BELT CONVEYORS ENCLOSED;WET AND/OR CHEMICAL SUPPRESSION20% OPACITYBACT-PSD 20% OPACITY20OH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001COKE AND BREEZECRUSHING/SCREENING/CONVEYINGMH & Fug VE ABAGHOUSE WITH 0.008 GR/DSCF20% OPACITYBACT-PSD 20% OPACITY20OH-0272HAVERHILL NORTHCOKE COMPANY2/27/2001ROADWAYS AND PARKINGMH & Fug VE PWATERING AS SUFFICIENT FREQUENCY TOENSURE COMPLIANCE0% OPACITYBACT-PSD 0% OPACITYIN-0090NUCOR STEEL1/19/2001LMS BAGHOUSE SILOMH & Fug VE PBIN VENT FILTER3% OPACITYBACT-PSD 3% OPACITY3IN-0090NUCOR STEEL1/19/2001DUMPING STORAGE &TRANSFERMH & Fug VE PWATERING STORAGE PILES5% OPACITYBACT-PSD 5% OPACITY5IN-0090NUCOR STEEL1/19/2001TRANSPORTATION ON ROADSMH & Fug VE A10% OPACITYBACT-PSD 10% OPACITY10IN-0090NUCOR STEEL1/19/2001STORAGE SILO FOR BLASTINGMEDIAMH & Fug 1000 DSCFM VE ABIN VENT3% OPACITYBACT-PSD 3% OPACITY3IN-0079STEEL DYNAMICS, INC.7/7/1999SLAG, HANDLING ANDPROCESSINGMH & Fug 262800 T/YR VE BWATER SUPPRESSION AND MINIMIZINGDROP HEIGHTS OPACITY REQUIREMENTS,SIX MINUTE AVERAGING10% OPACBACT-PSD 0 10% OPAC10IN-0080STEEL DYNAMICS, INC.7/7/1999HANDLING AND PROCESSING,SLAGMH & Fug 150 T/YR VE BWATER SUPPRESSION AND MINIMIZINGDROP HEIGHTS OPACITY, 3-10%, SIXMINUTE AVERAGE3% OPACBACT-PSD 0 3% OPAC3VA-0240CHAPARRAL STEELCOMPANY4/24/1998DUST HANDLING SYSTEM,BAGHOUSEMH & Fug 0 VE N10% OPACITYBACT-PSD 0 10% OPACITY10IN-0073QUALITECH STEELCORP.10/31/1996MATL. RECEIVING, HANDLING, &STORAGEMH & Fug 8000 T CAPACITY VE ARECEIVED IN SHED, SEALED HOPPERS ATRAIL CAR, ENCLOSED CONVEYORS ANDFILTERS ON STORAGE BIN EXHAUST. VEAVERAGE AS CALCULATED BY METHOD 9.3% OPACBACT-PSD 0 3% OPAC3MH & Fug RBLC Opacity BACT Limits Summarypage 86 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 RevisionMinnesota Steel Industries Air Quality Permit ApplicationBACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-46: Material Handling (MH) and Fugitive (Fug)- RBLC Opacity LimitsControl Equipment Codes: P= Pollution prevention, A= Add on Controls. B= Both, N= No controls feasibleRBLC ID FACILITY NAME PERMITDATEPROCESS NAME ProcTypeTHROUGHPUTUNITS POLLUTANTCONTROLCODECONTROL EQUIPMENT EMISSIONLIMIT 1EmissionLimit 1 UnitCASE-BY-CASE BASISEMISSIONLIMIT 2EmissionLimit 2 UnitSTDEmissionLimitSTD LimitUnitBACT %OpacityLimitsNon-BACT %OpacityLimitsBACT-PSD PM gr/dscf Emission LimitsMIN3% Opacity MIN10% OpacityMAX20% OpacityMAX20% OpacityMEDIAN10% OpacityMEDIAN10% OpacityCOUNT25CASES COUNT4CASESOther (non-BACT)-case-by-case PMgr/dscf Emission Limitspage 87 of 87P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachments\Attach L MN Steel RBLC Search MAR 2007 Revision

# Attachment M

BACT During SSM

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# 1.1 Compliance with BACT during Startup, Shutdown a nd Malfunction

For periods of startup, shutdown and malfunction, M innesota Steel proposes to follow Good
Air Pollution Control Practices for Minimizing Emis sions as BACT. To achieve this,

Minnesota Steel Industries will at all times, inclu ding periods of startup, shutdown, and
malfunction, operate and maintain the facility’s op erating equipment, associated air pollution
control equipment and monitoring equipment, in a ma nner consistent with safety and good air
pollution control practices for minimizing emission s.

Startups and, shutdowns are infrequent events assoc iated with maintenance of the facility
which usually occur no more than two or three times per year on any individual operating
unit. Typically, operating equipment is taken out of service once per year for inspection,
repair and preventative maintenance. Other startu p and shutdown events during the year are
associated with planned shutdowns to repair equipme nt which cannot be fixed while the unit
is operating or shutdowns due to unplanned equipmen t failures (malfunctions). Actions taken
during annual maintenance inspections are designed to minimize the number of shutdowns
due to malfunctions and maintenance during the rema inder of the year.

During periods of startup, shutdown and malfunction , temperatures, pressures and flows in
process equipment vary significantly over time. As the process transitions into/out of normal
operation conditions, it is not possible to keep em ission control equipment operating at
optimum control efficiency due to changing conditio ns. In addition, some emissions control
equipment must reach proper operating temperatures before it can achieve the desired
emissions control efficiency. Therefore, complianc e with BACT limitations for normal
operations cannot be guaranteed at all times during startup, shutdown and malfunction
conditions. By following good Air Pollution Contro l Practices, Minnesota Steel will

minimize both the extent and duration of excess emi ssions. In addition to following good
operating practices for minimizing emissions, Minne sota Steel Industries will operate its
facility so that emissions will not exceed the emis sions to the rates listed in Attachment N,

Table 2 at the emission units which cannot meet BAC T limitations during startup and
shutdown. The BACT report identifies those conditio ns where applicable BACT limitations
for normal operations cannot be met at all times du ring startup, shutdown and malfunction.
Specific measures, which Minnesota Steel will follo w to minimize emissions as good air
pollution control practices, include:

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## • 

# During startup, emission control equipment will be put into operation prior to the startup
of process equipment when it is feasible to do so.

• 

# During startup, process equipment and emission cont rol equipment will be brought to
proper operating conditions as soon as practicable, and in a manner consistent with safety
and process limitations in order to minimize emissi ons.

• 

# During shutdown, emission control equipment will re main in service until the process is

shut down when it is feasible to do so.

• 

# During shutdown, process equipment will be taken ou t of service as soon as practicable,
and in a manner consistent with safety and process limitations in order to minimize

emissions.

• 

# When practicable, planned startups and shutdowns of process units within the facility will
be phased. This will minimize the number of source s, which at any given time; have
excess emissions due to startup and shutdown activi ties.

• 

# During periods of malfunction, Minnesota Steel will identify and correct the cause of the
malfunctions as soon as practicable, and/or will co nsider taking the malfunctioning
equipment out of service until it can be operated i n a manner consistent with the
applicable environmental requirements.

Minnesota Steel will prepare a startup, shutdown an d malfunction plan specifying the actions
to be taken during startup, shutdown and malfunctio ns, and when the requirements of the
startup, shutdown and malfunction plan are applicab le. Specifics of the startup shutdown and
malfunction plan cannot be determined at this time because the facility has not been
completely designed. A startup shutdown and malfun ction plan will be prepared prior to the
initial startup of the facility. As noted above, p lans for startup, shutdown and malfunction
will follow all safety requirements.

The proposed startup and shutdown emission limits f or emission units, which cannot meet the
normal operation BACT during startup and shutdown, are listed in Table 1 that follows.

Table 2 lists the proposed startup and shutdown emi ssion limits the pelletizer waste gas

stream with LoTOx controls are installed. If the L oTOx trial is successful these limits would
apply after LoTOx controls are installed and operat ional.

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## Table 1 Emission Limits for Startup and Shutdown

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Pelletizer Waste Gas NO x 

## Best Practices for Minimizing Emissions NA 928 lb/hr NO x 

## 24-hour Average

S/U periods not to exceed 36 hours

S/D periods not to exceed 24 hours

Pelletizer Waste Gas CO Good Combustion Practices Clean Fuels

Best Practices for Minimizing Emissions NA 24 lb/hr CO 24-hour Average

S/U periods not to exceed 36 hours

S/D periods not to exceed 24 hours

Pelletizer Waste Gas VOC Good Combustion Practices Clean Fuels

Best Practices for Minimizing Emissions NA 11.9 lb/hr VOC 24-hour Average

S/U periods not to exceed 36 hours

S/D periods not to exceed 24 hours

Pelletizer Hood Exhaust NO x 

## Good Combustion Practices Clean Fuels

Best Practices for Minimizing Emissions NA 330 lb/hr NO x 

## 24-hour Average

S/U periods not to exceed 36 hours

S/D periods not to exceed 24 hours

Pelletizer Hood Exhaust CO Good Combustion Practices Clean Fuels

Best Practices for Minimizing Emissions NA 8.8 lb/hr CO 24-hour Average

S/U periods not to exceed 36 hours

S/D periods not to exceed 24 hours

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## Table 1 Emission Limits for Startup and Shutdown

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Pelletizer Hood Exhaust VOC Good Combustion Practices Clean Fuels

Best Practices for Minimizing Emissions NA 4.3 lb/hr VOC 24-hour Average

S/U periods not to exceed 36 hours

S/D periods not to exceed 24 hours

DRI Boiler NO x 

## Ultra Low NO x 

## Burners/Low NO x 

## Burners with Flue Gas Recirculation

Best Practices for Minimizing Emissions NA 10 lb/hr NO x 

## 3-hour Average

S/U & S/D periods not to exceed 24 hours

DRI Process Heater NO x 

## Ultra Low NO x 

## Burners

Best Practices for Minimizing Emissions NA 60.6 lb/hr NO x 

## 3-hour Average

S/U & S/D periods not to exceed 24 hours

PTS Gas Heater NO x 

## Ultra Low NO x 

## Burners/Low NO x 

## Burners with Flue Gas Recirculation

Best Practices for Minimizing Emissions NA 1.2 lb/hr NO x 

## 3-hour Average

S/U & S/D periods not to exceed 24 hours

Vacuum Degasser Boiler NO x 

## Low NO x 

## Burners with Flue Gas Recirculation

Best Practices for Minimizing Emissions NA 10 lb/hr NO x 

## 3-hour Average

S/U & S/D periods not to exceed 24 hours

Melt Shop NO x 

## Oxyfuel Burners and Direct –Shell Evacuation Control System no add-on controls

Best Practices for Minimizing Emissions NA 110 lb/hr NO x 

## 3-hour Average

S/U periods not to exceed 36 hours

S/D periods not to exceed 28 hours

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## Table 2 Pelletizer Waste Gas Emission Limits for St artup and Shutdown with LoTOx

Source Pollutant Emission Control Equipment Performance Standard Mass Emission Limit

Pelletizer Waste Gas NO x 

## LoTOx

Best Practices for Minimizing Emissions NA 92 lb/hr NO x 

## 24-hour Average

S/U periods not to exceed 36 hours

S/D periods not to exceed 24 hours

# Attachment N

BACT Mass Emission Limits for Material Handling Sources

### Minnesota Steel Industries Air Quality Permit Appli cation BACT Report -Attachment N - BACT Mass Emission Limi ts for Material Handling Sources

Stack No. Unit No. Unit
Name Pollutant Emission Unit
Controlled Emission Rate, (lb/hr) BACT

Stack/Vent
Emission Rate Limit, (lb/hr) BACT Stack/Vent

Emission
Performance Limit Performance Limit
Units
AREA 000: Mining & Crushing

SV 001 EU 002 Primary Ore Crusher PM 10 1.0 1.1 0.0025 gr/dscf

PM 1.0 1.1 0.0025 gr/dscf

Pb 1.3E-05

F 1.1E-06

EU 002 Primary Ore Crusher PM 10 0.033

PM 0.0

EU 002 Primary Ore Crusher PM 10 0.0

PM 0.0

SV 002 EU 004 Coarse Ore Screening/Conveying PM 10 0.04 1.3 0.0025 gr/dscf

PM 0.04 1.3 0.0025 gr/dscf

Pb 1.6E-05

F 1.3E-06

EU 004 Coarse Ore Screening/Conveying PM 10 0.13

PM 0.13

EU 004 Coarse Ore Screening/Conveying PM 10 0.20

PM 0.20

EU 004 Coarse Ore Screening/Conveying PM 10 0.04

PM 0.04

EU 004 Coarse Ore Screening/Conveying PM 10 0.15

PM 0.15

EU 005 Fine Ore Cobbing/Conveying PM 10 0.15

PM 0.15

EU 005 Fine Ore Cobbing/Conveying PM 10 0.15

PM 0.15

EU 005 Fine Ore Cobbing/Conveying PM 10 0.15

PM 0.15

EU 005 Fine Ore Cobbing/Conveying PM 10 0.07

PM 0.07

EU 005 Fine Ore Cobbing/Conveying PM 10 0.07

PM 0.07

EU 005 Fine Ore Cobbing/Conveying PM 10 0.15

PM 0.15

EU 005 Fine Ore Cobbing/Conveying PM 10 0.01

PM 0.01

SV 003 EU 008 Secondary Crushing Ore Storage and Handling PM 10 0.13 0.4 0.0025 gr/dscf

PM 0.13 0.4 0.0025 gr/dscf

Pb 4.8E-06

F 4.0E-07

EU 008 Secondary Crushing Ore Storage and Handling PM 10 0.13

PM 0.13

EU 008 Secondary Crushing Ore Storage and Handling PM 10 0.13

PM 0.13

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Emission Inventory\Current EI\MSI Criteria EI.xls 'Point Source EI w BACT limits' Page 1 of 7

### Minnesota Steel Industries Air Quality Permit Appli cation BACT Report -Attachment N - BACT Mass Emission Limi ts for Material Handling Sources

Stack No. Unit No. Unit
Name Pollutant Emission Unit
Controlled Emission Rate, (lb/hr) BACT

Stack/Vent
Emission Rate Limit, (lb/hr) BACT Stack/Vent

Emission
Performance Limit Performance Limit
Units

SV 004 EU 009 Secondary Crushing and Screening PM 10 0.3 1.4 0.0025 gr/dscf

PM 0.3 1.4 0.0025 gr/dscf

Pb 1.7E-05

F 1.4E-06

EU 009 Secondary Crushing and Screening PM 10 0.2

PM 0.2

EU 009 Secondary Crushing and Screening PM 10 0.3

PM 0.3

EU 009 Secondary Crushing and Screening PM 10 0.2

PM 0.2

EU 009 Secondary Crushing and Screening PM 10 0.3

PM 0.3

EU 009 Secondary Crushing and Screening PM 10 0.2

PM 0.2

AREA 100: Concentrator

SV 006 EU 013 Coarse Ore Barn PM 10 0.01 0.01 0.0025 gr/dscf

PM 0.01 0.01 0.0025 gr/dscf

Pb 1.6E-07

F 1.3E-08

SV 007 EU 014 Fine Ore Barn PM 10 0.3 0.3 0.0025 gr/dscf

PM 0.3 0.3 0.0025 gr/dscf

Pb 3.5E-06

F 2.9E-07

SV 008 EU 015 Coarse Ore Conveyor Gallery PM 10 0.02 0.1 0.0025 gr/dscf

PM 0.02 0.1 0.0025 gr/dscf

Pb 8.0E-07

F 6.7E-08

EU 015 Coarse Ore Conveyor Gallery PM 10 0.02

PM 0.02

EU 015 Coarse Ore Conveyor Gallery PM 10 0.02

PM 0.02

SV 009 EU 018 Fine Ore Conveyor Gallery PM 10 0.1 0.5 0.0025 gr/dscf

PM 0.1 0.5 0.0025 gr/dscf

Pb 5.8E-06

F 4.9E-07

EU 018 Fine Ore Conveyor Gallery PM 10 0.1

PM 0.1

EU 018 Fine Ore Conveyor Gallery PM 10 0.1

PM 0.1

EU 018 Fine Ore Conveyor Gallery PM 10 0.1

PM 0.1

SV 010 EU 022 Line 1 Primary Grinding Mill PM 10 0.2 0.3 0.0025 gr/dscf

PM 0.2 0.3 0.0025 gr/dscf

Pb 3.6E-06

F 3.0E-07

EU 022 Line 1 Primary Grinding Mill PM 10 0.1

PM 0.1

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Emission Inventory\Current EI\MSI Criteria EI.xls 'Point Source EI w BACT limits' Page 2 of 7

### Minnesota Steel Industries Air Quality Permit Appli cation BACT Report -Attachment N - BACT Mass Emission Limi ts for Material Handling Sources

Stack No. Unit No. Unit
Name Pollutant Emission Unit
Controlled Emission Rate, (lb/hr) BACT

Stack/Vent
Emission Rate Limit, (lb/hr) BACT Stack/Vent

Emission
Performance Limit Performance Limit
Units

SV 011 EU 024 Line 2 Primary Grinding Mill PM 10 0.2 0.3 0.0025 gr/dscf

PM 0.2 0.3 0.0025 gr/dscf

Pb 3.6E-06

F 3.0E-07

EU 024 Line 2 Primary Grinding Mill PM 10 0.1

PM 0.1

AREA 200: Pelletizer

SV 014 EU 028 Limestone Unloading PM 10 0.01 0.02 0.0025 gr/dscf

PM 0.01 0.02 0.0025 gr/dscf

Pb 5.3E-08

EU 029 Limestone Day Bin PM 10 0.01

PM 0.01

SV 015 EU 030 Binder Unloading PM 10 0.01 0.1 0.0025 gr/dscf

PM 0.01 0.1 0.0025 gr/dscf

Pb 5.0E-08

EU 031 Binder Day Bin PM 10 0.01

PM 0.01

EU 032 Soda Ash Unloading PM 10 0.01

PM 0.01

EU 033 Soda Ash Day Bin PM 10 0.01

PM 0.01

EU 034 Binder Feed & Conveying PM 10 0.00

PM 0.00

EU 035 Binder Blending PM 10 0.01

PM 0.01

SV 016 EU 036 Hearth Layer Bin PM 10 3.7 3.7 0.005 gr/dscf

PM 3.7 3.7 0.005 gr/dscf

Pb 7.4E-06

F 1.8E-04

EU 106 Oxide Pellets Transfer to Hearth Layer Bin PM 10

PM

SV 017 EU 037 Hearth Layer Feed PM 10 0.3 0.3 0.005 gr/dscf

PM 0.3 0.3 0.005 gr/dscf

Pb 6.3E-07

F 1.6E-05

SV 020 EU 040 Pellet Discharge PM 10 5.2 5.2 0.005 gr/dscf

PM 5.2 5.2 0.005 gr/dscf

Pb 1.0E-05

F 2.6E-04

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### Minnesota Steel Industries Air Quality Permit Appli cation BACT Report -Attachment N - BACT Mass Emission Limi ts for Material Handling Sources

Stack No. Unit No. Unit
Name Pollutant Emission Unit
Controlled Emission Rate, (lb/hr) BACT

Stack/Vent
Emission Rate Limit, (lb/hr) BACT Stack/Vent

Emission
Performance Limit Performance Limit
Units

SV 021 EU 041 Pellet Screening and Handling PM 10 2.8 7.7 0.005 gr/dscf

PM 2.8 7.7 0.005 gr/dscf

Pb 1.5E-05

F 3.8E-04

EU 041 Pellet Screening and Handling PM 10

PM

EU 041 Pellet Screening and Handling PM 10 2.8

PM 2.8

EU 041 Pellet Screening and Handling PM 10

PM

EU 041 Pellet Screening and Handling PM 10 2.1

PM 2.1

SV 022 EU 042 Pellet Screenings to Regrind Conveyors PM 10 0.03 0.1 0.005 gr/dscf

PM 0.03 0.1 0.005 gr/dscf

Pb 1.3E-07

F 3.2E-06

EU 042 Pellet Screenings to Regrind Conveyors PM 10 0.03

PM 0.03

SV 059 EU 044 Pellet Plant Area - Powder Coating Unloading PM 10 0.003 0.01 0.0025 gr/dscf

PM 0.003 0.01 0.0025 gr/dscf

Pb 1.6E-08

EU 045 Pellet Plant Area - Powder Coating Day Bin PM 10 0.00

PM 0.00

SV 023 EU 048 Oxide Pellet Stockpile Conveyor Gallery PM 10 1.0 1.0 0.0025 gr/dscf

PM 1.0 1.0 0.0025 gr/dscf

Pb 2.0E-06

F 5.0E-05

AREA 300: DIRECT REDUCED IRON (DRI)

SV 027 EU 054 DRI Line 1 Oxide Pellet Screening and Handling PM 10 0.6 1.5 0.0025 gr/dscf

PM 0.6 1.5 0.0025 gr/dscf

Pb 3.0E-06

F 7.6E-05

EU 054 DRI Line 1 Oxide Pellet Screening and Handling PM 10 0.3

PM 0.3

EU 054 DRI Line 1 Oxide Pellet Screening and Handling PM 10 0.3

PM 0.3

EU 054 DRI Line 1 Oxide Pellet Screening and Handling PM 10 0.3

PM 0.3

EU 054 DRI Line 1 Oxide Pellet Screening and Handling PM 10 0.0

PM 0.0

EU 054 DRI Line 1 Oxide Pellet Screening and Handling PM 10 0.1

PM 0.1

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Emission Inventory\Current EI\MSI Criteria EI.xls 'Point Source EI w BACT limits' Page 4 of 7

### Minnesota Steel Industries Air Quality Permit Appli cation BACT Report -Attachment N - BACT Mass Emission Limi ts for Material Handling Sources

Stack No. Unit No. Unit
Name Pollutant Emission Unit
Controlled Emission Rate, (lb/hr) BACT

Stack/Vent
Emission Rate Limit, (lb/hr) BACT Stack/Vent

Emission
Performance Limit Performance Limit
Units

SV 073 EU 060 DRI Line 1 Pellet Silos PM 10 0.1 0.3 0.0025 gr/dscf

PM 0.1 0.3 0.0025 gr/dscf

Pb 5.6E-07

F 1.4E-05

EU 060 DRI Line 1 Pellet Silos PM 10 0.1

PM 0.1

EU 060 DRI Line 1 Pellet Silos PM 10 0.1

PM 0.1

SV 060 EU 063 Line 1 Oxide Charging Area PM 10 0.1 0.1 0.0025 gr/dscf

PM 0.1 0.1 0.0025 gr/dscf

Pb 2.1E-07

F 5.2E-06

SV 029 EU 064 Line 1 Depressurization PM 10 0.8 0.8 0.005 gr/dscf

PM 0.8 0.8 0.005 gr/dscf

Pb 1.6E-06

F 4.1E-05

SV 063 EU 070 Line 1 P.T.S. Depressurization PM 10 0.5 0.5 0.005 gr/dscf

PM 0.5 0.5 0.005 gr/dscf

Pb 9.9E-06

F 2.5E-05

SV 032 EU 071 DRI Line 2 Oxide Pellet Screening and Handling PM 10 0.4 1.5 0.0025 gr/dscf

PM 0.4 1.5 0.0025 gr/dscf

Pb 3.0E-05

F 7.6E-05

EU 071 DRI Line 2 Oxide Pellet Screening and Handling PM 10 0.4

PM 0.4

EU 071 DRI Line 2 Oxide Pellet Screening and Handling PM 10 0.4

PM 0.4

EU 071 DRI Line 2 Oxide Pellet Screening and Handling PM 10 0.4

PM 0.4

EU 071 DRI Line 2 Oxide Pellet Screening and Handling PM 10 0.001

PM 0.001

EU 071 DRI Line 2 Oxide Pellet Screening and Handling PM 10 0.09

PM 0.09

SV 074 EU 077 DRI Line 2 Pellet Silos PM 10 0.1 0.3 0.0025 gr/dscf

PM 0.1 0.3 0.0025 gr/dscf

Pb 5.6E-06

F 1.4E-05

EU 077 DRI Line 2 Pellet Silos PM 10 0.1

PM 0.1

EU 077 DRI Line 2 Pellet Silos PM 10 0.1

PM 0.1

SV 031 EU 080 Line 2 Oxide Charging Area PM 10 0.1 0.1 0.0025 gr/dscf

PM 0.1 0.1 0.0025 gr/dscf

Pb 2.1E-06

F 5.2E-06

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Emission Inventory\Current EI\MSI Criteria EI.xls 'Point Source EI w BACT limits' Page 5 of 7

### Minnesota Steel Industries Air Quality Permit Appli cation BACT Report -Attachment N - BACT Mass Emission Limi ts for Material Handling Sources

Stack No. Unit No. Unit
Name Pollutant Emission Unit
Controlled Emission Rate, (lb/hr) BACT

Stack/Vent
Emission Rate Limit, (lb/hr) BACT Stack/Vent

Emission
Performance Limit Performance Limit
Units

SV 064 EU 081 Line 2 Depressurization PM 10 0.8 0.8 0.005 gr/dscf

PM 0.8 0.8 0.005 gr/dscf

Pb 1.6E-05

F 4.1E-05

SV 069 EU 087 Line 2 P.T.S. Depressurization PM 10 0.5 0.5 0.005 gr/dscf

PM 0.5 0.5 0.005 gr/dscf

Pb 9.9E-06

F 2.5E-05

SV 070 EU 088 Line 1 DRI Screening and Handling PM 10 0.2 1.5 0.005 gr/dscf

PM 0.2 1.5 0.005 gr/dscf

Pb 3.0E-05

F 7.5E-05

EU 088 Line 1 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 088 Line 1 DRI Screening and Handling PM 10 0.0

PM 0.0

EU 088 Line 1 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 088 Line 1 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 088 Line 1 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 088 Line 1 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 088 Line 1 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 088 Line 1 DRI Screening and Handling PM 10 0.2

PM 0.2

SV 071 EU 097 Line 2 DRI Screening and Handling PM 10 0.2 1.5 0.005 gr/dscf

PM 0.2 1.5 0.005 gr/dscf

Pb 3.0E-05

F 7.5E-05

EU 097 Line 2 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 097 Line 2 DRI Screening and Handling PM 10 0.0

PM 0.0

EU 097 Line 2 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 097 Line 2 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 097 Line 2 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 097 Line 2 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 097 Line 2 DRI Screening and Handling PM 10 0.2

PM 0.2

EU 097 Line 2 DRI Screening and Handling PM 10 0.2

PM 0.2

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Emission Inventory\Current EI\MSI Criteria EI.xls 'Point Source EI w BACT limits' Page 6 of 7

### Minnesota Steel Industries Air Quality Permit Appli cation BACT Report -Attachment N - BACT Mass Emission Limi ts for Material Handling Sources

Stack No. Unit No. Unit
Name Pollutant Emission Unit
Controlled Emission Rate, (lb/hr) BACT

Stack/Vent
Emission Rate Limit, (lb/hr) BACT Stack/Vent

Emission
Performance Limit Performance Limit
Units

SV 072 EU 052 DRI Area - Powder Coating Bin PM 10 0.003 0.01 0.0025 gr/dscf

PM 0.003 0.01 0.0025 gr/dscf

Pb 1.6E-08

EU 053 DRI Area - Powder Coating Day Bin PM 10 0.003

PM 0.003

AREA 400: Steel Mill

SV 039 EU 115 Hydrated Lime Unloading PM 10 0.01 0.02 0.0025 gr/dscf

PM 0.01 0.02 0.0025 gr/dscf

EU 116 Hydrated Lime Day Bin PM 10 0.0

PM 0.0

SV 040 EU 117 Calcined Limestone Unloading PM 10 0.01 0.02 0.0025 gr/dscf

PM 0.01 0.02 0.0025 gr/dscf

EU 118 Calcined Limestone Day Bin PM 10 0.0

PM 0.0

SV 041 EU 119 Carbon Unloading PM 10 0.01 0.02 0.0025 gr/dscf

PM 0.01 0.02 0.0025 gr/dscf

EU 120 Carbon Day Bin PM 10 0.0

PM 0.0

SV 042 EU 121 Fluorspar Storage Bin PM 10 0.00 0.01 0.0025 gr/dscf

PM 0.00 0.01 0.0025 gr/dscf

F 3.5E-03

EU 122 Fluorspar Feeder PM 10 0.00

PM 0.00

SV 043 EU 123 Bauxite Storage Bin PM 10 0.0 0.1 0.0025 gr/dscf

PM 0.0 0.1 0.0025 gr/dscf

EU 124 Bauxite Feeder PM 10 0.0

PM 0.0

SV 047 EU 131 Line 1 Baghouse Dust Transfer PM 10 0.01 0.01 0.0025

PM 0.01 0.01 0.0025

Pb 7.2E-05

F 4.1E-05

SV 052 EU 139 Line 2 Baghouse Dust Transfer PM 10 0.01 0.01 0.0025 gr/dscf

PM 0.01 0.01 0.0025 gr/dscf

Pb 7.2E-05

F 4.1E-05

*Averaging period is 3 hours, unless the amount of material collected during the 3 hour period is insufficient to accurately measure, in which case the averaging period will
be the time it takes to collect a sufficient amount of material.

P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Emission Inventory\Current EI\MSI Criteria EI.xls 'Point Source EI w BACT limits' Page 7 of 7

# Attachment O

Fugitive Dust Control Plan

# F u g i t

i v e D u s t C

o n t r o l P l a n

P r e p a r e d f o r M i n n e s o t a S t e e l I n d u s t r i e s

A p r i l 2 0 0 7

4 7 0 0 W e s t 7 7 t h 

## S t r e e t M i n n e a p o l i s , M N 5 5 4 3 5

- 4 8 0 3 P h o n e : ( 9 5 2 ) 8 3 2

- 2 6 0 0 F a x : ( 9 5 2 ) 8 3 2

- 2 6 0 1

# i

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# A t t a c h m e n t O

M i n n e s o t a S t e e l I n d u s t r i e s , L L C

F u g i t i v e D u s t C o n t r o l P l a n

T a b l e o f C o n t e n t s

1

. 0 I n t r o d u c t i o n

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2

. 0 P l a n O b

j e c t i v e s

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

3

. 0 F u g i t i v e E m i s s i o n s S o u r c e s

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3

. 1 U n p a v e d R o a d s

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3

. 2 P a v e d R o a d s

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3

. 3 S t o c k

p i l e s

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3

. 4 M a t e r i a l s T r a n s f

e r P o i n t s

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 3

. 5 T a i l i n g s B a s i n

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

4

. 0 O p e r a t i n g P r a c t i c e s a n d C o n t r o l M e a s u r e s

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 4

. 1 H a u l R o a d s a n d S e r v i c e R o a d s ( F S 0 0 7

, F S 0 0 8 )

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 4

. 2 P a v e d R o a d s ( F S 0 7 0 )

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 4

. 3 S t o c k

p i l e s ( F S 0 0 9

, F S 0 1 2

, F S 0 2 0

, F S 0 2 3

, F S 0 2 6

, F S 0 2 9

, F S 0 4 2

, F S 0 5 2

, F S 0 7 6 )

. . . . . . . . . . 9 4

. 4 M a t e r i a l T r a n s f

e r P o i n t s ( F S 0 0 2

, F S 0 0 3

, F S 0 0 4

, F S 0 0 5

, F S 0 0 6

, F S 0 1 1

, F S 0 1 3

, F S 0 1 4

, F S 0 1 9

, F S 0 2 1

, F S 0 2 2

, F S 0 2 4

, F S 0 2 5

, F S 0 2 7

, F S 0 2 8

, F S 0 3 0

, F S 0 3 1

, F S 0 3 2

, F S 0 3 3

, F S 0 3 4

, F S 0 3 5

, F S 0 3 7

, F S 0 3 8

, F S 0 4 0

, F S 0 4 1

, F S 0 4 3

, F S 0 4 4

, F S 0 4 5

, F S 0 4 6

, F S 0 4 7

, F S 0 4 8

, F S 0 4 9

, F S 0 5 0

, F S 0 5 1

, F S 0 5 3

, F S 0 5 4

, F S 0 5 5

, F S 0 5 6

, F S 0 5 7

, F S 0 5 8

, F S 0 5 9

, F S 0 6 0

, F S 0 6 1

, F S 0 6 2

, F S 0 6 3

, F S 0 6 4

, F S 0 6 5

, F S 0 6 6

, F S 0 6 7

, F S 0 6 8

, F S 0 6 9

, F S 0 7 0

, F S 0 7 5 )

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 4

. 5 T a i l i n g s B a s i n ( F S 0 0 8

, F S 0 1 6

, F S 0 1 7

, F S 0 1 8 )

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0

5

. 0 R e c o r d k e e p i n g

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2

6

. 0 T r a i n i n g

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 3

T a b l e s T a b l e 1 : L i s t o f F u g i t i v e S o u r c e s

## P a g e 1 o f 1

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# 1

. 0 I n t r o d u c t i o n

M i n n e s o t a S t e e l I n d u s t r i e s , L L C ( M i n n e s o t a S t e e l ) i s a p p l y i n g f o r a t o t a l f a c i l i t y p e r m i t
, i n c l u d i n g t h e a u t h o r i z a t i o n t o c o n s t r u c t i o n a n e w f a c i l i t y a n d a P a r t 7 0 o p e r a t i n g p e r m i t
, w h i c h w i l l a u t h o r i z e M i n n e s o t a S t e e l I n d u s t r i e s t o m i n e i r o n o r e a n d t o p r o d u c e f i n i s h e d s t e e l n e a r N a s h w a u k

, M i n n e s o t a

. A s p a r t o f t h e p e r m i t t i n g p r o c e s s M i n n e s o t a S t e e l I n d u s t r i e s i s r e q u i r e d t o p e r f o r m a B e s t A v a i l a b l e C o n t r o l T e c h n o l o g y ( B A C T ) a n a l y s i s

. T h e B A C T a n a l y s i s c i t e s t h e i m p l e m e n t a t i o n o f a B e s t M a n a g e m e n t P r a c t i c e s ( B M P ) p l a n f o r c o n t r o l l i n g f

u g i t i v e e m i s s i o n s

.

M i n n e s o t a S t e e l I n d u s t r i e s i s s u b m i t t i n g t h i s B M P i n c o n j u n c t i o n w i t h t h e a i r p e r m i t a p p l i c a t i o n f o r
t h e f a c i l i t y

. T h e p l a n i s b a s e d o n d u s t c o n t r o l p l a n p r a c t i c e s u s e d b y t h e m i n i n g i n d u s t r y o n t h e M e s a b i I r o n R a n g e o f n o r t h e r n M i n n e s o t a

.

## P a g e 2 o f 2

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# 2

. 0 P l a n O b j e c t i v e s

T h e F u g i t i v e C o n t r o l P l a n i d e n t i f i e s M i n n e s o t a S t e e l I n d u s t r i e s c o n t r o l m e a s u r e s a n d p r a c t i c e s t o

m i n i m i z e a n d c o n t r o l f

u g i t i v e d u s t a s r e q u i r e d b y t h e T i t l e V p e r m i t

. T h e p l a n d e f i n e s t h e f o l l o w i n g :

• P r o c e d u r e s t h a t M i n n e s o t a S t e e l I n d u s t r i e s p e r s o n n e l w i l l f o l l o w t o c o n t r o l e m i s s i o n s

• F u g i t i v e d u s t l e v e l s r e q u i r i n g c o r r e c t i v e a c t i o n s

• S t e p s t h a t w i l l b e f

o l l o w e d t o b r i n g e m i s s i o n s w i t h i n a p p r o p r i a t e r a n g e s

• S t e p s t h a t M i n n e s o t a S t e e l I n d u s t r i e s w i l l t a k e t o d e m o n s t r a t e t h a t c o r r e c t i v e p r o c e d u r e s a r e f o l l o w e d a n d t o v e r i f

y t h e f a c i l i t y i s c o n t r o l l i n g a v o i d a b l e f u g i t i v e e m i s s i o n s

T o m e e t t h e s e o b

j e c t i v e s , t h e F u g i t i v e C o n t r o l P l a n :

• I d e n t i f

i e s a l l f u g i t i v e e m i s s i o n s o u r c e s l i s t e d i n t h e T i t l e V p e r m i t a p p l i c a t i o n

• I d e n t i f

i e s t h e p r i m a r y a n d c o n t i n g e n t c o n t r o l m e a s u r e s a n d p r a c t i c e s t o c o n t r o l a n d m i n i m i z e f u g i t i v e e m i s s i o n s

.

• I d e n t i f

i e s v i s i b l e e m i s s i o n s o b s e r v a t i o n a n d c o r r e c t i v e a c t i o n r e q u i r e m e n t s

.

• I d e n t i f

i e s f u g i t i v e d u s t c o n t r o l r e c o r d k e e p i n g r e q u i r e m e n t s

.

• I d e n t i f

i e s f u g i t i v e d u s t c o n t r o l n o t i f i c a t i o n r e q u i r e m e n t s

.

• D e s c r i b e s f

u g i t i v e d u s t c o n t r o l t r a i n i n g e l e m e n t s

.

## P a g e 3 o f 3

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# 3

. 0 F u g i t i v e E m i s s i o n s S o u r c e s

T a b l e 1 l i s t s t h e f

u g i t i v e e m i s s i o n s o u r c e s i d e n t i f i e d i n t h e T i t l e V p e r m i t
, b r i e f l y d e s c r i b e s t h e

m e a s u r e s a n d p r a c t i c e s e m p l o y e d t o c o n t r o l f u g i t i v e e m i s s i o n s a t e a c h s o u r c e a n d i d e n t i f i e s t h e f u g i t i v e e m i s s i o n s o u r c e s t h a t r e q u i r e v i s i b l e e m i s s i o n o b s e r v a t i o n

. T h e s e s o u r c e s a r e f u r t h e r d e s c r i b e d b e l o w

.



# 3

. 1 U n p a v e d R o a d s

H a u l r o a d s o u r c e s s u b

j e c t t o t h e p l a n i n c l u d e :

• H a u l R o a d E m i s s i o n s ( F S 0 0 7 )

. T h i s s o u r c e i n v o l v e s 2 0 5

- t o n t r u c k s h a u l i n g m a t e r i a l s o n

u n p a v e d r o a d s

. T h e m a t e r i a l s b e i n g h a u l e d i n c l u d e s u r f a c e o v e r b u r d e n a n d w a s t e r o c k / l e a n
t a c o n i t e ( h a u l e d b e t w e e n t h e p i t a n d t h e i r r e s p e c t i v e d i s c h a r g e a r e a s )

, t a c o n i t e o r e ( h a u l e d b e t w e e n t h e p i t a n d t h e p r i m a r y c r u s h e r ) a n d c o b b e r r e j e c t ( h a u l e d f

r o m t h e c r u s h e r s t o i t s d e s i g n a t e d s t o c k p i l e )

. T h e h a u l r o a d s o n t h e s i t e w i l l b e a p p r o x i m a t e l y 1 0 m i l e s l o n g a n d f i f t y f e e t w i d e l a n e s

.

• S e r v i c e R o a d E m i s s i o n s ( F S 0 0 8 )

. T h i s s o u r c e i n v o l v e s l i g h t v e h i c l e s t r a v e l i n g o n u n p a v e d

r o a d s b e t w e e n t h e m a i n p l a n t a r e a a n d t h e c r u s h e r , m i n i n g a n d t a i l i n g s b a s i n f a c i l i t i e s

. T h e

s e r v i c e r o a d w i l l b e a p p r o x i m a t e l y 1 3 m i l e s l o n g a n d f i f t y f e e t w i d e

.

• C o n t r o l l i n g h a u l r o a d f u g i t i v e d u s t i s i m p o r t a n t f o r e m p l o y e e s a f e t y , e q u i p m e n t m a i n t e n a n c e , a s w e l l a s p r o t e c t i n g t h e a i r q u a l i t y o f t h e a r e a

. M i n n e s o t a S t e e l I n d u s t r i e s i s c o m m i t t e d t o

m i n i m i z i n g h a u l r o a d e m i s s i o n s

. H a u l r o a d d u s t s u p p r e s s i o n a c t i v i t i e s a r e d e s c r i b e d i n

s e c t i o n 4

.



# 3

. 2 P a v e d R o a d s

P a v e d r o a d e m i s s i o n s ( F S 0 7 0 ) o c c u r o n t h e a c c e s s r o a d t o t h e c o n c e n t r a t o r p l a n t p a r k i n g l o t a n d o n
t h e e a s t a n d w e s t e n t r a n c e s t o t h e m a i n p l a n t a r e a

. 2

. 5 m i l e s o f p a v e d r o a d a r e i n c l u d e d i n t h e

e m i s s i o n i n v e n t o r y a n d a r e a s s u m e d t o b e t r a v e l e d b y c a r s a n d l i g h t t r u c k s a n d b y f r e i g h t t r u c k s ,



# 3

. 3 S t o c k p i l e s

S t o c k p i l e s o u r c e s c o v e r e d b y t h e d u s t p l a n i n c l u d e :

• O v e r b u r d e n / W a s t e R o c k A r e a W i n d E r o s i o n ( F S 0 0 9 )

• C o b b e r R e

j e c t s P i l e W i n d E r o s i o n ( F S 0 1 2 )

• C o b b e r R e

j e c t s S t o c k p i l e W i n d E r o s i o n ( F S 0 1 5 )

• 1 2 0 K t o n C o n c e n t r a t e S t o c k p i l e ( F S 0 2 0 )

• O x i d e P r o d u c t S t o c k p i l e W i n d E r o s i o n ( F S 0 2 6 )

• D R I S t o c k p i l e W i n d E r o s i o n ( F S 0 2 3 )

• D R I R e m e t B u n k e r W i n d E r o s i o n ( F S 0 3 1 )

• O v e r s i z e C D R I B u n k e r W i n d E r o s i o n ( F S 0 3 4 )

## P a g e 4 o f 4

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# • G r i z z l y S t o c k p i l e W i n d E r o s i o n ( F S 0 4 5 )

• P r o c e s s e d S l a g P i l e s W i n d E r o s i o n ( F S 0 6 7 )

• N o n

- m e t a l l i c S l a g S t o c k p i l e W i n d E r o s i o n ( F S 0 6 9 )



# 3

. 4 M a t e r i a l s T r a n s f e r P o i n t s

S e v e r a l f u g i t i v e d u s t s o u r c e s a r e r e l a t e d t o t h e t r a n s f e r o f m a t e r i a l s i n t h e m i n i n g a n d c r u s h i n g , c o n c e n t r a t o r , p e l l e t i z e r , d i r e c t r e d u c e d i r o n , s t e e l m i l l

, a n d s l a g p r o c e s s i n g a r e a s

. T h e s e s o u r c e s i n c l u d e :

• O v e r b u r d e n L o a d o u t ( F S 0 0 2 )

– t r a n s f e r o f b l a s t e d w a s t e r o c k b y s h o v e l t o t r u c k s

• O v e r b u r d e n U n l o a d i n g ( T r u c k ) ( F S 0 0 3 )

– t r a n s f e r o f b l a s t e d o v e r b u r d e n b y s h o v e l t o o r e t r u c k s

• W a s t e R o c k L o a d o u t ( F S 0 0 4 )

– t r a n s f e r o f b l a s t e d w a s t e r o c k b y s h o v e l t o o r e t r u c k s

• W a s t e R o c k U n l o a d i n g ( T r u c k ) ( F S 0 0 5 )

– o r e t r u c k u n l o a d i n g o f w a s t e r o c k a t t h e s t o c k p i l e s

• C r u d e O r e L o a d o u t ( F S 0 0 6 )

– t r a n s f e r o f b l a s t e d o r e b y s h o v e l t o o r e t r u c k s

• D r o p o n t o C o b b e r R e j e c t s P i l e ( F S 0 1 1 )

– t r a n s f e r r i n g o f t a c o n i t e o r e f

r o m a c o n v e y o r o n t o t h e C o b b e r r e

j e c t s p i l e

.

• C o b b e r R e

j e c t s P i l e L o a d o u t ( F S 0 1 3 )

– u s e o f a l o a d e r a n d t r u c k t o h a u l t h e c o b b e r r e j e c t s t o t h e

c o b b e r r e j e c t s s t o c k p i l e

.

• C o b b e r R e

j e c t s U n l o a d i n g ( T r u c k ) ( F S 0 1 4 )

– u n l o a d i n g o f c o b b e r r e j e c t s f r o m a t r u c k t o t h e

s t o c k p i l e

.

• D r o p o n t o 1 2 0 K t o n C o n c e n t r a t e P i l e ( F S 0 1 9 )

– c o n v e y o r t r a n s f e r o n t o t h e 1 2 0 K t o n c o n c e n t r a t e p i l e

.

• 1 2 0 K t o n C o n c e n t r a t e S t o c k p i l e L o a d o u t ( F S 0 2 1 )

– t r a n s f e r o f c o n c e n t r a t e t o a c o n v e y o r b y u s e

o f a l o a d e r

.

• O x i d e P r o d u c t S t o c k p i l e S t a c k i n g C o n v e y o r ( F S 0 2 5 )

– c o n v e y o r t r a n s f e r o f o x i d e p r o d u c t o n t o
t h e o x i d e p r o d u c t s t o c k p i l e

.

• O x i d e P r o d u c t L o a d o u t t o R a i l c a r s ( F S 0 2 7 )

– t r a n s f e r o f o x i d e p r o d u c t t o e i t h e r t h e o x i d e f e e d

s y s t e m o r r a i l c a r s b y u s e o f a l o a d e r

.

• O x i d e F i n e s B i n D i s c h a r g e ( F S 0 2 8 )

– c o n v e y o r t r a n s f e r o f o x i d e f

i n e s i n t o t h e o x i d e f

i n e s b u n k e r

.

• O x i d e F i n e s R e t u r n t o R e g r i n d M i l l ( F S 0 2 9 )

– t r a n s f e r o f o x i d e f

i n e s t o t h e r e g r i n d m i l l b y u s e

o f a l o a d e r

.

• D R I R e c l a i m t o M e l t s h o p / R a i l c a r ( F S 0 2 4 )

– D R I p r o d u c t p i c k u p f r o m s t o c k p i l e b y f

r o n t e n d l o a d e r

.

• R a i l c a r L o a d i n g ( F S 0 3 6 )

– F E L r a i l c a r l o a d i n g o f D R I p r o d u c t f o r p e r i o d i c s a l e t o o f f

- s i t e

c u s t o m e r s

.

• D R I D r o p i n t o R e m e t B u n k e r ( F S 0 3 0 )

– c o n v e y o r t r a n s f e r o f o f f

- s p e c D R I f

r o m a c o n v e y o r i n t o
t h e R e m e t B u n k e r

.

## P a g e 5 o f 5

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# • D R I R e m e t R e t u r n t o D R I R e c l a i m H o p p e r ( F S 0 3 2 )

- t r a n s f e r o f o f f

- s p e c D R I f

r o m t h e r e m e t b u n k e r t o t h e o x i d e f

e e d s y s t e m b y u s e o f a l o a d e r

.

• O v e r s i z e C D R I D r o p i n t o B u n k e r ( F S 0 3 3 )

– c o n v e y o r t r a n s f e r o f c o l d D R I f

r o m a c o n v e y o r i n t o

a b u n k e r

.

• O v e r s i z e C D R I t o E A F b y S c r a p B u c k e t ( F S 0 3 5 )

– t r a n s f e r o f o v e r s i z e c o l d D R I t o t h e E A F b y

u s e o f a l o a d e r / s c r a p b u c k e t

.

• D R I S t o c k p i l e S t a c k i n g C o n v e y o r ( F S 0 2 2 )

– c o n v e y o r t r a n s f e r o f D R I f

r o m a c o n v e y o r o n t o t h e p e r i o d i c D R I s t o c k p i l e

.

• C D R I D r o p i n t o L i n e I E A F F e e d C o l l e c t i o n C h u t e ( F S 0 3 7 )

– c o n v e y o r t r a n s f e r o f C D R I i n t o
t h e E A F f

e e d c o l l e c t i o n c h u t e

.

• C D R I D r o p i n t o L i n e I I E A F F e e d C o l l e c t i o n C h u t e ( F S 0 3 8 )

- c o n v e y o r t r a n s f e r o f C D R I i n t o
t h e E A F f

e e d c o l l e c t i o n c h u t e

.

• L u m p L i m e / C a r b o n U n l o a d i n g ( F S 0 3 9 )

- u n l o a d i n g o f m e l t s h o p a d d i t i v e s f r o m a t r u c k o n t o a

c o n v e y o r

.

• L i m e / C a r b o n B u c k e t E l e v a t o r ( F S 0 4 0 )

– t r a n s f e r o f m a t e r i a l f

r o m t h e b u c k e t e l e v a t o r t o a

c o n v e y o r

.

• L i m e / C a r b o n T r i p p e r C o n v e y o r D r o p ( F S 0 4 1 )

– c o n v e y o r t r a n s f e r o f m e l t s h o p a d d i t i v e s f r o m a

c o n v e y o r i n t o d a y b i n s

.

• S l a g D u m p i n g ( F S 0 4 2 )

– m o l t e n s l a g t r a n s f e r f r o m s l a g p o t s t o t h e s l a g p i t s

.

• D i g g i n g P i t s / B r e a k i n g S l a g ( F S 0 4 3 )

– r e t r i e v a l a n d b r e a k i n g o f s o l i d i f i e d s l a g p r i o r t o p r o c e s s i n g

.

• L o a d i n g G r i z z l y S t o c k p i l e ( F S 0 4 4 )

– l o a d e r a c t i v i t y t o m o v e s l a g m a t e r i a l f r o m t h e s l a g d u m p i n g s t a t i o n t o t h e g r i z z l y s t o c k p i l e

.

• G r i z z l y S t o c k p i l e L o a d o u t ( F S 0 4 6 ) a n d G r i z z l y L o a d i n g ( F S 0 4 7 )

– l o a d i n g s l a g m a t e r i a l f r o m
t h e g r i z z l y s t o c k p i l e i n t o t h e g r i z z l y

.

• G r i z z l y O v e r s i z e t o S l a g D u m p i n g ( F S 0 4 8 )

– t r a n s f e r o f m a t e r i a l f r o m t h e g r i z z l y b a c k t o t h e

s l a g d u m p i n g a r e a f o r a d d i t i o n a l s i z e r e d u c t i o n

.

• G r i z z l y / F e e d e r ( F S 0 4 9 )

– t r a n s f e r o f b r o k e n s l a g m a t e r i a l f r o m t h e g r i z z l y o n t o a c o n v e y o r

.

• S l a g T r a n s f e r C o n v e y o r ( F S 0 5 0 )

– t r a n s f e r o f s l a g m a t e r i a l f

r o m a c o n v e y o r t o t h e s l a g s c r e e n

.

• S l a g S c r e e n ( F S 0 5 1 )

– t r a n s f e r o f s l a g m a t e r i a l f

r o m t h e s l a g s c r e e n t o e i t h e r a c o n v e y o r o r t h e

s l a g c r u s h e r

.

• S c r e e n e d S l a g C o n v e y o r ( F S 0 5 2 )

– c o n v e y o r t o c o n v e y o r t r a n s f e r o f s c r e e n e d s l a g

.

• S c r e e n e d S l a g C o b b e r ( F S 0 5 3 )

– s e p a r a t i o n o f s c r e e n e d s l a g i n t o m e t a l l i c a n d n o n

- m e t a l l i c f r a c t i o n s

.

• N o n

- m e t a l l i c s S t a c k e r N o

. 1 ( F S 0 5 4 ) a n d N o n

- m e t a l l i c s S t a c k e r N o

. 2 ( F S 0 5 5 )

– c o n v e y o r
t r a n s f e r o f n o n

- m e t a l l i c s l a g m a t e r i a l s t o a s t o c k p i l e

.

• M e t a l l i c s S t a c k e r N o

. 1 ( F S 0 5 6 ) a n d M e t a l l i c s S t a c k e r N o

. 2 ( F S 0 5 7 )

– c o n v e y o r t r a n s f e r o f

m e t a l l i c s l a g m a t e r i a l s f

r o m t w o c o n v e y o r s t o a s t o c k p i l e

.

• S l a g C r u s h e r ( F S 0 5 8 )

– t r a n s f e r o f c r u s h e d s l a g f r o m t h e s l a g c r u s h e r t o a c o n v e y o r

.

## P a g e 6 o f 6

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# • C r u s h e r B y

- p a s s C o n v e y o r ( F S 0 5 9 )

– c o n v e y o r t o c o n v e y o r t r a n s f e r o f s l a g m a t e r i a l

.

• C r u s h e d S l a g C o b b e r ( F S 0 6 0 )

– s e p a r a t i o n o f c r u s h e d s l a g i n t o m e t a l l i c a n d n o n

- m e t a l l i c f r a c t i o n s

.

• C r u s h e d M e t a l l i c s S t a c k e r ( F S 0 6 1 )

– t r a n s f e r o f m e t a l l i c m a t e r i a l f

r o m a c o n v e y o r t o a

s t o c k p i l e

.

• C r u s h e d N o n

- m e t a l l i c s S c r e e n ( F S 0 6 2 )

- t r a n s f e r o f n o n

- m e t a l l i c s l a g m a t e r i a l f r o m t h e s c r e e n
t o a c o n v e y o r

.

• C r u s h e d N o n

- m e t a l l i c s S t a c k e r N o

. 1 ( F S 6 3 ) a n d C r u s h e d N o n

- m e t a l l i c s S t a c k e r N o

. 2 ( F S 0 6 4 )

– t r a n s f e r o f c r u s h e d n o n

- m e t a l l i c m a t e r i a l s f r o m t w o c o n v e y o r s t o a s t o c k p i l e

.

• M e t a l l i c s R e t u r n t o E A F ( F S 0 6 5 )

– t r a n s f e r b y l o a d e r o f c r u s h e d m e t a l l i c s l a g f r o m a s t o c k p i l e
t o t h e E A F f

e e d c o l l e c t i o n c h u t e s

.

• N o n

- m e t a l l i c s L o a d o u t ( F S 0 6 6 )

– t r a n s f e r b y l o a d e r o f c r u s h e d n o n

- m e t a l l i c s l a g m a t e r i a l f r o m a

s t o c k p i l e t o t r u c k s

.

• N o n

- m e t a l l i c s U n l o a d i n g t o O f f

- s i t e S a l e o r O n

- s i t e S t o c k p i l e ( F S 0 6 8 )

- t h e u n l o a d i n g o f n o n

m e t a l l i c m a t e r i a l f

r o m a t r u c k t o a n o n

- s i t e s t o c k p i l e

.



# 3

. 5 T a i l i n g s B a s i n

T h e r e a r e f o u r f

u g i t i v e s o u r c e s a s s o c i a t e d w i t h t h e t a i l i n g s b a s i n :

• T a i l i n g s B a s i n W i n d E r o s i o n ( F S 0 1 6 )

– t a i l i n g s b a s i n b e a c h a r e a t h a t i s e x p o s e d t o w i n d e r o s i o n p r i o r t o d u s t c o n t r o l m e a s u r e s

.

• D o z e r a c t i v i t y a t T a i l i n g s B a s i n ( F S 0 1 7 )

– d i k e b u i l d i n g a n d m a i n t e n a n c e

.

• G r a d i n g a t T a i l i n g s B a s i n ( F S 0 1 8 )

– d i k e b u i l d i n g a n d m a i n t e n a n c e

.

• S e r v i c e a n d a c c e s s r o a d s a t t h e t a i l i n g s b a s i n ( F S 0 0 8 )

– l i g h t v e h i c l e t r a f f i c f o r p e r s o n n e l a n d

m a i n t e n a n c e

## P a g e 7 o f 7

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# 4

. 0 O p e r a t i n g P r a c t i c e s a n d C o n t r o l M e a s u r e s

T h e o p e r a t i n g p r a c t i c e s a n d c o n t r o l m e a s u r e s t h a t w i l l b e i m p l e m e n t e d a n d r e c o r d e d f o r t h e f u g i t i v e d u s t s o u r c e s i d e n t i f

i e d i n S e c t i o n 3 a r e d e s c r i b e d b e l o w

. M i n n e s o t a S t e e l w i l l t r a i n a n d a s s i g n

a p p r o p r i a t e p e r s o n n e l t h e r e s p o n s i b i l i t y t o c o n t r o l f u g i t i v e e m i s s i o n s i n t h e i r a r e a s o f r e s p o n s i b i l i t y

.



# 4

. 1 H a u l R o a d s a n d S e r v i c e R o a d s ( F S 0 0 7
, F S 0 0 8 )

P r i m a r y C o n t r o l s : 

# W a t e r i n g a n d o t h e r d u s t s u p p r e s s a n t a p p l i c a t i o n , r o a d m a i n t e n a n c e i n c l u d i n g

c r u s h e d r o c k s u r f a c i n g , g r a d i n g , a n d s c a r i f y i n g

.

C o n t i n g e n t C o n t r o l s : 

# I n c r e a s e d a p p l i c a t i o n o f p r i m a r y c o n t r o l s

.

P r a c t i c e s 

# : T h e o p e r a t i n g p r a c t i c e s M i n n e s o t a S t e e l I n d u s t r i e s w i l l u s e i n c l u d e , b u t a r e n o t l i m i t e d t o

t h e f o l l o w i n g :

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l p e r f o r m d a i l y v i s i b l e e m i s s i o n s c h e c k s o n a l l a c t i v e h a u l

r o a d s a t t h e b e g i n n i n g s h i f t s t h a t s t a r t d u r i n g d a y l i g h t h o u r s

. H a u l t r u c k d r i v e r s w i l l a l s o

o b s e r v e f o r v i s i b l e e m i s s i o n s d u r i n g t h e s h i f t a n d r e p o r t b y r a d i o a s n e e d e d

. I f v i s i b l e

e m i s s i o n s a r e o b s e r v e d d u r i n g t h e v i s i b l e e m i s s i o n s c h e c k o r a r e r e p o r t e d b y a n e q u i p m e n t

o p e r a t o r , M i n n e s o t a S t e e l I n d u s t r i e s w i l l i n v e s t i g a t e t h e c o n d i t i o n a n d t a k e a p p r o p r i a t e

c o r r e c t i v e a c t i o n t o a d d r e s s t h e v i s i b l e e m i s s i o n s

. T h e o b s e r v a t i o n o f v i s i b l e e m i s s i o n s d o e s

n o t
, i n a n d o f i t s e l f

, d e m o n s t r a t e n o n c o m p l i a n c e w i t h a n y a p p l i c a b l e r e q u i r e m e n t b u t i s a

s i g n a l t o t r i g g e r i n v e s t i g a t i o n a n d

, i f n e c e s s a r y , r e a s o n a b l e a n d a p p r o p r i a t e c o r r e c t i v e a c t i o n

.

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l m a i n t a i n d a i l y v i s i b l e e m i s s i o n c h e c k r e p o r t s b a s e d o n t h e

v i s i b l e e m i s s i o n s c h e c k s

. A n e x c e p t i o n r e p o r t w i l l b e f i l e d i f v i s i b l e e m i s s i o n s c a n n o t b e

c o n t r o l l e d b y u s u a l c o n t r o l s t r a t e g i e s

. E x a m p l e s o f s u c h e x c e p t i o n s m a y b e w a t e r w a g o n b r e a k d o w n , e x t r a o r d i n a r y w e a t h e r e v e n t s ( e x t r e m e l y h o t
, d r y ) e t c

. E m p l o y e e s w i l l i n f o r m t h e i r s u p e r v i s o r o f a n e x c e p t i o n c o n d i t i o n a t t h e e n d o f t h e i r s h i f t s o t h a t t h e r e p o r t c a n b e f i l l e d o u t

.

• I n n o n

- f

r e e z i n g c o n d i t i o n s , d u s t w i l l b e c o n t r o l l e d b y t h e f o l l o w i n g s t r a t e g i e s :

o W a t e r w i l l b e a p p l i e d t o t h e a c t i v e h a u l r o a d s d u r i n g t h e d a y a n d a f t e r n o o n s h i f

t s , a s

r e q u i r e d b y w e a t h e r , t r a f f i c , a n d r o a d c o n d i t i o n s

. W a t e r t r u c k s w i l l b e d i s p a t c h e d

a n d u n p a v e d r o a d s w i l l b e w a t e r e d i f e x c e s s i v e d u s t i n g i s e n c o u n t e r e d

. S o m e

w e a t h e r c o n d i t i o n s d u r i n g t h e s u m m e r m o n t h s , s u c h a s l o w h u m i d i t y a n d h i g h w i n d s , r e q u i r e a h i g h e r w a t e r f

r e q u e n c y

. T h e f

r e q u e n c y a n d a m o u n t o f w a t e r a p p l i c a t i o n i s

a d j u s t e d d e p e n d i n g o n w e a t h e r c o n d i t i o n s

.

o H a u l r o a d s w i l l b e g r a d e d a s r e q u i r e d

.

o C r u s h e d a n d s c r e e n e d r o c k w i l l b e a d d e d t o t h e r o a d s u r f a c e t o m i n i m i z e f u g i t i v e d u s t
g e n e r a t i o n

.

o L i q u i d c h e m i c a l d u s t s u p p r e s s a n t m a y a l s o b e a p p l i e d t o s o m e h i g h t r a f f i c a r e a s f o r d u s t c o n t r o l a s n e e d e d

.

• I n f

r e e z i n g c o n d i t i o n s , d u s t w i l l b e c o n t r o l l e d b y t h e f o l l o w i n g s t r a t e g i e s :

o S o l i d o r l i q u i d c h e m i c a l d u s t s u p p r e s s a n t w i l l b e a p p l i e d t o t h e h a u l r o a d i n l a t e f a l l

p r i o r t o f r e e z e u p

.

## P a g e 8 o f 8

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c



# o H a u l r o a d s w i l l b e s c a r i f i e d a s n e c e s s a r y

.

o N e w h a u l r o a d m a t e r i a l w i l l b e a p p l i e d a s n e e d e d

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l m a i n t a i n a d e q u a t e w a t e r i n g c a p a c i t y , i n c l u d i n g b a c k u p i n t h e

e v e n t o f b r e a k d o w n , t o c o n t r o l d u s t d u r i n g t y p i c a l s u m m e r c o n d i t i o n s

.

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l m a i n t a i n d a i l y w a t e r i n g r e c o r d s a n d c h e m i c a l a p p l i c a t i o n

r e c o r d s

. T h e r e c o r d s w i l l i n c l u d e t h e w a t e r i n g t r u c k i d e n t i f i c a t i o n n u m b e r , t h e n u m b e r o f

w a t e r l o a d s a p p l i e d p e r s h i f t a n d t h e o p e r a t o r n a m e

. M i n n e s o t a S t e e l I n d u s t r i e s w i l l e q u i p

e a c h w a t e r i n g t r u c k w i t h t h e s a m e G P S m o n i t o r i n g s y s t e m u s e d b y t h e o t h e r h a u l t r u c k s

.

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l r e l y o n N a t i o n a l W e a t h e r S e r v i c e ( N W S ) r e p o r t s f r o m t h e H i b b i n g A i r p o r t t o p r o v i d e a r e c o r d o f d a i l y p r e c i p i t a t i o n a n d h u m i d i t y , h i g h a n d l o w t e m p e r a t u r e , w i n d s p e e d a n d d i r e c t i o n r e a d i n g s , a n d d e w p o i n t

.

• V e h i c l e m i l e s t r a v e l e d ( V M T ) w i l l b e c a l c u l a t e d p e r i o d i c a l l y b a s e d o n m i n e p r o d u c t i o n a n d a

r e c o r d w i l l b e k e p t o n s i t e

. T h i s i n f o r m a t i o n w i l l b e s e n t t o t h e M P C A a n n u a l l y f o r i n c o r p o r a t i n g i n t o t h e a n n u a l e m i s s i o n s i n v e n t o r y

.

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l e v a l u a t e n e w t e c h n o l o g i e s o r m e t h o d s i n d u s t s u p p r e s s i o n f o r
t h e i r t e c h n i c a l a n d e c o n o m i c f e a s i b i l i t y a s t h e y b e c o m e c o m m e r c i a l l y a v a i l a b l e

.

R e c o r d k e e p i n g : 

# M i n n e s o t a S t e e l I n d u s t r i e s w i l l m a i n t a i n t h e f o l l o w i n g r e c o r d s o n s i t e :

• H a u l R o a d F u g i t i v e E m i s s i o n s E x c e p t i o n R e p o r t ( F S 0 0 7 a n d F S 0 0 8 )

• D a i l y W a t e r i n g R e p o r t s

• D a i l y w e a t h e r i n f o r m a t i o n a s r e p o r t e d b y t h e N a t i o n a l W e a t h e r S e r v i c e a t t h e H i b b i n g A i r p o r t

.

• T h e a p p l i c a t i o n o f c h e m i c a l d u s t s u p p r e s s a n t s w i l l b e r e c o r d e d a n d r e p o r t e d f r o m M i n n e s o t a S t e e l I n d u s t r i e s ’ p u r c h a s e r e c o r d s

.

• T r a c k i n g a n d c a l c u l a t i o n o f a n n u a l v e h i c l e m i l e s t r a v e l e d ( V M T ) w i l l b e b a s e d o n m i n e p r o d u c t i o n

.



# 4

. 2 P a v e d R o a d s ( F S 0 7 0 )

P r i m a r y C o n t r o l s : 

# S t r e e t s w e e p i n g a s n e e d e d

.

C o n t i n g e n t C o n t r o l s : 

# I n c r e a s e d a p p l i c a t i o n o f p r i m a r y c o n t r o l s

.

P r a c t i c e s 

# : T h e o p e r a t i n g p r a c t i c e s M i n n e s o t a S t e e l I n d u s t r i e s w i l l u s e i n c l u d e , b u t a r e n o t l i m i t e d t o

s w e e p i n g o r w a s h i n g o f t h e p a v e d r o a d s a s n e e d e d t o p r e v e n t f u g i t i v e e m i s s i o n s

.

R e c o r d k e e p i n g : 

# M i n n e s o t a S t e e l I n d u s t r i e s w i l l m a i n t a i n t h e f o l l o w i n g r e c o r d s o n s i t e :

• T r a c k i n g a n d c a l c u l a t i o n o f a n n u a l v e h i c l e m i l e s t r a v e l e d ( V M T ) w i l l b e b a s e d o n e m p l o y e e

c o u n t s a n d e s t i m a t e d p e r i o d i c a l l y

.

## P a g e 9 o f 9

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# 4

. 3 S t o c k p i l e s ( F S 0 0 9
, F S 0 1 2
, F S 0 2 0
, F S 0 2 3
, F S 0 2 6
, F S 0 2 9
, F S 0 4 2
, F S 0 5 2
, F S 0 7 6 )

P r i m a r y C o n t r o l s : 

# N a t u r a l m o i s t u r e c o n t e n t o f s t o c k p i l e d m a t e r i a l s

C o n t i n g e n t C o n t r o l s : 

# W a t e r s p r a y a s n e e d e d d u r i n g n o n

- f r e e z i n g c o n d i t i o n s

.

P r a c t i c e s 

# : T h e o p e r a t i n g p r a c t i c e s M i n n e s o t a S t e e l I n d u s t r i e s w i l l u s e i n c l u d e , b u t a r e n o t l i m i t e d t o

t h e f o l l o w i n g :

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l p e r f o r m v i s i b l e e m i s s i o n s c h e c k s o n a l l s t o c k p i l e s l i s t e d

a b o v e o n c e p e r d a y d u r i n g d a y l i g h t h o u r s

.

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l m i n i m i z e t h e d r o p d i s t a n c e s o n t o e a c h s t o c k p i l e a s f a r a s p r a c t i c a b l e

. R e c o r d k e e p i n g : 

# M i n n e s o t a S t e e l I n d u s t r i e s w i l l m a i n t a i n t h e f o l l o w i n g r e c o r d s o n s i t e :

• D a i l y V i s i b l e E m i s s i o n s C h e c k l i s t s ( F S 0 1 2

, F S 0 2 0

, F S 0 2 3

, F S 0 2 6

, F S 0 2 9

, F S 0 4 2

, F S 0 5 2

, F S 0 7 4 a n d F S 0 7 6 )

• M a t e r i a l H a n d l e r R e p o r t ( F S 0 1 2

, F S 0 2 0

, F S 0 2 3

, F S 0 2 6

, F S 0 2 9

, F S 0 4 2

, F S 0 5 2

, F S 0 7 4

a n d F S 0 7 6 )



# 4

. 4 M a t e r i a l T r a n s f e r P o i n t s ( F S 0 0 2
, F S 0 0 3
, F S 0 0 4
, F S 0 0 5
, F S 0 0 6
, F S 0 1 1
, F S 0 1 3
, F S 0 1 4
, F S 0 1 9
, F S 0 2 1
, F S 0 2 2
, F S 0 2 4
, F S 0 2 5
, F S 0 2 7
, F S 0 2 8
, F S 0 3 0
, F S 0 3 1
, F S 0 3 2
, F S 0 3 3
, F S 0 3 4
, F S 0 3 5
, F S 0 3 7
, F S 0 3 8
, F S 0 4 0
, F S 0 4 1
, F S 0 4 3
, F S 0 4 4
, F S 0 4 5
, F S 0 4 6
, F S 0 4 7
, F S 0 4 8
, F S 0 4 9
, F S 0 5 0
, F S 0 5 1
, F S 0 5 3
, F S 0 5 4
, F S 0 5 5
, F S 0 5 6
, F S 0 5 7
, F S 0 5 8
, F S 0 5 9
, F S 0 6 0
, F S 0 6 1
, F S 0 6 2
, F S 0 6 3
, F S 0 6 4
, F S 0 6 5
, F S 0 6 6
, F S 0 6 7
, F S 0 6 8
, F S 0 6 9
, F S 0 7 0
, F S 0 7 5 )

P r i m a r y C o n t r o l s : 

# N a t u r a l m o i s t u r e c o n t e n t o f m a t e r i a l s , m i n i m i z e d d r o p d i s t a n c e s w h e n p o s s i b l e

.

C o n t i n g e n t C o n t r o l s : 

# N o n e

.

P r a c t i c e s 

# : T h e o p e r a t i n g p r a c t i c e s M i n n e s o t a S t e e l I n d u s t r i e s w i l l u s e i n c l u d e , b u t a r e n o t l i m i t e d t o

t h e f o l l o w i n g :

• M i n n e s o t a S t e e l I n d u s t r i e s w i l l p e r f o r m v i s i b l e e m i s s i o n s c h e c k s o n a l l m a t e r i a l t r a n s f e r p o i n t s l i s t e d a b o v e o n c e p e r d a y d u r i n g d a y l i g h t h o u r s

.

R e c o r d k e e p i n g : 

# M i n n e s o t a S t e e l I n d u s t r i e s w i l l m a i n t a i n t h e f o l l o w i n g r e c o r d s o n s i t e :

• D a i l y V i s i b l e E m i s s i o n s C h e c k l i s t s ( F S 0 0 1

, F S 0 1 1

, F S 0 1 4

, F S 0 1 6

, F S 0 1 7

, F S 0 1 9

, F S 0 2 0

, F S 0 2 2

, F S 0 2 5

, F S 0 4 2

, a n d F S 0 7 0

. )

• M a t e r i a l H a n d l e r R e p o r t ( F S 0 0 2

, F S 0 0 3

, F S 0 0 4

, F S 0 0 5

, F S 0 0 6

, F S 0 1 0

, F S 0 1 3

, F S 0 1 4

, F S 0 2 1

, F S 0 2 7

, F S 0 4 2

, F S 0 4 6

, F S 0 6 6

, a n d F S 0 6 8 )

## P a g e 1 0 o f 1 0

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# 4

. 5 T a i l i n g s B a s i n ( F S 0 0 8
, F S 0 1 6
, F S 0 1 7
, F S 0 1 8 )

P r i m a r y C o n t r o l s : 

# B e a c h a r e a m i n i m i z a t i o n , m u l c h i n g , v e g e t a t i o n , s y s t e m a t i c d u m p i n g

.

C o n t i n g e n t C o n t r o l s : 

# C h a n g e t a i l i n g s d i s c h a r g e p o i n t s

.

P r a c t i c e s 

# : T h e o p e r a t i n g p r a c t i c e s M i n n e s o t a S t e e l I n d u s t r i e s w i l l u s e i n c l u d e , b u t a r e n o t l i m i t e d t o

t h e f o l l o w i n g :

• D u r i n g f

r e e z i n g m o n t h s ( t y p i c a l l y l a t e N o v e m b e r t h r o u g h e a r l y A p r i l )

, f r e s h l y d e p o s i t e d

t a i l i n g s f r e e z e a n d a r e c o v e r e d w i t h s n o w f a l l w h i c h m i n i m i z e s d u s t e m i s s i o n s

. M u l c h i n g d u r i n g t h e w i n t e r , e s p e c i a l l y w h e n s n o w i s p r e s e n t
, w i l l b e d o n e t o r e d u c e f u g i t i v e d u s t l i f

t

o f f

. W h e n t h e s n o w m e l t s t h e m u l c h f o r m s a m a t o n t h e t a i l i n g s t h e r e b y m i n i m i z i n g

e m i s s i o n s

.

• T a i l i n g s d e p o s i t e d d u r i n g w i n t e r w i l l b e v e g e t a t e d i n e a r l y s p r i n g b e f o r e t h e t a i l i n g s

c o m p l e t e l y t h a w

.

• B e a c h a r e a s d e v e l o p e d d u r i n g n o n

- f r e e z i n g m o n t h s ( t y p i c a l l y e a r l y A p r i l t h r o u g h l a t e N o v e m b e r ) w i l l b e t r e a t e d ( i

. e

. m u l c h e d a p p l i e d

, v e g e t a t e d

, o r a p p l i c a t i o n o f d u s t

s u p p r e s s a n t s ) a s s o o n a s p r a c t i c a l t o p r e v e n t l a r g e a r e a s o f e x p o s e d b e a c h f r o m d r y i n g o u t
, e s p e c i a l l y d u r i n g f

r e e z e d r y i n g c o n d i t i o n s o r h o t
, w i n d y c o n d i t i o n s

. D i k e c o n s t r u c t i o n t e c h n i q u e s a n d w a t e r l e v e l m a n a g e m e n t w i l l h e l p m i n i m i z e e x p o s e d b e a c h a r e a s , w h i c h w i l l b e t r e a t e d i n a t i m e l y m a n n e r t o l i m i t t h e r i s k o f d r y c o n d i t i o n s o n t h e b e a c h e s

. I d e a l l y f r e s h b e a c h w i l l b e t r e a t e d w i t h i n t w o w e e k s , b u t t h e s e a c t i v i t i e s a r e d e p e n d e n t o n w e a t h e r

c o n d i t i o n s a n d b a s i n c o n f i g u r a t i o n s

. M u l c h w i l l b e s t a g e d o n

- s i t e t o m i n i m i z e t h e t i m e

n e c e s s a r y f o r i t t o b e a p p l i e d o n c e c o n d i t i o n s a r e s u i t a b l e

.

•

.

• D u r i n g c o n s t r u c t i o n a n d

, t o t h e e x t e n t p o s s i b l e d u r i n g o p e r a t i o n s , b e r m s a n d b e n c h e s w i l l b e g r a d e d t o g e n t l e s l o p e s t o r e d u c e w i n d r e s i s t a n c e , w h i c h w i l l l i m i t t h e p o t e n t i a l f o r f u g i t i v e d u s t e m i s s i o n s

.

• M i n n e s o t a S t e e l w i l l m a i n t a i n a s y s t e m a t i c d i s c h a r g e s c h e d u l e

. T h e t a i l i n g s b a s i n w i l l b e d e s i g n e d w i t h m u l t i p l e c e l l s

. T a i l i n g s w i l l t y p i c a l l y b e d i s c h a r g e d t o o n l y o n e c e l l a t a t i m e

. T h e i d l e c e l l s w i l l b e v e g e t a t e d a n d w i l l r e m a i n u n d i s t u r b e d f o r l o n g p e r i o d s o f t i m e ( u p t o 2

y e a r s ) t h e r e b y m i n i m i z i n g d u s t e m i s s i o n s f r o m t h o s e p o r t i o n s o f t h e t a i l i n g s b a s i n

. T h e i d l e

c e l l s w i l l b e r e v e g e t a t e d

, i f n e c e s s a r y , t o m a i n t a i n a d e q u a t e v e g e t a t i o n f o r d u s t c o n t r o l

p u r p o s e s

.

• I n a d d i t i o n , t h e d u s t s u p p r e s s i n g o b j e c t i v e s f o r t h e a c t i v e c e l l i n c l u d e :

o M a i n t e n a n c e o f a d e q u a t e f r e e b o a r d a r o u n d t h e d i k e p e r i m e t e r

o H i g h i n t e r i o r w a t e r l e v e l s b y m a i n t a i n i n g u n o b s t r u c t e d g r a v i t y f l o w o f s l u r r y t o w a r d

t h e d e c a n t p o o l ( i n t e r i o r )

o A d e q u a t e p u m p i n g c a p a c i t y a l l o w i n g f o r d i s c h a r g e t o c o m p l e t e l y e n c i r c l e t h e d i k e p e r i m e t e r c r e a t i n g a s t r o n g d i k e a n d a d e q u a t e b e a c h t o p r o t e c t t h e d i k e

.

o I f h i g h w i n d s a r e f

o r e c a s t d u r i n g t h e n o n

- f

r e e z i n g m o n t h s , e i t h e r t h e t a i l i n g s d i s c h a r g e w i l l b e m o v e d o r c l e a r w a t e r w i l l b e p u m p e d o n t o b e a c h a r e a s t h a t a r e

e x p o s e d a n d a r e d e t e r m i n e d t o b e d r y

.

## P a g e 1 1 o f 1 1

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# • A s n e e d e d

, M i n n e s o t a S t e e l I n d u s t r i e s w i l l a p p l y w a t e r o r c h e m i c a l d u s t s u p p r e s s i o n

m a t e r i a l s t o t h e t a i l i n g s b a s i n s e r v i c e r o a d s

.

## P a g e 1 2 o f 1 2

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# 5

. 0 R e c o r d k e e p i n g

T h e f o l l o w i n g r e c o r d s w i l l b e m a i n t a i n e d a t M i n n e s o t a S t e e l I n d u s t r i e s f o r t h e p e r i o d s p e c i f i e d b y t h e T i t l e V p e r m i t :

• D a i l y V i s i b l e E m i s s i o n s C h e c k s

. D u e t o t h e l a r g e n u m b e r o f t h e s e r e p o r t s t h a t a r e g e n e r a t e d

o n a d a i l y b a s i s ( o n e c o p y o f e a c h r e p o r t p e r d a y )

, M i n n e s o t a S t e e l I n d u s t r i e s c o m m i t s t o

r e t a i n i n g t h e s e r e c o r d s f o r a p e r i o d o f n o l e s s t h a n o n e y e a r

.

• P r i m a r y C r u s h e r A t t e n d a n t R e p o r t ( F S 0 6 5 ) *

• C r u s h i n g C o n t r o l R o o m R e p o r t ( F S 0 6 5

– 0 6 9 ) *

• C o n c e n t r a t o r M a t e r i a l H a n d l e r R e p o r t ( F S 0 1 1

– 0 1 8 ) *

• P e l l e t i z e r M a t e r i a l H a n d l e r R e p o r t ( F S 0 1 9

– 0 2 7 ) *

• D i r e c t R e d u c e d I r o n M a t e r i a l H a n d l e r R e p o r t ( F S 0 2 8

– 0 4 5 ) *

• S t e e l M i l l M a t e r i a l H a n d l e r R e p o r t ( F S 0 4 6

– 0 4 8 ) *

• S l a g P r o c e s s i n g M a t e r i a l H a n d l e r R e p o r t ( F S s 0 4 9

– 0 7 6 ) *

• D a i l y W a t e r i n g R e p o r t s H a u l R o a d F u g i t i v e E m i s s i o n s E x c e p t i o n R e p o r t s *

• D a i l y W e a t h e r I n f o r m a t i o n R e p o r t s ( f r o m N a t i o n a l W e a t h e r S e r v i c e a t H i b b i n g A i r p o r t ) *

• E m p l o y e e T r a i n i n g R e c o r d s *

• M P C A L e t t e r o f A p p r o v a l o f t h i s F u g i t i v e C o n t r o l P l a n

•

• * T h e s e r e c o r d s a r e a n t i c i p a t e d t o b e e l e c t r o n i c r e p o r t s g e n e r a t e d f r o m t h e p l a n t p r o c e s s

c o n t r o l s y s t e m s

.

## P a g e 1 3 o f 1 3

P : \ M p l s \ 2 3 M N \ 3 1 \ 2 3 3 1 2 8 6 M S I \ W o r k F i l e s \ W O E 0 0 3 A i r P e r m i t A p p l i c a t i o n \ 1 0 3 B A C T R e s p o n s e t o C o m m e n t \ U p d a t e d B A C T R e p o r t ( M a r 2 0 0 7 ) \ A t t a c h m e n t s \ A t t a c h O

- F u g i t i v e C o n t r o l P l a n

- R e v i s e d 0 4

_ 3 0

_ 0 7

. d o c 

# 6

. 0 T r a i n i n g

A n i n t e g r a l p a r t o f t h e i m p l e m e n t a t i o n o f t h e F u g i t i v e C o n t r o l P l a n i s a p p r o p r i a t e t r a i n i n g f o r t h e p e r s o n n e l i n v o l v e d

. T r a i n i n g w i l l b e p r o v i d e d f o r a l l l e v e l s o f p e r s o n n e l a t t h e f a c i l i t y a n d w i l l c o v e r

a s u b s e t o f t h e f

o l l o w i n g s u b

j e c t s a s n e e d e d f

o r i n d i v i d u a l l e v e l s o f r e s p o n s i b i l i t y :

• E m p l o y e e R e s p o n s i b i l i t i e s

• F o r m s a n d R e c o r d K e e p i n g

• R e p o r t i n g

• C o r r e c t i v e A c t i o n s

• M a i n t e n a n c e

• W o r k O r d e r s

• D u s t O b s e r v a t i o n a n d V i s i b i l i t y T r a i n i n g

• W e a t h e r O b s e r v a t i o n s

• L o c a t i o n o f I n f

o r m a t i o n

M i n n e s o t a S t e e l I n d u s t r i e s w i l l p r o v i d e t r a i n i n g i n t h e a r e a s l i s t e d a b o v e t o n e w e m p l o y e e s a s t h e i r j o b f u n c t i o n d e m a n d s

. R e f

r e s h e r t r a i n i n g w i l l b e p r o v i d e d t o e x i s t i n g e m p l o y e e s o n a n a n n u a l b a s i s

.

# T a b l e sP:\Mpls\23MN\31\2331286MSI\WorkFiles\WOE003AirPermitApplication\103BACTResponsetoComment\UpdatedBACTReport(Mar2007)\Attachments\AttachO-FugitiveControlPlan-Revised04_30_07.docTable1ListofFugitiveSourcesFugitiveSourceIDFugitiveSourceDescriptionAreaOperating/ControlPracticeDailyVisibleEmissionsCheckRequired?FS001DrillingMiningandCrushingNoneYesFS002OverburdenLoadoutMiningandCrushingNoneNoFS003OverburdenUnloading(Truck)MiningandCrushingNoneNoFS004WasteRockLoadoutMiningandCrushingNoneNoFS005WasteRockUnloading(Truck)MiningandCrushingNoneNoFS006CrudeOreLoadoutMiningandCrushingNoneNoFS007HaulRoadEmissionsMiningandCrushingWateringandotherdustsuppressantapplication;roadmaintenanceYesFS008ServiceRoadEmissionsMiningandCrushingWateringandotherdustsuppressantapplication;roadmaintenanceYesFS070PavedRoadEmissionsMiningandCrushingWateringandotherdustsuppressantapplication;roadmaintenanceYesFS009Overburden/WasteRockAreaWindErosionMiningandCrushingNoneNoFS010Overburden/WasteRockBulldozerMiningandCrushingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS011DropontoCobberRejectsPileConcentratornaturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS012CobberRejectsPileWindErosionConcentratorLimitedpilesize;naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS013CobberRejectsPileLoadoutConcentratornaturalmoisture;watersprayasneededduringnon-freezingconditionsNoTable1ListofFugitiveSourcesFugitiveSourceIDFugitiveSourceDescriptionAreaOperating/ControlPracticeDailyVisibleEmissionsCheckRequired?FS014CobberRejectsUnloading(Truck)Concentratornaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS015CobberRejectsPileWindErosionConcentratorLimitedpilesize;naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS016TailingBasinWindErosionConcentratorNaturalmoistureoftailings;revegetationYesFS017DozerActivityatTailingsBasinConcentratorNaturalmoistureoftailingsYesFS018GradingatTailingsBasinConcentratorNaturalmoistureoftailingsNoFS019Droponto120KtonConcentrateStockpilePelletizernaturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS020120KtonConcentrateStockpileWindErosionPelletizernaturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS021120KtonConcentrateStockpileLoadoutPelletizernaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS025OxideProductStockpileStackingConveyorPelletizernaturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS026OxideProductStockpileWindErosionPelletizernaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS074PelletizerBuilding,NaturalDraftPelletizerPartialenclosure(Pelletizerbuilding)NoFS027OxideProductLoadouttoRailcarsPelletizernaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS028OxideFinesBinDischargeDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS029OxideFinesReturntoDirectReducednaturalmoisture;watersprayasneededduringnon-freezingNoTable1ListofFugitiveSourcesFugitiveSourceIDFugitiveSourceDescriptionAreaOperating/ControlPracticeDailyVisibleEmissionsCheckRequired?RegrindMillIron(DRI)conditionsFS030DRIDropintoRemetBunkerDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS031DRIRemetBunkerWindErosionDirectReducedIron(DRI)Limitedpilesize;naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS032DRIRemetReturntoDRIReclaimHopperDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS033OversizeCDRIDropintoBunkerDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS034OversizeCDRIBunkerWindErosionDirectReducedIron(DRI)Limitedpilesize;naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS035OversizeCDRItoEAFbyscrapbucketDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS022DRIStockpileStackingConveyorDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS023DRIStockpileWindErosionDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS024DRIReclaimtoMeltshop/RailcarDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS036RailcarLoadingDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS037CDRIDropintoLineIEAFFeedCollectionChuteDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS038CDRIDropintoLineIIEAFFeedCollectionChuteDirectReducedIron(DRI)naturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS039LumpLime/CarbonSteelMillnaturalmoisture;watersprayasneededduringnon-freezingNoTable1ListofFugitiveSourcesFugitiveSourceIDFugitiveSourceDescriptionAreaOperating/ControlPracticeDailyVisibleEmissionsCheckRequired?UnloadingconditionsFS040Lime/CarbonBucketElevatorSteelMillnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS041Lime/CarbonTripperConveyorDropSteelMillnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS042SlagDumpingSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsYesFS043DiggingPits/BreakingSlagSlagProcessingWateringNoFS044LoadingGrizzlyStockpileSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNo1FS045GrizzlyStockpileWindErosionSlagProcessingLimitedpilesize;naturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS046GrizzlyStockpileLoadoutSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS047GrizzlyLoadingSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS048GrizzlyOversizetoSlagDumpingSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS049Grizzly/FeederSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS050SlagTransferConveyorSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS051SlagScreenSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS052ScreenedSlagConveyorSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS053ScreenedSlagCobberSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingNoTable1ListofFugitiveSourcesFugitiveSourceIDFugitiveSourceDescriptionAreaOperating/ControlPracticeDailyVisibleEmissionsCheckRequired?conditionsFS054Non-metallicsStackerNo.1SlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS055Non-metallicsStackerNo.2SlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS056MetallicsStackerNo.1SlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS057MetallicsStackerNo.2SlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS058SlagCrusherSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS059CrusherBy-passConveyorSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS060CrushedSlagCobberSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS061CrushedMetallicsStackerSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS062CrushedNon-metallicsScreenSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS063CrushedNon-metallicsStackerNo.1SlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS064CrushedNon-metallicsStackerNo.2SlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS065MetallicsReturntoEAFSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS066Non-metallicsLoadoutSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS067ProcessedSlagPilesSlagProcessingLimitedpilesize;naturalmoisture;watersprayasneededNoTable1ListofFugitiveSourcesFugitiveSourceIDFugitiveSourceDescriptionAreaOperating/ControlPracticeDailyVisibleEmissionsCheckRequired?WindErosionduringnon-freezingconditionsFS068Non-metallicsUnloadingtoOff-siteSaleorOnSiteStockpileSlagProcessingnaturalmoisture;watersprayasneededduringnon-freezingconditionsNoFS069Non-metallicSlagStockpileWindErosion(inpermitarea)SlagProcessingLimitedpilesize;naturalmoisture;watersprayasneededduringnon-freezingconditionsNo