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 77th Street 

Minneapolis, MN 55435-4803 

Phone: (952) 832-2600 

Fax: (952) 832-2601
Minnesota Steel Page - i Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Minnesota Steel Industries 

Best Available Control 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 under 40 CFR Parts 60 (NSPS), 61 (NESHAP), and 63 

(NESHAP/MACT)....................................................................................................................18

3.5.1 40 CFR 60 Subpart Dc, Standards of Performance 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 for Steel Plants: Electric Arc Furnaces and 

Argon-Oxygen Decarburization Vessels Constructed 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 Institutional Boilers and Process Heaters....................... 22

4.0 Emission Control Technologies..........................................................................................................24

4.1 Overview of Emission Control Technologies...........................................................................24

4.2 Particulate Matter (PM & PM10), 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 (SO2), 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 (NOx) Emission Control Technologies..........................................................32

4.5.1 Sources of NOx Emissions .......................................................................................... 32

4.5.2 Identification of NOx Control Technologies................................................................ 33
Minnesota Steel Page - ii Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

4.6 Carbon Monoxide (CO) and Volatile Organic 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 (H2S) 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 Startup, 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 Handling 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 PM10) Emissions........................................................52

7.4.1 Sources of Induration Furnace Particulate Matter Emissions ...................................... 52

7.4.2 Identification of Potential PM/PM10 Control Technologies......................................... 52

7.4.3 Elimination of Technically Infeasible PM/PM10 Control Options............................... 52

7.4.4 Evaluation of Most Effective Control Technologies ................................................... 54

7.4.5 Pellet Plant Indurating Furnace PM/PM10 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 (SO2) Emissions ..........................................................................58

7.6.1 Sources of Induration Furnace SO2 Emissions ............................................................ 58

7.6.2 Identification of Potential SO2 Control Technologies ................................................. 59

7.6.3 Elimination of Technically Infeasible SO2 Control Options........................................ 59

7.6.4 Ranking of Remaining SO2 Control Technologies by Control Effectiveness.............. 61

7.6.5 Evaluation of Most Effective SO2 Control Technologies ............................................ 61

7.6.6 Pellet Plant Indurating Furnace SO2 BACT Selection................................................. 63

7.7 Pellet Plant Nitrogen Oxides (NOx) Emissions.........................................................................64

7.7.1 Sources of Induration Furnace NOx Emissions............................................................ 64

7.7.2 Identification of Potential NOx Control Technologies................................................. 64

7.7.3 Elimination of Technically Infeasible NOx Control Options....................................... 65

7.7.4 Ranking of Remaining NOx Control Technologies by Control Effectiveness............. 72

7.7.5 Evaluation of Most Effective NOx Control Technologies ........................................... 72
Minnesota Steel Page - iii Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

7.7.6 Pellet Plant Indurating Furnace NOx 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..............................................................................................95

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 ....................................................................................................104

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 Package Boiler ................................................................................................................110

8.3 DRI Boiler Particulate MatterPM/PM10 Emission..................................................................110

8.3.1 Identification of Potential PM/PM10 Control Technologies....................................... 110

8.3.2 Elimination of Technically Infeasible PM/PM10 Control Options ............................. 110
Minnesota Steel Page - iv Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.3.3 Rank Remaining PM/PM10 Control Technologies by Control Effectiveness ............ 112

8.3.4 Evaluation of Most Effective PM Control Technologies........................................... 112

8.3.5 DRI Boiler PM/PM10 BACT Selection ...................................................................... 112

8.4 DRI Package Boiler Visible Emissions ..................................................................................114

8.4.1 DRI Package Boiler Visible Emissions BACT Selection.......................................... 114

8.5 DRI Boiler Sulfur Dioxide (SO2) emission.............................................................................115

8.5.1 Identification of Potential SO2 Control Technologies ............................................... 115

8.5.2 Elimination of Technically Infeasible SO2 Control Options...................................... 115

8.5.3 Ranking of Remaining SO2 Control Technologies by Control Effectiveness............ 116

8.5.4 Evaluation of Most Effective SO2 Control Technologies .......................................... 117

8.5.5 DRI Boiler SO2 BACT Selection............................................................................... 117

8.6 DRI Boiler Nitrogen Oxides (NOx) Emissions .......................................................................118

8.6.1 Elimination of Technically Infeasible NOx Control Options..................................... 118

8.6.2 Ranking of Remaining NOx Control Technologies by Control Effectiveness........... 120

8.6.3 Evaluation of Most Effective NOx Control Technologies ......................................... 121

8.6.4 DRI Boiler NOx 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/PM10) Emissions...............................................131

8.10.1 Identification of Potential PM/PM10 Control Technologies....................................... 131

8.10.2 Elimination of Technically Infeasible PM/PM10 Control Options............................. 132

8.10.3 Ranking of Remaining PM/PM10 Control Technologies by Control Effectiveness ... 134

8.10.4 Evaluation of Most Effective Control Technologies ................................................. 134

8.10.5 DRI Process Heater PM/PM10 BACT Selection ........................................................ 135

8.11 DRI Process Heater Visible Emissions...................................................................................136

8.11.1 DRI Process Heater Visible Emissions BACT Selection .......................................... 136

8.12 DRI Process Heater Sulfur Dioxide (SO2) Emissions.............................................................136

8.12.1 Identification of Potential SO2 Control Technologies ............................................... 136

8.12.2 Elimination of Technically Infeasible SO2 Control Options...................................... 137

8.12.3 Ranking of Remaining SO2 Control Technologies by Control Effectiveness............ 138

8.12.4 Evaluation of Most Effective DRI Process Heater SO2 Control Technologies.......... 139

8.12.5 DRI Process Heater SO2 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
Minnesota Steel Page - v Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 PbControl 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 (H2S) Emissions ..............................................163

8.19.1 Identification of Potential H2S Control Technologies ............................................... 163

8.19.2 Elimination of Technically Infeasible H2SControl Options...................................... 163

8.19.3 Ranking of Remaining H2SControl Technologies by Control Effectiveness............ 164

8.19.4 Evaluation of Most Effective H2SControl Technologies .......................................... 165

8.19.5 DRI Top Gas Purification H2SBACT Selection........................................................ 165

8.20 Pneumatic Transport System (PTS) Gas Heaters ...................................................................166

8.21 PTS Gas Heater Particulate MatterPM/PM10 Emission ..........................................................166

8.21.1 Identification of Potential PM/PM10 Control Technologies....................................... 166

8.21.2 Elimination of Technically Infeasible PM/PM10 Control Options ............................. 167

8.21.3 Evaluation of Most Effective PM Control Technologies........................................... 169

8.21.4 PTS Gas Heater PM/PM10 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 (SO2) emissions ..........................................................................172

8.23.1 Identification of Potential SO2 Control Technologies ............................................... 172

8.23.2 Elimination of Technically Infeasible SO2 Control Options...................................... 172

8.23.3 Ranking of Remaining SO2 Control Technologies by Control Effectiveness............ 173

8.23.4 Evaluation of Most Effective SO2 Control Technologies .......................................... 174

8.23.5 PTS Gas Heater SO2 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
Minnesota Steel Page - vi Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Tower Blowdown Vent Control Technologies .. 189

8.27.4 Elimination of Technically Infeasible Cooling Tower Blowdown Vents Control 

Options ...................................................................................................................... 189

8.27.5 Ranking of Remaining Cooling Tower Blowdown Vents Control Technologies by 

Control Effectiveness ................................................................................................ 189

8.27.6 Evaluation of Most Effective Cooling Tower 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 Process 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 PM10) Emissions ................................................................197

9.3.1 Identification of Potential PM/PM10 Control Technologies....................................... 198

9.3.2 Elimination of Technically Infeasible PM/PM10 Control Options ............................. 198

9.3.3 Rank Remaining PM/PM10 Control Technologies by Control Effectiveness ............ 200

9.3.4 Evaluation of Most Effective PM/PM10 Control Technologies.................................. 200

9.3.5 EAF PM/PM10 BACT Selection................................................................................. 201

9.4 EAF Visible Emissions...........................................................................................................203

9.4.1 EAF Visible Emissions BACT Selection................................................................... 203

9.5 EAF Sulfur Dioxide (SO2) Emissions.....................................................................................204

9.5.1 Identification of Potential SO2 Control Technologies ............................................... 204

9.5.2 Elimination of Technically Infeasible SO2 Control Options...................................... 204

9.5.3 Ranking of Remaining SO2 Control Technologies by Control Effectiveness............ 206

9.5.4 Evaluation of Most Effective SO2 Control Technologies .......................................... 206

9.5.5 EAF SO2 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
Minnesota Steel Page - vii Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 ...................................................................................................235

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.......................................................................................................243

9.11.1 Identification of Potential Pb Control Technologies.................................................. 243

9.11.2 Elimination of Technically Infeasible PbControl Options ........................................ 244

9.11.3 Rank Remaining Pb Control Technologies by Control Effectiveness ....................... 245

9.11.4 Evaluation of Most Effective PbControl Technologies............................................. 246

9.11.5 EAF PbBACT 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/Tundish 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
Minnesota Steel Page - viii Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.15 Vacuum Degasser Boiler ........................................................................................................257

9.16 Vacuum Degasser Boiler Particulate MatterPM/PM10 Emission............................................257

9.16.1 Identification of Potential PM/PM10 Control Technologies....................................... 257

9.16.2 Elimination of Technically Infeasible PM/PM10 Control Options ............................. 258

9.16.3 Rank Remaining PM/PM10 Control Technologies by Control Effectiveness ............ 259

9.16.4 Evaluation of Most Effective PM Control Technologies........................................... 259

9.16.5 Vacuum Degasser Boiler PM/PM10 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 SO2 Control Technologies ............................................... 263

9.18.2 Elimination of Technically Infeasible SO2 Control Options...................................... 263

9.18.3 Ranking of Remaining SO2 Control Technologies by Control Effectiveness............ 264

9.18.4 Evaluation of Most Effective SO2 Control Technologies .......................................... 265

9.18.5 Vacuum Degasser Boiler SO2 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 NOx 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/PM10) Emissions .....................................................281

9.24.1 Identification of Potential PM Control Technologies ................................................ 281

9.24.2 Elimination of Technically Infeasible PM/PM10 Control Options............................. 281

9.24.3 Ranking of Remaining PM/PM10 Control Technologies by Control Effectiveness... 283

9.24.4 Evaluation of Most Effective PM/PM10 Control Technologies ................................. 283

9.24.5 Tunnel Furnace PM/PM10 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 (SO2) Emissions ...................................................................285

9.26.1 Identification of Potential SO2 Control Technologies ............................................... 285

9.26.2 Elimination of Technically Infeasible SO2 Control Options...................................... 285

9.26.3 Ranking of Remaining SO2 Control Technologies by Control Effectiveness............ 286

9.26.4 Evaluation of Most Effective SO2 Control Technologies .......................................... 287
Minnesota Steel Page - ix Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.26.5 Tunnel Furnace SO2 BACT Selection........................................................................ 287

9.27 Tunnel Furnace Nitrogen Oxides (NOx) 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 NOx 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 ......................................................................................................302

10.1.1 Process Description.................................................................................................... 302

10.1.2 Summary of Fugitive Emissions BACT .................................................................... 302

11.0 Material Handling – Transfers of Raw Materials Between Processes..............................................303

11.1 Raw Material Handling Process Description ..........................................................................303

11.2 Material Handling Particulate Matter (PM/PM10) Emissions .................................................303

11.2.1 Identification of Potential PM/PM10 Control Technologies....................................... 303

11.2.2 Elimination of Technically Infeasible PM/PM10 Control Options ............................. 304

11.2.3 Ranking of Remaining PM/PM10 Control Technologies by Control Effectiveness ... 305

11.2.4 Evaluation of Most Effective PM/PM10 Control Technologies.................................. 305

11.2.5 Material Handling PM/PM10 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
Minnesota Steel Page - x Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Particulate 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 Pumps PM BACT Selection.......................................... 334

14.3 Emergency Generators and Pumps Visible Emissions ...........................................................334

14.3.1 Emergency Generators and Pumps Visible Emissions BACT Selection................... 334

14.4 Emergency Generators and Pumps SO2 Emission Controls ...................................................335

14.4.1 Identification of Potential SO2 Control Technologies ............................................... 335

14.4.2 Elimination of Technically Infeasible SO2 Control Options...................................... 335

14.4.3 Ranking of Remaining SO2 Control Technologies by Control Effectiveness............ 336

14.4.4 Evaluation of Most Effective SO2 Control Technologies and Document Results ..... 336

14.4.5 Emergency Generators and Pumps SO2 BACT Selection.......................................... 337

14.5 Emergency Generators NOx Emission Controls .....................................................................337

14.5.1 Identification of Potential NOx Control Technologies............................................... 337

14.5.2 Elimination of Technically Infeasible NOx Control Options .................................... 338
Minnesota Steel Page - xi Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

14.5.3 Ranking of Remaining NOx Control Technologies by Control Effectiveness .......... 338

14.5.4 Evaluation of Most Effective NOx Control Technologies and Document Results.... 339

14.5.5 Emergency Generators NOx 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 Infeasible 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 ................................................................................................................... 341

14.6.5 Emergency Generators VOC and CO BACT Selection............................................. 341

15.0 Fugitive Dust ....................................................................................................................................343

15.1 Fugitive Dust Process Description..........................................................................................343

15.2 Fugitive Dust PM/PM10 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 Process Description ...........................................................................347

16.2 Insignificant Actives Addressed within the BACT Report.....................................................347

16.3 Insignificant Activities Requiring Review..............................................................................348
Minnesota Steel Page - xii Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Heater BACT Analysis Summary .................................................. 4

Table 1-6 DRI Cooling Water Blowdown Vents BACT Analysis 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 Analysis Summaries........................................................................................... 8

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

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

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

Table 3-2 NSPS Emission Limits for Metallic 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 Completeness Review............................................................................... 37

Table 7-1 Evaluation of Most Effective PM/PM10 Control Technologies for the Pellet Plant Indurating 

Furnace Waste Gas Stream ................................................................................................................. 53

Table 7-2 Ranking of Remaining PM/PM10 Control Technologies and Control Effectiveness for the 

Pellet Plant Indurating Furnace........................................................................................................... 54

Table 7-3 Evaluation of Most Effective PM/PM10 Control Technologies for the Pellet Plant Indurator 

Waste Gas Stream............................................................................................................................... 55

Table 7-4 Evaluation of Most Effective PM/PM10 Control Technologies for the Pellet Plant Indurator 

Hood Exhaust Stream ......................................................................................................................... 55

Table 7-5 Technical Feasibility of SO2 Control Technologies for Taconite Pellet Indurating Furnace.............. 60

Table 7-6 Ranking of Remaining SO2 Control Technologies and Control Effectiveness for the Pellet 

Plant Indurating Furnace..................................................................................................................... 61

Table 7-7 Evaluation of Most Effective SO2 Control Technologies for the Pellet Plant Indurating 

Furnace Waste Gas Stream ................................................................................................................. 62

Table 7-8 Evaluation of Most Effective SO2 Control Technologies for the Pellet Plant Indurating Hood 

Exhaust Stream ................................................................................................................................... 62

Table 7-9 Technical Feasibility of NOx Control Technologies for Taconite Pellet Indurating Furnace ............. 65
Minnesota Steel Page - xiii Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 7-10 Remaining NOx Control Technologies and Control Effectiveness for the Taconite Pellet 

Indurating Furnace.............................................................................................................................. 72

Table 7-11 Evaluation of Most Effective NOx Control Technologies for the Pellet Plant Indurating 

Furnace Waste Gas Stream ................................................................................................................. 72

Table 7-12 Evaluation of Most Effective NOx 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 Control Effectiveness for the Taconite Pellet 

Indurating Furnace.............................................................................................................................. 79

Table 7-15 Evaluation of Most Effective CO Control Technologies for the Taconite Pellet Indurating 

Furnace Waste Gas Stack ................................................................................................................... 79

Table 7-16 Evaluation of Most Effective CO Control Technologies for the Taconite Pellet Indurating 

Furnace Hood Exhaust........................................................................................................................ 80

Table 7-17 Technical Feasibility of VOCControl 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 Technologies for the Taconite Pellet Indurating 

Furnace Waste Gas Stack ................................................................................................................... 83

Table 7-20 Evaluation of Most Effective VOC Control Technologies for the Taconite Pellet Indurating 

Furnace Hood Exhaust........................................................................................................................ 84

Table 7-21 Technical Feasibility of FluorideControl 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 MistControl 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 Waste 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 Technologies and Control Effectiveness for the Pellet 

Plant Indurating Furnace..................................................................................................................... 97
Minnesota Steel Page - xiv Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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/PM10 Control Technologies for the DRI Boilers................................. 111

Table 8-2 Ranking of Remaining PM/PM10 Control Technologies for DRI Boilers ........................................ 112

Table 8-3 Evaluation of Most Effective PM/PM10 Control Technologies for the DRI Boilers ........................ 112

Table 8-4 Technical Feasibility of SO2 Control Technologies for the DRI Boilers.......................................... 116

Table 8-5 Ranking of Remaining SO2 Control Technologies for the DRI Boilers ........................................... 116

Table 8-6 Evaluation of Most Effective SO2 Control Technologies for the DRI Boilers ................................. 117

Table 8-7 Technical Feasibility of NOx Control Technologies for the DRI Boilers......................................... 119

Table 8-8 Ranking of Remaining NOx Control Technologies for the Tunnel Furnace..................................... 121

Table 8-9 Evaluation of Most Effective NOx 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/PM10 Control Technologies and Control Effectiveness for the DRI Process 

Heaters .............................................................................................................................................. 134

Table 8-18 Evaluation of Most Effective PM/PM10 Control Technologies for the DRI Process Heaters .......... 134

Table 8-19 Technical Feasibility of SO2 Control Technologies for DRI Process Heaters.................................. 138

Table 8-20 Remaining SO2 Control Technologies and Control Effectiveness for the DRI Process 

Heaters .............................................................................................................................................. 138

Table 8-21 Evaluation of Most Effective SO2 Control Technologies for the DRI Process Heaters ................... 139

Table 8-22 Technical Feasibility of NOx Control Technologies for the DRI Process Heaters ........................... 141

Table 8-23 Ranking of Remaining NOx 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
Minnesota Steel Page - xv Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Control Technologies for DRI Process Heaters.................. 158

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

Table 8-35 Remaining Pb Control Technologies and Control 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 H2S Control Technologies for DRI Top Gas Purification.......................... 164

Table 8-38 Remaining H2SControl Technologies and Control Effectiveness for the DRI Top Gas 

Purification ....................................................................................................................................... 165

Table 8-39 Evaluation of Most Effective H2S Control Technologies for the DRI Top Gas Purification ........... 165

Table 8-40 Technical Feasibility of PM/PM10 Control Technologies for the PTS Gas Heaters......................... 167

Table 8-41 Ranking of Remaining PM/PM10 Control Technologies for PTS Gas Heaters ................................ 169

Table 8-42 Evaluation of Most Effective PM/PM10 Control Technologies for the PTS Gas Heaters ................ 169

Table 8-43 Technical Feasibility of SO2 Control Technologies for the PTS Gas Heaters.................................. 173

Table 8-44 Ranking of Remaining SO2 Control Technologies for the PTS Gas Heaters ................................... 173

Table 8-45 Evaluation of Most Effective SO2 Control Technologies for the PTS Gas Heaters ......................... 174

Table 8-46 Technical Feasibility of NOx Control Technologies for the PTS Heater.......................................... 176

Table 8-47 Ranking of Remaining NOx Control Technologies for the PTS Gas Heaters................................... 178

Table 8-48 Evaluation of Most Effective NOx 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/PM10 Control Technologies for the Melt Shop ................................... 198

Table 9-2 Ranking of Remaining PM/PM10 Control Technologies for Melt Shop........................................... 200

Table 9-3 Technical Feasibility of SO2 Control Technologies for the Melt Shop ............................................ 205

Table 9-4 Ranking of Remaining SO2 Control Technologies for Melt Shop.................................................... 206
Minnesota Steel Page - xvi Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-5 Evaluation of Most Effective SO2 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 NOx 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 FluorideControl 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/PM10 Control Technologies for the Vacuum Degasser Boiler ............ 258

Table 9-29 Ranking of Remaining PM/PM10 Control Technologies for Vacuum Degasser Boiler ................... 259

Table 9-30 Evaluation of Most Effective PM/PM10 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 SO2 Control Technologies for the Vacuum Degasser Boiler ...................... 264

Table 9-33 Evaluation of Most Effective SO2 Control Technologies for the Vacuum Degasser Boiler ............ 265

Table 9-34 Technical Feasibility of NOx Control Technologies for the Vacuum Degasser Boiler .................... 267

Table 9-35 Ranking of Remaining NOx Control Technologies for the Vacuum Degasser Boiler...................... 269

Table 9-36 Evaluation of Most Effective NOx Control Technologies for the Vacuum Degasser Boiler ............ 269

Table 9-37 Technical Feasibility of CO Control Technologies for the Vacuum Degasser Boiler...................... 273
Minnesota Steel Page - xvii Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

Table 9-39 Evaluation of Most Effective CO Control Technologies 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 Technologies for the Vacuum Degasser Boiler .......... 278

Table 9-43 Technical Feasibility of PM/PM10 Control Technologies for the Tunnel Furnace........................... 282

Table 9-44 Ranking of Remaining PM/PM10 Control Technologies for the Tunnel Furnace............................. 283

Table 9-45 Evaluation of Most Effective PM/PM10 Control Technologies for the Tunnel Furnace .................. 283

Table 9-46 Technical Feasibility of SO2 Control Technologies for the Tunnel Furnace.................................... 286

Table 9-47 Ranking of Remaining SO2 Control Technologies for the Tunnel Furnace ..................................... 286

Table 9-48 Evaluation of Most Effective SO2 Control Technologies for the Tunnel Furnace ........................... 287

Table 9-49 Technical Feasibility of NOx Control Technologies for the Tunnel Furnace ................................... 288

Table 9-50 Ranking of Remaining NOx Control Technologies for the Tunnel Furnace..................................... 292

Table 9-51 Evaluation of Most Effective NOx 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/PM10 Control Technologies for Material Handling............................. 304

Table 11-2 Ranking of Remaining PM/PM10 Control Technologies for Material Handling............................... 305

Table 11-3 Evaluation of Most Effective PM/PM10 Control Technologies for Pelletizer—Hearth Layer 

Bin Material Handling ...................................................................................................................... 306

Table 11-4 Evaluation of Most Effective PM/PM10 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 Technologies 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 Technologies 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
Minnesota Steel Page - xviii Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 12-1 Technical Feasibility of PM/PM10 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 Technologies 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 Technologies for Additive Material Handling................. 325

Table 14-1 Technical Feasibility of PM Control Technologies 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 / PM10 Control Technologies for Emergency Generators 

and Pumps......................................................................................................................................... 334

Table 14-4 Technical Feasibility of SO2 Control Technologies for Emergency Diesel Generators and 

Pumps ............................................................................................................................................... 336

Table 14-5 Ranking of Remaining SO2 Control Technologies for Emergency Generators and Pumps ............. 336

Table 14-6 Evaluation of Most Effective SO2 Control Technologies 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 Technologies for Emergency Generators and Pumps............ 339

Table 14-9 Evaluation of Most Effective NOx Control Technologies 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 Technologies for Emergency Generators and 

Pumps ............................................................................................................................................... 341

Table 14-12 Evaluation of Most Effective VOC and CO Control Technologies for Emergency Generators 

and Pumps......................................................................................................................................... 341
Minnesota Steel Page - xix Table of Contents 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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, Material Handling – BACT Cost Tables 

Attachment K Diesel Powered Stationary Engines 

Attachment L RACT/BACT/LAER Clearinghouse Summary 

Attachment M BACT Limits for Startups and Shutdowns 

Attachment N BACT Mass Emission Limits for Material Handling Sources 

Attachment O Fugitive Dust Control Plan 
Minnesota Steel 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

This Page Intentionally Left Blank
Minnesota Steel Page - 1 Executive Summary 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 SO2, NOx, PM and PM10

• Good Combustion Practices for CO, VOC, PM and PM10

• Enclosures with Fabric Filter for PM, PM10

• Enclosures with PM Wet Scrubbers for PM, PM10

• Low NOx, ultra low NOx and oxy fuel burners for NOx

• Wet Scrubbers for PM, PM10

• Absorber/Wet Scrubber for SO2, fluorides (F) and sulfuric acid mist (SAM) 

• Pb, F and SAM control performance monitored via SO2 and particulate emission limits 

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

In addition, Minnesota Steel proposes to test and install, 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 the 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 PM10 Wet Scrubber 

 

0.012 gr/dscf* 47 lb/hr PM10 

24-hour Average 

Hood Exhaust Opacity Wet Scrubber <10% NA 

Hood Exhaust SO2 No Controls 7.8 ppm 

3-hour average 

36 lb/hr SO2

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 NOx No Controls 45 ppm 

24-hour average 

165 lb/hr NOx

24-hour Average 
Minnesota Steel Page - 2 Executive Summary 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 PM10 Wet Scrubber 

 

0.012 gr/dscf* 33 lb/hr PM10 

24-hour Average 

Waste Gas Opacity Wet Scrubber <10% NA 

Waste Gas SO2 Wet Scrubber 

 

3.3 ppm 

3-hour average 

10 lb/hr SO2

3-hour Average 

Waste Gas SAM Wet Scrubber 0.018ppm 

3-hour average 

0.085 lb/hr SAM 

3-hour average 

Waste Gas 

 

NOx Clean fuels 

Good 

Combustion 

Practices 

205 ppm 464 lb/hr NOx

24-hour Average 

Waste Gas 

(estimated limits if 

on-site testing 

demonstrates 

LoTOx is feasible) 

NOx LoTOx 25 ppm 

24-hour average 

46 lb/hr NOx

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). PM10 EPA Method 201or 201A (Filterable) and 202 or EPA approved 

modified Method 202 procedures (Condensable) 
Minnesota Steel Page - 3 Executive Summary 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 1-2 DRI Boiler BACT Analysis Summary 

Source Pollutant 

Emission 

Control 

Equipment 

Performance 

Standard 

Mass Emission 

Limit 

DRI Boiler PM / PM10

Good Combustion 

Practices 

 Clean Fuels 

0.0075 lb/MMBtu of 

PM / PM10

0.7 lb/hr PM/PM10 

24-hour Average 

DRI Boiler Opacity 

Good Combustion 

Practices 

Clean Fuels 

3% Opacity NA 

DRI Boiler SO2

Good Combustion 

Practices 

 Clean Fuels 

Good Combustion 

Practices 

 Clean Fuels 

0.1 lb/hr SO2

3-hour Average 

DRI Boiler NOx

Ultra Low NOx

Burners/Low NOx

Burners with Flue 

Gas Recirculation 

0.035 lb/MMBtu 3.5 lb/hr NOx

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 / PM10 Top Gas Scrubber 

System; no add-on 

controls. 

0.015 lb/MMBtu of 

PM / PM10

(0.01 gr/dscf) 

8.8 lb/hr PM/PM10 

24-hour Average 

DRI Process Heater 

 Opacity 

Good Combustion 

Practices 

Clean Fuels 

3% Opacity NA 

DRI Process Heater SO2, Clean Fuels 

Top Gas or Natural 

Gas 

Clean Fuels 1 lb/hr SO2

3-hour Average 

DRI Process Heater NOx Ultra Low NOx

Burners 

0.04 lb/MMBtu 24 lb/hr NOx

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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 1-4 Top Gas Purification System BACT Analysis Summary 

Source Pollutant 

Emission 

Control 

Equipment 

Performance 

Standard 

Mass Emission 

Limit 

Top Gas 

Purification H2S No Controls 

11.1 lb/hr DMDS 

injection 

3-hour average 

68 ppm 

3-hour Average 

8.2 lb/hr H2S 

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 / PM10

Good Combustion 

Practices 

 Clean Fuels 

0.0075 lb/MMBtu of 

PM / PM10

0.09 lb/hr PM/PM10 

24-hour Average 

PTS Gas Heater Opacity 

Good Combustion 

Practices 

Clean Fuels 

3% Opacity NA 

PTS Gas Heater SO2

Good Combustion 

Practices 

 Clean Fuels 

Good Combustion 

Practices 

 Clean Fuels 

0.024 lb/hr SO2

3-hour Average 

PTS Gas Heater NOx

Ultra Low NOx

Burners/Low NOx

Burners with Flue 

Gas Recirculation 

0.035 lb/MMBtu 0.4 lb/hr NOx

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 Water 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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 PM10 Direct –Shell 

Evacuation Control 

System Baghouse 

0.0030 gr/dscf* 

Total PM10

16 lb/hr PM10 

24-hour Average 

Melt Shop 

 Opacity 

Good Operating 

Practices 

 Clean Fuels 

3% Opacity NA 

Melt Shop SO2 Clean Fuels 

Low Sulfur Carbon 

0.15 Lb SO2/ton 

liquid steel 

produced 

33 lb/hr SO2

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 NOx Oxyfuel Burners 

and Direct –Shell 

Evacuation Control 

System no add-on 

controls 

0.26 Lb NOx/ton 

liquid steel 

produced 

30-day rolling 

average 

53 lb/hr NOx

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 

NOx Low NOx 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). PM10 EPA Method 201or 201A and 202 or EPA approved modified 

Method 202 procedures (Filterable + Condensable) 
Minnesota Steel Page - 6 Executive Summary 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 / PM10

Good Combustion 

Practices 

 Clean Fuels 

0.0075 lb/MMBtu of 

PM / PM10

0.7lb/hr PM/PM10 

24-hour Average 

Vacuum Degasser 

Boiler Opacity 

Good Combustion 

Practices 

Clean Fuels 

3% Opacity NA 

Vacuum Degasser 

Boiler SO2

Good Combustion 

Practices 

 Clean Fuels 

Good Combustion 

Practices 

 Clean Fuels 

0.1 lb/hr SO2

3-hour Average 

Vacuum Degasser 

Boiler NOx

Low NOx Burners 

with Flue Gas 

Recirculation 

0.035 lb/MMBtu 3.5 lb/hr NOx

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 / PM10 Good Combustion 

Practices 

Clean Fuels 

Good Combustion 

Practices 

Clean Fuels 

1 lb/hr PM/PM10 

24-hour Average 

Tunnel Furnace Opacity 

Good Combustion 

Practices 

Clean Fuels 

3% Opacity NA 

Tunnel Furnace SO2 Good Combustion 

Practices 

 Clean Fuels 

Good Combustion 

Practices 

 Clean Fuels 

0.1 lb/hr SO2

3-hour Average 

Tunnel Furnace NOx Low NOx Burners 0.1 lb NOx/MMBtu 5.0 lb/hr NOx 

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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 1-10 Material Handling BACT Analysis Summaries 

Source Pollutant 

Emission 

Control 

Equipment 

Performance 

Standard 

Mass Emission 

Limit 

Mining & Crushing 

PM / PM10 

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 / PM10 

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 / PM10 

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 / PM10 

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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 / PM10 

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 / PM10 

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 / PM10 

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 / PM10 

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 / PM10 

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 / PM10 

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 
Minnesota Steel Page - 9 Executive Summary 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Source Pollutant 

Emission 

Control 

Equipment 

Performance 

Standard 

Mass Emission 

Limit 

Slag Processing PM / PM10 

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 / PM10 Drift Eliminator 0.005% drift rate NA 

DRI Opacity Drift Eliminator <20% NA 

Melt Shop PM / PM10 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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 / PM10

Emergency 

Generator 

Classification 

combined with GCP 

Emergency 

Generator 

Classification 

combined with 

Good Combustion 

Practices 

NA 

Emergency Diesels SO2

Emergency 

Generator 

Classification 

combined with Low 

Sulfur Fuel 

Emergency 

Generator 

Classification 

combined with Low 

Sulfur Fuel 

NA 

Emergency Diesels NOx

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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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, Minnesota. 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 adversely impacting the environment. A key element in 

pursuing this goal is the commitment by Minnesota Steel to use only natural gas for all process heat 

needs. 

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

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

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

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

Minnesota Steel emissions unit. Sources consulted 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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

3.0 Methodology 

3.1 PSD Applicability 

The requirement to conduct a BACT analysis and determination 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 stationary 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 the potential to emit in significant amounts. 

40 CFR 52.21(b) 23 defines1 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 

• Fluorides2: 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 (measured 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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 conducted in accordance with the requirements specified in 

EPA’s draft New Source Review Workshop Manual, (October 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 approach to the BACT process are as follows: 

Step 1 – Identify all Control Technologies 

The first step in a top down analysis is to identify 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 factors. Technologies which are determined to be 

infeasible are eliminated from further consideration. 
Minnesota Steel Page - 14 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 option, 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 vendors did not respond to bid requests, cost data 

from other recent projects were used with adjustments 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 cost 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 pollutant 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 application of production processes or available methods, 

systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for 

control of such pollutant. In no event shall application of best available control technology result in emissions of 

any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 

61. If the Administrator determines that technological or economic limitations on the application of measurement 

methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a 

design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to 

satisfy the requirement for the application of best available control technology. Such standard shall, to the degree 
Minnesota Steel Page - 15 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

possible, set forth the emissions reduction achievable by implementation of such design, equipment, work 

practice or operation, and shall provide for compliance by means which achieve equivalent results.”

3.3 Emission Limits 

While the BACT review process is used to evaluate potential control technologies and work 

practices, a PSD permit must express the BACT determination as a permit limitation, which is 

federally enforceable. Suggested emission limits within this BACT review will be expressed as a 

standard of performance and a mass 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 enforceable. Proposed 

mass emission limits for SO2 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 SO2.impact of the Minnesota Steel facility was only 14 μg/m3

. Since this 

impact is well below the state 1-hour SO2 standard of 1,300 μg/m3

, no 1-hour average limits are 

needed to protect state air quality standards. If a mass emission 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 (RBLC) for taconite mining and 

pellet production, Direct Reduced Iron (DRI) production, 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 descriptions, 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 simplify 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 distinguish BACT-PSD data from other case-by-case 

data. The non-BACT limits do not include economic feasibility as criteria for determining emission 
Minnesota Steel Page - 16 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 ascending 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 control performance based limits (e.g. lb/MMBtu) may appear in 

any of these limit categories. Therefore, the limit 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 contains the most relevant data. Please note that 

the other limit columns may contain relevant information 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 top 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 included 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 footnote 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 facilities 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. 
Minnesota Steel Page - 17 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

Plant Section PSD Pollutants Emitted 

1 Mining and Crushing PM , PM10 and Fluorides 

2 Pellet Plant PM, PM10, SO2, NOx, CO, VOC, 

Fluorides, Sulfuric Acid Mist and Pb 

3 DRI Plant PM, PM10, SO2, NOx, CO, VOC, H2S, 

Fluorides, Sulfuric Acid Mist and Pb 

4 Steel Mill PM, PM10, SO2, NOx, CO, VOC, 

Fluorides, Sulfuric Acid Mist and Pb 

5 Slag Handling PM, PM10

6 Cooling Towers PM and PM10 , Fluorides and Pb 

7 Emergency Generators and Pumps PM, PM10, SO2, NOx, CO and VOC 

8 Fugitive Emissions PM , PM10 ,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 shutdown. 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 unexpected nature of malfunctions; a BACT limit 

cannot be proposed for malfunctions. However, Minnesota Steel will follow best 

practices for minimizing emissions during malfunctions. These will include continued 

operation of emissions control equipment when feasible, repairing equipment in an 

expedient manner and/or shutting down the process if the malfunction is expected to 
Minnesota Steel Page - 18 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

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

3.5 Identification of Applicable 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 (NESHAPS) cannot be less stringent than the 

applicable standards. Maximum Achievable Control Technology (MACT) standards under 40 CFR 

Part 63 for the control of Hazardous Air Pollutants are not applicable 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 minimum emission control requirements 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 those cases, MACT standards may be 

used as an indicator of the level of emissions control 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 Performance 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 Vessels Constructed After August 17, 1983 

• 40 CFR Part 60 Subpart IIII, Standards of Performance 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 Emission Standards for Hazardous Air Pollutants: 

Industrial, Commercial, and Institutional Boilers and Process Heaters 

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

limits. 
Minnesota Steel Page - 19 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

Subpart Dc regulates steam generating 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 section, 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 million 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 recordkeeping. There are no emission limits applicable to gasfired units under Subpart Dc. 

3.5.2 Subpart LL, Standards of Performance for Metallic Mineral Processing 

Subpart LL regulates point source emissions of particulate matter from material handling sources and 

thermal dryers at Metallic Mineral Processing facilities. 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 commences with the mining of ore and includes all operations 

either up to and including the loading of wet or dry concentrates or solutions of metallic minerals for transfer to 

facilities at non-adjacent locations that will subsequently process metallic concentrates into purified metals (or other 

products), or up to and including all material transfer and storage operations that precede the operations that produce 

refined metals (or other products) from metallic mineral concentrates at facilities adjacent to the metallic mineral 

processing plant. This definition shall not be construed as requiring that mining of ore be conducted in order for the 

combination of equipment to be considered a metallic mineral processing plant. (See also the definition of metallic 

mineral concentrate.)” 

Based on this definition Subpart LL applies to the process from mining and crushing up to the point 

where the taconite pellets enter the DRI unit. Subpart LL applies to material transfer and storage 

operations that precede the operation that produce refined 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 the 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, enclosed storage area, truck loading station, truck 

unloading station, railcar loading station, 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 including the beneficiation of uranium ore are exempted from 

the provisions of this subpart.” 
Minnesota Steel Page - 20 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 shall 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 opacity, unless the stack emissions are discharged 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 maximum production rate at which the affected facility will be 

operated, but not later than 180 days after initial startup, no owner or operator subject to the provisions of this subpart 

shall cause to be discharged into the atmosphere from an affected facility any process fugitive emissions that exhibit 

greater than 10 percent opacity.” 

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

maximum allowable emissions for a BACT determination 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% opacity1 40 CFR 60.382(a)(2) 

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

3.5.3 Subpart AAa, Standards of Performance for Steel Plants: Electric Arc 

Furnaces and Argon-Oxygen Decarburization 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 following affected facilities in steel 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 containing 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 subpart. For the purposes of this subpart, the dust-handling system 

shall consist of the control device dust hoppers, the dust-conveying equipment, any central dust storage equipment, 
Minnesota Steel Page - 21 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

the dust-treating equipment (e.g., pug mill, pelletizer), dust 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 produces molten steel and heats the charge materials with electric 

arcs from carbon electrodes. For the purposes of this subpart, an EAF shall consist of the furnace shell and roof and 

the transformer. Furnaces that continuously 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 definition 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 limits. The EAF is designed to processes DRI pellets in 

a continuous manner; therefore it is exempt 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 Performance for Stationary 

Compression Ignition Internal Combustion Engines 

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

emissions of PM, NOx, CO and VOCs from diesel engines based on size, service and date of manufacture. 

SO2 emissions will be limited by fuel specifications. Minnesota Steel Industries stationary diesels will be 

used for emergency purposes only. The new rule limits 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 larger 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 without 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. 
Minnesota Steel Page - 22 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

3.5.5 Subpart RRRRR, National Emission 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 are 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 crushing 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 handling 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, indurating furnace, or finished pellet handling operation at your 

taconite iron ore processing plant is existing if you commenced construction or reconstruction of the affected source 

before December 18, 2002. 

(e) An ore crushing and handling operation, ore dryer, indurating furnace, or finished pellet handling operation at your 

taconite iron ore processing plant is new if you commence construction or reconstruction of the affected source on or 

after December 18, 2002. An affected source is reconstructed if it meets the definition of reconstruction in §63.2.” 

Table 3-4 summarizes the emission limits from Table 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 Emission Standards for Hazardous Air 

Pollutants: Industrial, Commercial, 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. 
Minnesota Steel Page - 23 Methodology 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 mercury. Subpart DDDDD applies to 

boilers and process heaters at major HAP sources and 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 boilers and process heaters is 400 ppm of CO on a 

dry basis corrected to 3 percent oxygen (30-day rolling 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 gas fired boilers and process heaters because emissions of these constituents 

are not significant.
Minnesota Steel Page - 24 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 controls 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 emission 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 combinations will be address in the individual BACT 

analysis 

Descriptions of emission control practices for fugitive emissions are discussed in Section 15, which 

covers fugitive emission control for the entire facility. 

4.2 Particulate Matter (PM & PM10), Fluoride (F-), Particulate, and 

Lead (Pb) Emission Control Technologies 

Fluoride and lead emissions will be controlled with particulate matter emission 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 particulate 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 processing. When stacks are tested using EPA test 

procedures like EPA Method 5, these particulates are collected on a filter; hence, they are called 

“filterable particulates”. 

The control efficiency of a particulate matter 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 particles are present in the exhaust gas being treated. Therefore, the 
Minnesota Steel Page - 25 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

control efficiency of a particulate control method will vary when applied to different source types 

(e.g. ore grinding which contains larger particles vs. an EAF which contains relatively small 

particles) because each source type will have a different size distribution of particulates emitted. 

Exhaust streams containing combustion products, vapors from iron ore conversion processes and 

steel making may also contain “condensable particulate” matter. Condensable particulates are in a 

vapor state when emitted, and change to a liquid or solid state when cooled. Condensable 

particulates are measured using EPA Method 202 or EPA approved modified Method 202 

procedures3

. 

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 capturing condensable particulates than one which does 

not reduce the temperature of the exhaust gas. Particulate 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 control efficiency of any particulate control method for a given 

source type, is dependent upon the size distribution of the filterable particulate 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 particulates vs. the amount and size of each type of particulate matter present in the 

exhaust steam. The relative control efficiencies of particulate control devices for filterable and 

condensable particulates can be summarized as follows: 

 

3

 EPA is currently evaluating modified procedures for Method 202 to improve the accuracy of the test method. 
Minnesota Steel Page - 26 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 type of particulate control equipment are discussed in the following 

sections. Included is a description of each type of pollution control equipment, operating limitations, 

and there effectiveness at controlling filterable and condensable 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 surface 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 the reverse-air fabric filter and the pulse-jet fabric filter. In a 

reverse-air fabric filter, the flue gas flows upward 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. 
Minnesota Steel Page - 27 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

The main operating limitation of a baghouse is that its operating temperature is limited by the bag 

material. Most filter materials are limited to 200oF – 300o F. Some materials like glass fiber or 

nomex may be operated at 400oF, but are more expensive. 

Baghouse control efficiency under normal loading conditions typically is in the 98% - 99%+ range. 

Reduced efficiencies will occur when the inlet particle concentration is low. 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 particle concentrations typically are in the 0.005 gr/dscf range. In some cases 

lower concentrations can be achieved, but the outlet concentrations achieved will depend on the size 

range and nature of the particles being filtered, and the type of filter media which can be used in that 

application. Therefore, baghouses are most effective controlling sources with filterable particulates 

and less effective controlling hot exhaust streams with condensable 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 field is maintained between high-voltage discharge 

electrodes, typically wires or rigid frames, and grounded collecting electrodes, typically plates. A 

corona discharge from the discharge electrodes ionizes 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 particulate matter, which falls into hoppers for removal. Collector dust is removed 

from the precipitator for disposal, recycling or reprocessing. 

Since ESP’s use electrical forces for particle collection, the electrical properties of the particles can 

adversely impact ESP operation. Particles with high resistivity may not readily accept an electric 

charge and will be difficult to collect. Particles with high conductivity or magnetic properties, such 

as iron, will strongly adhere to the collection plates and be difficult to remove. 

ESP control efficiency under normal loading conditions 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 treated; so, condensable particulate 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 
Minnesota Steel Page - 28 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

with filterable particulates and less effective controlling hot exhaust streams 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 mechanical cleaning methods. In a WESP, an intense 

electrostatic field is maintained between high-voltage discharge electrodes, typically wires or rigid 

frames, and grounded collecting electrodes, typically plates. A corona discharge from the discharge 

electrodes ionizes 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. 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 may not readily accept an electric 

charge and will be difficult to collect. Particles with high conductivity or magnetic properties, such 

as iron, will strongly adhere to the collection plates and be difficult to remove; WESP water sprays 

may reduce this problem. However, WESP water spray 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 evaporative cooling by the ESP spray water. Since wet 

ESP’s use water, they may also capture particulate matter composed of water soluble salts. 

Therefore, wet ESP’s are more likely to control condensable particulates 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 concentrations achieved will depend 

on the size range and nature of the particles being filtered. 

4.2.4 Wet Scrubbers 

Wet scrubbers, also termed particulate 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. 
Minnesota Steel Page - 29 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Scrubbers may capture particulates through the following mechanisms: 

• Impaction of the particle directly into a target droplet. 

• Interception of the particle by a target droplet 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 scrubbers, 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 cause 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 capture particulate matter composed of water soluble 

salts. Therefore, wet scrubbers are more likely to control condensable 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/dscf; 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 remove the larger particles from the smaller ones. 

• Cyclones use centrifugal force to separate 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 forces 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 
Minnesota Steel Page - 30 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

box. Inertial separators can only remove the larger dust particles (>75 microns). They are typically 

used upstream of other control devices in high inlet dust loading cases. 

Cyclone separators are designed to remove particles 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 the vortex and consequently slide 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 middle 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 efficiencies being achieved 

with large particles and low efficiencies for smaller particles (< PM10). 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 improves 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 equipment designs which are either inherently lower 

polluting or are designed to minimize emissions. 

Good operating practices include operating methods, procedures and selection 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 materials 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 
Minnesota Steel Page - 31 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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/PM10 BACT control. 

4.4 Sulfur Dioxide (SO2), Sulfuric Acid Mist and Gaseous Fluoride 

Emission Control Technologies 

Sulfur dioxide, sulfuric acid mist, and fluoride emissions are concurrently generated from certain 

sources in the Minnesota Steel project. Sulfuric acid mist is formed from sulfur trioxide (SO3) 

reacting with water in exhaust streams. SO3 (and SO2) 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 controlled hand-in-hand with 

similar, most often the same piece of pollution control equipment. Therefore, the descriptions of 

technologies for controlling these pollutants are discussed together in this section. 

4.4.1 Flue Gas Desulfurization (FGD) 

There are many available FGD systems including wet scrubbing, spray dryer absorption and dry 

sorbent injection. The FGD systems currently in use to control SO2 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 (SO2, SAM, and F) are absorbed by the droplets. The 

absorption of the SO2 and SAM leads to the formation of calcium sulfite (CaSO3●2H2O) and calcium 

sulfate (CaSO4) within the droplets. The adsorption of fluorides leads to the formation of CaF2. 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 leads to the formation of a dry powder which is carried 
Minnesota Steel Page - 32 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 kiln exhaust gas stream with a slurry comprised 

of lime (CaO) or limestone (CaCO3) 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 particulates in the scrubber. The SO2 and SAM in the gas stream 

reacts with the lime or limestone slurry to form calcium sulfite (CaSO3●2H2O) and calcium sulfate 

(CaSO4). The F- in the gas stream reacts to form CaF2. 

4.4.5 Good Design Methods and Operating Practices 

Good design includes process and mechanical equipment designs which are either inherently lower 

polluting or are designed to minimize emissions. 

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

minimize emissions. 

Since these methods are generally source specific (e.g. good operating practices for SO2 control), 

they will be addressed for each process when such measures are available. 

4.5 Nitrogen Oxides (NOx) Emission Control Technologies 

4.5.1 Sources of NOx Emissions 

There are three mechanisms by which NOx production occurs and they are thermal, fuel and prompt 

NOx formation. 

In the case of natural gas combustion, the primary mechanism of NOx production is through thermal 

NOx formation. This mechanism arises from the thermal dissociation of nitrogen and oxygen 

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

N2 + O2 → 2NO (1) 

Downstream of the flame, significant amounts of NO2 can be formed when NO is mixed with air. 

The reaction is as follows: 

2NO + O2 → 2NO2 (2) 

Thermal oxidation is a function of the residence time, free oxygen, and peak reaction temperature. 
Minnesota Steel Page - 33 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the result of 

reactions between nitrogen and carbon radicals generated during combustion. Only minor amounts 

of NOx are emitted as prompt NOx. 

Fuel bound NOx 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 NOx as a major concern. 

4.5.2 Identification of NOx Control Technologies 

Combustion Controls 

Various combustion controls exist for NOx reduction from combustion units. A few feasible 

examples of these controls include Low Excess Air (LEA), Low NOx 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 NOx 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 NOx Burners (LNB) 

LNB technology utilizes advanced burner design to reduce NOx 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, NOx formation is limited by 

either one of two conditions. Under a rich (high fuel) condition, oxygen levels and flame 

temperatures are low resulting in less NOx formation. The primary zone is then followed by a 

secondary zone in which the incomplete combustion products formed in the primary zone act as 

reducing agents. Alternatively, under lean (low fuel) conditions, excess air will reduce flame 

temperature to reduce NOx formation. In the secondary zone, combustion products formed in the 

primary zone act to lower the local oxygen concentration, resulting in a decrease in NOx formation. 

Due to the reduced flame temperatures, low NOx and ultra low NOx burners have higher CO emission 

rates than uncontrolled burners. Low NOx burners typically achieve NOx emission reductions of 

25% - 50%. 
Minnesota Steel Page - 34 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Second generation low NOx burners are called Ultra Low NOx 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 applications like the electric arc furnaces. Oxy-fuel 

burners combust natural gas using pure oxygen. Under normal 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 NOx emissions because nitrogen is not 

present in the combustion zone. However, some atmospheric nitrogen is present in EAFs, which 

lowers the NOx 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 NOx

emissions by approximately 10% on a lb of NOx per ton of steel produced basis. 

Non-Selective Catalytic Reduction (NSCR) 

A non-selective catalytic reduction (NSCR) system 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 hydrocarbons (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 this condition, in the presence of a catalyst, NOx is 

reduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions 

for NOx removal are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 
Minnesota Steel Page - 35 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Selective Catalytic Reduction (SCR) 

Selective catalytic reduction is a post combustion NOx control technology in which ammonia (NH3) 

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

70% - 90%. NOx is removed through the following chemical reaction: 

4NO + 4NH3 + O2 → 4N2 + 6H20 (1) 

2NO2 + 4NH3 + O2 → 3N2 + 6H20 (2) 

The catalyst bed lowers the activation energy required for NOx decomposition. The catalyst contains 

metals in the platinum family and these are used for their ability to lower the activation energy 

required for NOx 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, N2, and water. SNCR control efficiency is typically 50% - 75%. 

Without the participation of a catalyst, the reaction requires a high temperature range to obtain 

activation energy. The relevant reactions are as follows: 

NO + NH3 + 1⁄4O2 → N2 + 3/2H2O (1) 

NH3 + 1⁄4O2 → NO + 3/2H2O (2) 

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

reaction (2) will dominate. 

NOxOUT®

NOxOUT® is a commercially available urea based SNCR process for the reduction of NOx from 

stationary sources. The process requires injection of stabilized urea liquid into the combustion flue 

gas in a location where the temperature 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 NOx. 

NOx 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 
Minnesota Steel Page - 36 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 calcium nitrate. The nitrates in the scrubbing system 

are discharged to an appropriate water treatment system. Commercially available LTO systems 

include Tri-NOx® and LoTOx. 

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Tri-NOx® 

This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a 

primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The 

reactions are as follows: 

O3 + NO → O2 + NO2 (1) 

2NaOH + 2NO2 + 1⁄2 O2 → 2NaNO3 + H2O (2) 

Tri-NOx® is a commercially available multi-staged wet scrubbing process in industrial use. Several 

process columns, each assigned a separate processing stage, are involved. In the first stage, the 

incoming material is quenched to reduce its temperature. The second, oxidizing stage, converts NO 

to NO2. Subsequent stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble 

salt. A major advantage of the Tri-NOx® process is that concurrent scrubbing of SO2 can be 

achieved. Tri-NOx is typically applied at small to medium sized sources with high NOx

concentration in the exhaust gas (1,000 ppm NOx). Under only these high NOx concentration 

conditions control efficiencies of 99% can be achieved. Exhaust gas concentrations of NOx from this 

type of source using Tri-NOx® are in the 25 ppm to 50ppm NOx 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 LTO system. LoTOx is an innovative NOx control 

technology which, to date, has not been applied to a taconite induration furnace or a source with 
Minnesota Steel Page - 37 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

similar size and exhaust gas characteristics. LoTOx technology uses ozone to oxidize NO to NO2

and NO2 to N2O5 prior to removal in a wet scrubber (absorber). The N2O5 is converted to HNO3 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 

NOx control. Ozone is generated from pure oxygen. In order for LoTOx to be economically feasible, 

a source of low cost oxygen must be available from a pipeline or on site generation. Since oxygen is 

needed for the steel making process, Minnesota Steel will have on site oxygen production facilities. 

The normal NOx control efficiency range for Lo-TOx is 80% to 95% with outlet NOx concentrations 

in the 15ppm – 25 ppm range. 

Good Design Methods and Operating Practices 

Good design includes process and mechanical equipment designs which are either inherently lower 

polluting or are designed to minimize emissions. 

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

minimize emissions. 

Since these methods are generally source specific (e.g. good operating practices for NOx control), 

they will be addressed for each process when such measures are available. 

Other NOx Controls Potentially Applicable to the Minnesota Steel Project 

The NOx emission controls listed above represent available technologies which are reasonably 

available and are typically considered in a BACT review. Other potential, though less developed, 

technologies exist and were also evaluated. Most of these controls were not considered because they 

were not commercially available, or are variations 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. 
Minnesota Steel Page - 38 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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: 

 SO2 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. 
Minnesota Steel Page - 39 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 injected 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 CO2. The oxidation process requires temperatures of 600 to 1,000°F to 

achieve 90 to 95 percent conversion of CO. The catalyst increases the reaction rate and allows the 

conversion of CO to CO2 at lower temperatures than a normal thermal incinerator. The catalyst is 

typically porous noble metal material, which is supported in individual compartments within the unit. 

An auxiliary fuel-fired burner ahead of the bed heats the entering 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 presence of oxygen, and maintaining it at high 

temperature for sufficient time to complete combustion 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 parameters for thermal oxidation 

systems. 

There are three basic types of thermal oxidation systems: direct flame, 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. 
Minnesota Steel Page - 40 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Recuperative thermal oxidation systems use a tube or plate heat exchanger to preheat the effluent 

stream prior to oxidation in the combustion chamber. Thermal recovery efficiencies typically are 

limited to 40-70% to prevent auto-ignition in the heat exchange package, which could damage the 

equipment. Supplemental fuel therefore is usually required to maintain 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 efficiencies as high as 95%. An incoming gas stream passes through a 

hot bed of ceramic or other material, which simultaneously cools the bed and heats the stream to 

temperatures above the auto-ignition points of its organic constituents. Oxidation 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. Periodically the flow through the beds is reversed 

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

4.6.3 Good Design Methods and Operating Practices 

Good design includes process and mechanical equipment designs which are either inherently lower 

polluting or are designed to minimize emissions. 

Good operating practices include operating methods, procedures and selection 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 (H2S) Emission Control Technologies 

Hydrogen Sulfide (H2S) 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 purpose of the purification units is to remove CO2 from 

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

CO2 from the reducing gas. H2S present in the top gas is also captured by this solution. When the 

solution is regenerated, the CO2 and H2S are released. This off gas steam is treated to control H2S 

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

additional information. 
Minnesota Steel Page - 41 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

4.7.1 Sulfur Recovery - LoCAT 

One method of controlling H2S emissions is to convert the H2S 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 H2S is first absorbed by a slightly basic aqueous LoCAT 

solution and ionizes to bisulfide. Next the reduction 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: 

H2S (g) + H2O ↔ H2S (l) (1) 

H2S (l)→ HS-

 + H+ (2) 

HS-

 + 2Fe+++ → S0(s) + 2Fe++ + H+ (3) 

1/2O2 (g) + H2O → 1/2O2 (l) (4) 

1/2O2 (l) + 2Fe++ + H2O → 2Fe+++ + 2OH-

 (5) 

4.7.2 Absorption – Zinc Oxide 

Absorption is another means of controlling H2S emissions. In this case, the H2S chemically reacts 

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

H2S removal when H2S 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, H2S can be destroyed by oxidation. Oxidation is used to eliminate the odor 

issues associated with H2S, which H2S can cause odor problems at low ppm concentrations. In an 

oxidizer, H2S is oxidized to form SO2. SO2 emissions are much less odorous and therefore, less 

objectionable than H2S 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 H2S. 
Minnesota Steel Page - 42 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

4.7.4 Flue Gas Desulfurization (FGD) Following Oxidation 

There are many available FGD systems including wet scrubbing, spray dryer absorption and dry 

sorbent injection as described in Section 4.3. FGD would be employed downstream of an oxidizer to 

minimize collateral SO2 emissions. 

4.8 Compliance with BACT during Startup, Shutdown and 

Malfunction 

For periods of startup, shutdown and malfunction, 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 per 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 fixed while the unit is operating or shutdowns due to 

unplanned equipment failures (malfunctions). Actions taken during annual maintenance inspections 

are designed to minimize the number of shutdowns due to malfunctions and maintenance during the 

remainder 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 emission control equipment operating at optimum control 

efficiency due to changing conditions. In addition, some emissions control equipment must reach 

proper operating temperatures before 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 operating practices for minimizing emissions, 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 which cannot meet BACT limitations during startup and 
Minnesota Steel Page - 43 Emission Control Technologies 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

shutdown. The BACT report identifies those conditions where applicable BACT limitations for 

normal operations cannot be met at all times during startup, shutdown and malfunction. 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 emission 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 equipment 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 shutdowns of process units within the facility will be 

phased. This will minimize the number of sources, which at any given time; have excess 

emissions due to startup and shutdown activities. 

• During periods of malfunction, Minnesota Steel will identify and correct the cause of the 

malfunctions as soon as practicable, and/or will consider taking the malfunctioning equipment 

out of service until it can be operated in a manner consistent with the applicable environmental 

requirements. 

Minnesota Steel will prepare a startup, shutdown and malfunction plan specifying the actions to be 

taken during startup, shutdown and malfunctions, and when the requirements of the startup, 

shutdown and malfunction plan are applicable. 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 malfunction plan will be prepared prior to the initial startup of the facility. As 

noted above, plans for startup, shutdown and malfunction 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 BACT Attachment M Table 1.
Minnesota Steel Page - 44 Mining & Crushing 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 open pit mine. First the earth and rock on top of the 

ore (overburden) are removed with controlled blasting, diesel-hydraulic 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 vary, but the general goal is to strip one ton of overburden and waste 

rock per ton of ore for the life of the mine. After overburden stripping, waste 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 ore 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 matter emissions. Point 

source emissions from mining 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 processing crude taconite ore and consists mostly of 

crushing and milling (grinding). This step will reduce mined ore to the appropriate size for further 

processing. Primary and secondary crushers crush dry ore and are sources of particulate matter. 

5.2 Mining and Crushing Material Handling Process and Emission 

Description 

In the mining section of the plant, material handling equipment include ore crushing equipment, ore 

screening and ore conveyor drops. Primary and secondary crushers operate on dry ore and are subject 

to BACT requirements for particulate control. Tertiary ore size reduction takes place in an 

autogenous grinder which is a wet process; therefore, it 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. Material handing equipment reviewed in 
Minnesota Steel Page - 45 Mining & Crushing 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Section 11 includes conveyor drops, crushing and grinding operations and screening of raw materials 

and intermediate products. Section 11 also contains a list of sources covered by the material 

handling BACT analysis. 

5.2.1 BACT Selection Summary for Mining and Crushing Material Handling 

BACT for material handling in the mining and crushing area 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/dscf as measured by EPA Method 5. 

For periods of startup and shutdown, Minnesota Steel 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 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. 

5.3 Fugitive Dust Emissions 

Sources of fugitive particulate emissions from mining operations at Minnesota Steel include drilling, 

unpaved roads, storage piles, loading and unloading operations, and material drops from mobile 

equipment. 

In order to simplify the BACT report, fugitive sources 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 drops 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 Mining 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. 
Minnesota Steel Page - 46 Concentrator 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 (FE3O2) 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 will 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 

(Fe3O4 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 formation and induration. 

Because only about 33 percent of the crude taconite ore becomes concentrate for iron making, about 

67 percent must be transferred to stockpiling as tailings. 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 operations 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 stockpiling and handling, and tailings basin wind erosion. 

6.2 Ore Concentrator Material Handling Process and Emission 

Description 

In the ore concentration section of the plant, material handling equipment includes crushed ore 

conveyors and conveyor drops and concentrate conveyors and conveyor drops. Crushed ore entering 

the concentrator is dry, and particulate controls will be needed at the entry point to the concentration 
Minnesota Steel Page - 47 Concentrator 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 materials 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 enclosure 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 Material 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 particulate emissions. 

6.3 Ore Concentrator Fugitive Dust Emissions 

Sources of fugitive particulate emissions from ore concentrator operations at Minnesota Steel 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 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. 
Minnesota Steel Page - 48 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 moistened 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 hardened by a process called induration. The green balls are dried and 

heated in an oxidizing atmosphere at a temperature of 1290° to 1400°C (2350° to 2550°F). 

The application of heat during indurating triggers the oxidation of magnetite mineral (Fe3O4) 

to the hematite form of iron mineral (Fe2O3). 

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, hardening, 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 contains 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 designed to maximize heat recovery with process 

constraints. Airflow across the pellet cooling grates is directed to the updraft drying section. 

Pellet cooling air is also utilized 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. 
Minnesota Steel Page - 49 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

After preheating, pellets proceed to the primary 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. These temperatures are needed to meet taconite 

pellet product specifications. The application of heat during indurating triggers the oxidation 

of magnetite mineral (Fe3O4) to the hematite form of iron mineral (Fe2O3). This reaction is 

exothermic and contributes 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 degree 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 flue 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 information, approximately 30 percent of the 

combustion gases exit through the hood exhaust. This is due to the diversion of some high 

temperature gases associated with the firing section for 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 the DRI plant oxide day bins, and transfer of 

oversize and undersize pellets and pellet fines to the regrind mill. Pellet plant additive 

receiving and handling includes the railcar or truck unloading of materials 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 conveyors leading to the pellet storage bins or 

stockpiling. Point source emissions for the additive receiving and handling operations are the 

result of venting additive silos and day bins during pneumatic transfer. Day bins vent back to 

the storage silos whose vents are controlled with fabric filters. 
Minnesota Steel Page - 50 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Fugitive air emission sources within the pellet plant include wind erosion of concentrate 

stockpiles, oxide product handling, and oxide pellet stockpiling. Intermittent concentrate 

storage and handling operations consist of the on-ground storage of concentrate during pellet 

plant shutdown events, loading of stockpiled concentrate onto conveyers, and the transfer of 

concentrate by conveyor. These operations occur only if downstream processing cannot 

accommodate the concentrate 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 the pellets move through the indurating 

furnace. 

• The majority of sulfur dioxide (SO2) emissions originate from the sulfur present in 

the taconite ore. The emission inventory and BACT review determined the SO2

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 finished 

taconite pellets and the taconite pellet production rate. 

• Nitrogen oxides (NOx) 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, NOx emissions due to fuel 

bound nitrogen are negligible. Thermal oxidation is a function of the residence time, 

free oxygen, and peak temperature, and produces the majority of NOx emissions from 

the pellet plant. The oxidation reaction, which 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: 

N2 + O2 → 2NO (1) 
Minnesota Steel Page - 51 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Downstream of the flame, significant amounts of NO2 can be formed when NO is mixed 

with air. The reaction is as follows: 

2NO + O2 → 2NO2 (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 zone and are released into the waste gas. 

Fluoride compounds are acidic in nature and will be captured by SO2 controls or wet 

particulate scrubbing. 

• Sulfuric acid mist formation is the result of oxidation of SO2 to SO3. For this permit 

application, an 0.4% SO2 to SO3 oxidation ratio has been assumed to conservatively 

assess the ambient impacts of sulfate emissions. Once formed, SO3 reacts with water 

to form sulfuric acid mist. This reaction occurs at approximately 350oF. Sulfuric acid 

mist will be captured by SO2 controls or wet particulate scrubbing. 

7.3 Pellet Plant Control Selection 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, PM10, SO2, NOx, 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 controlling all of these pollutants. Although a control 

technology may work for controlling one pollutant, 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 would potentially increase the risk of Minnesota Steel’s project 

not moving forward. 
Minnesota Steel Page - 52 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Sections 7.4 – 7.11discuss the technical and 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 PM10) Emissions 

7.4.1 Sources of Induration Furnace Particulate Matter Emissions 

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 and other and 

the process equipment as the pellets move through the induration furnace. Particulate matter 

is emitted from both the waste gas and hood exhaust vents. 

The waste gas also contains a small about of condensable particulate matter. The 

condensable particulates are primarily inorganic compounds like sulfates, acid gases, 

chlorides and fluorides which are generated as a byproduct of pellet induration. The waste 

gas may also contain volatile organic compounds, which are products of incomplete natural 

gas combustion. 

7.4.2 Identification of Potential PM/PM10 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 Technically Infeasible PM/PM10 Control Options 

Table 7-1 summarizes the feasibility of PM/PM10 emission control technologies for the pellet 

plant. 
Minnesota Steel Page - 53 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Table 7-1 Evaluation of Most Effective PM/PM10 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 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 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 the bags that would be difficult to remove. 

In addition, it is possible to exceed filter bag temperature limits. Taconite pellets in the 
Minnesota Steel Page - 54 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

straight grate furnace are extremely hot. The temperature of the hood exhaust and waste gas 

will increase significantly during 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/PM10 Control Technologies by Control Effectiveness 

The remaining control technologies and their control efficiencies are presented in Table 7-2. 

Table 7-2 Ranking of Remaining PM/PM10 Control Technologies and Control 

Effectiveness for the Pellet Plant Indurating Furnace 

PM / PM10 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 inertial 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. These 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 improve the effectiveness of downstream pollution 

control equipment. 

7.4.4 Evaluation of Most Effective Control Technologies 

Table 7-3 and Table 7-4 summarize the effectiveness of PM/PM10 control technologies for the 

waste gas stream and hood exhaust respectively. The effectiveness evaluation for the waste 
Minnesota Steel Page - 55 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

gas stream is based on control of the total amount of particulate matter emitted in the waste 

gas stream and does not include consideration of the particulates 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/PM10 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/PM10 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). 
Minnesota Steel Page - 56 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

The particulate control devices listed above are all highly effective and have the same 

relative control effectiveness for total particulate matter emitted (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 particulate matter (See 

particulate matter control equipment descriptions in Section 4.2). 

7.4.5 Pellet Plant Indurating Furnace PM/PM10 BACT Selection 

The technical feasibility and removal effectiveness of fabric filters is questionable when 

applied to the pellet plant waste gas and hood exhaust stacks due to filter blinding associated 

with water condensation. A baghouse was deemed technically infeasible for the hood exhaust 

due to high moisture content. Currently, no taconite plants in the United States use fabric 

filters for particulate control on induration furnaces. The process designs for induration 

furnaces include provisions for energy 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 induration 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 filter media would create a wet 

and sticky filter cake that would 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 

(SO2, NOx, acid gases, and some forms of mercury) with minimal additional capital 

investment. With the addition of an oxidizing agent (e.g. ozone) to oxidize elemental 

mercury, removal efficiency of mercury (particle 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 estimated to be approximately $17,000,000 and $22,000,000 

more than a wet scrubber on the waste gas and hood 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 
Minnesota Steel Page - 57 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

control scrubber will be treated in a zero discharge system as described in Section 7.5.6. 

Particulates captured by the emission control scrubber will be disposed with other solids from 

the waste water treatment system in appropriate manner. Therefore, a wet scrubber was 

selected for control of particulate matter from the pellet plant. 

The proposed BACT, for particulate 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 PM10 limit of 0.012 gr/dscf as measured by EPA Methods 201 (or 201A) and 

202 or EPA approved modified Method 202 procedures. Proposed BACT mass emission 

limits for the hood exhaust are 23 lb/hr for PM and 47 lb/hr of PM10, and waste gas stack 

limits of 17 lb/hr PM and 33 lb/hr of PM10. 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 proposed test methods for measuring PM10 (filterable 

particulates less than 10 microns 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 recently promulgated Taconite MACT for new 

sources; which represents the best level of control for new sources within the Taconite source 

category. The preferred method of meeting this goal is by wet scrubbing. 

There were no BACT determinations listed in the RBLC for particulate matter or PM10 

emissions from taconite plants. BACT report Attachment L, Table L -1 is a summary RBLC 

search finding for taconite plants 

For periods of startup and shutdown, Minnesota Steel will put the pellet 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 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 generated by material handling equipment within the 

pelletizer and by incomplete combustion in the pelletizer firing zone. 
Minnesota Steel Page - 58 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.5.1 Pellet Plant 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/PM10 BACT. 

On the pelletizer, PM/PM10 emissions are controlled by wet 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 water droplets when the exhaust plume comes in 

contact 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 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. 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 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 (SO2) Emissions 

7.6.1 Sources of Induration Furnace SO2 Emissions 

The majority of sulfur dioxide (SO2) emissions originate from the sulfur present in the 

taconite ore. There is also a small amount of SO2 emitted from natural gas combustion. The 

emission inventory and BACT review determined the SO2 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 finished taconite pellets and the taconite pellet 

production rate. 

Most of the SO2 emissions emanate from the waste gas stack as the regions of the induration 

furnace where sufficient temperature exist to liberate sulfur compounds from the taconite. 

The hood exhaust contains a small amount of SO2 due to leakage between induration furnace 

zones and the diversion of up to 30% of waste gas for temperature control. 
Minnesota Steel Page - 59 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.6.2 Identification of Potential SO2 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 SO2 control technologies are 

discussed in Section 4.0 and Table 7-5. Potential control technologies for pellet plant 

particulate emissions are the following: 

• Absorber (Wet Scrubber) 

• Wet ESP 

• Spray dryer absorption 

• Dry sorbent injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design and Operating Practices 

7.6.3 Elimination of Technically Infeasible SO2 Control Options 

All of the listed technologies are technically feasible in this application for waste gas 

exhaust. 

SO2 concentrations in the hood exhaust however are calculated to be only 5 - 10 ppm using 

the SO2 mass emission rate from the Air Emission Inventory (Appendix 3B.), and stack flow 

rate from form GI-04. Removal of additional SO2 at these concentrations is technically and 

economically infeasible. SO 2 control technologies use chemical reactions to remove SO2. 

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 SO2 removal 

were technically feasible, the amount removed would be so small that removal would also be 

economically infeasible. 

Application of Good Design and Operating Practices is the only feasible emission control 

method for SO2 on the hood exhaust. 

The technical feasibility in Table 7-5 ignores the technical infeasibility of the particulate 

control technology that must also be employed. The spray dryer absorption and dry sorbent 

injection are typically employed with a baghouse for removal of particulates. A baghouse 
Minnesota Steel Page - 60 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 injection were carried through the BACT selection 

process to evaluate their cost effectiveness. 

Table 7-5 Technical Feasibility of SO2 Control Technologies for Taconite Pellet Indurating 

Furnace 

SO2 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 SO2 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 SO2 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 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. 

Yes 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 

Yes No 

Clean Fuel/ Good 

Combustion Practices 

(Base Case) 

Use natural gas as induration fuel source to 

minimize SO2 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 
Minnesota Steel Page - 61 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.6.4 Ranking of Remaining SO2 Control Technologies by Control 

Effectiveness 

The remaining control technologies and their control efficiencies are presented in Table 7-6. 

Table 7-6 Ranking of Remaining SO2 Control Technologies and Control Effectiveness for 

the Pellet Plant Indurating Furnace 

SO2 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 provided 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 SO2 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 the specifications in the bid request. An 85% 

control efficiency is more representative of the expected control efficiency at the current 

design concentration of SO2 in the waste gas. Wet ElectroStatic Precipitator (Wet ESP) 

control efficiency is based on Northshore Mining 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 SO2 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 exhaust (Table 7-8). The detailed control cost 

analyses are located in Attachment A for the hood exhaust and Attachment B for the waste 

gas. 
Minnesota Steel Page - 62 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Table 7-7 Evaluation of Most Effective SO2 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 SO2 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 
Minnesota Steel Page - 63 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.6.6 Pellet Plant Indurating Furnace SO2 BACT Selection 

As discussed earlier the feasibility of associated particulate control technologies was ignored 

in the assessment of SO2 control technologies. Regardless of the particulate control 

equipment selection, a wet scrubber with lime injection is the most cost effective control 

option for SO2. A wet scrubber was also selected for control of particulates. 

The proposed SO2 BACT for the Hood Exhaust is Clean Fuel/Good Combustion Practices 

(Base Case) and Good Design Methods and Operating Practices. This is based on combustion 

of natural gas in the fired section of the pelletizer which minimized the amount of SO2 which 

migrates from the waste gas to the hood exhaust via wind box leakage. The proposed SO2

mass limit for the Hood Exhaust is 36 lb/hr SO2 on a 3-hour average basis and 7.8 ppm. 

The proposed SO2 BACT for the Waste Gas Stack is 3.3 ppm SO2 at 15% O2 and 10 lb/hr 

SO2 on a 3 hour average basis. Both wet scrubber and Wet ESP controls will generate 

wastewater. The facility will have a wastewater treatment system to handle the wastewater 

steams in an environmentally acceptable manner. Minnesota Steel Industries has elected to 

design the facility with zero waste water discharge 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 whether 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 and deposed of in and appropriate manner along 

with the other compounds removed by the softening 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 SO2 BACT also includes good design methods and 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 SO2 present in the Hood 

Exhaust. 

There were no BACT determinations listed in the RBLC for SO2 emissions from taconite 

plants. BACT report Attachment L, Table L -1 is a summary RBLC search finding for 

taconite plants 
Minnesota Steel Page - 64 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

For periods of startup and shutdown, Minnesota Steel will put the pellet plant SO2 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 (NOx) Emissions 

7.7.1 Sources of Induration Furnace NOx Emissions 

Nitrogen oxides (NOx) 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, NOx 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 NOx emissions 

from a pellet plant are from thermal NOx formation. 

The majority of combustion zone gases, including NOx, are emitted through the waste gas stack. The 

hood exhaust contains up to thirty percent of the NOx due to leakage between induration furnace 

zones and the diversion of some waste gas for temperature control. 

7.7.2 Identification of Potential 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 NOx control technologies are discussed in Section 

4.0 and Table 7-9. Potential control technologies 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 Flue Gas Recirculation Burners 

• Oxyfuel burners 

• Low excess air (LEA) 

• Other combustion controls 

• Good design methods and operating practices 
Minnesota Steel Page - 65 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.7.3 Elimination of Technically Infeasible NOx Control Options 

Table 7-9 summarizes the technical feasibility of NOx control technologies for the waste gas stream 

and the hood exhaust. Details regarding the feasibility of each technology are discussed in the 

following sections. 

Table 7-9 Technical Feasibility of NOx Control Technologies for Taconite Pellet Indurating 

Furnace 

NOx 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 

NOx 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 NOx control technology in which 

ammonia (NH3) 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 N2 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. NOx and CO react in the 

presence of NSCR catalyst to form nitrogen (N2) 

and carbon dioxide (CO2). 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 NOx. 

No No 
Minnesota Steel Page - 66 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

NOx 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-NOx burner (LNB) technology utilizes 

advanced burner design to reduce NOx

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 NOx 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 NOx

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), Burners 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 the hood exhaust for temperature control. Since no 

combustion is taking place in the hood exhaust stream, combustion controls are technically 

infeasible. 

7.7.3.1 Low Temperature Oxidation (LTO) 

LoTOx is an innovative NOx control technology licensed by BOC Gases which uses low temperature 

oxidataion (LTO) to control NOx. LoTOx 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 characteristics. Application of 

LoTOx to the pelletizer waste gas 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: 
Minnesota Steel Page - 67 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

• 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 

NOx 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 refineries. The LoTOx technology 

applications in the petroleum refining industry are for Fluid Catalytic Cracking (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 gas 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 temperatures (2,400°F vs 

1,300°F) and higher oxygen concentrations (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 regenerator 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 for particles > 10u. The pelletizer scrubber 

water will contain lime for SO2 emissions control. A sodium hydroxide solution (caustic) is 

typically used to control SO2 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 and install LoTOx controls. All the factors noted 

above have the potential to affect NOx control efficiency and reagent 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. 
Minnesota Steel Page - 68 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.7.3.2 Selective Catalytic Reduction (SCR) 

The MPCA has requested consideration of the application of SCR for NOx control in conjunction 

with dry scrubbing for SO2 control on the Minnesota Steel pelletizer. This combination of controls 

affords use of dry particulate control technologies and of activated carbon 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 SO2 control. Dry 

controls keep the dust collected in a dry state, which allows recycling4

 of SO2 and mercury removal 

reagents and eliminates a wastewater stream. Baghouses for dry controls have not been employed on 

taconite furnaces due to concerns that moisture from pellet drying and fuel combustion would 

condense the baghouse and were deemed technically infeasible in Section 7.4. 

In evaluating the technical feasibility of SCR, Minnesota Steel has identified two potential locations 

in the pelletizing furnace where SCR could potentially be installed to control NOx 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 particulate 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 reactor. In conventional straight grate pelletizing 

furnace designs, gases exiting the bottom of the combustion zone grate system are at 258oF– 320oF. 

The normal SCR operating temperature window is 600oF – 800oF and the minimum temperature that 

the newer low temperature 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. Application of SCR to the pellet plant would require reheating the waste gas exhaust back to the temperature necessary for SCR operation. Re-heating the 
Minnesota Steel Page - 69 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

waste gas exhaust generates additional NOx formation from natural gas combustion. The conceptual 

design balances treatment of NOx 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 NOx 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 NOx. This reduces the overall efficiency of SCR compared to other 

technologies that are able to treat the entire waste gas exhaust stream. The overall NOx 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 temperature 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 salts. 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 indurating furnace. Therefore, use of SCR In the 

recuperative heat recovery system duct between the pellet firing 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 temperatures. Re-heating the waste gas pollution control 

exhaust for SCR is not feasible because it would require an excessive 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 contains un-reacted reagents. Some of the material collected is mixed with fresh 

reagent and reused in the scrubber. This is done to minimize reagent consumption. 
Minnesota Steel Page - 70 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

put this into perspective, reheating waste gas for the Minnesota Steel pelletizer would require 63 

MMBtu per hour assuming a 70% recuperative heat recovery system is used. An energy efficient 

pellet plant requires 265,000 Btu per short ton of pellets. 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 service. 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 flow 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 significant capital investment 

which would be lost if SCR did not function as intended. An SCR approach would require the redesign of the pelletizer wind box system 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 

NOx controls is much less. The only additional equipment needed to test wet NOx controls on a 

SO2/PM wet scrubber, is an ozone injection system consisting of a temporary ozone generator and a 

temporary oxygen supply (delivered). If LoTOx testing is unsuccessful, the LoTOx equipment can 

be removed at minimal cost. Because of potential corrosion problems, additional energy 

requirements for gas reheating, and lower NOx 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 NOx control. The combustion zone temperature of the indurating 

furnace is 2,400oF. Gases leaving the combustion zone grates are only 258oF– 320oF, well below the 

SNCR temperature window. In addition, ammonia slip would react with sulfur dioxide to form 
Minnesota Steel Page - 71 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

ammonium sulfate salts. These compounds are gummy and corrosive. If present, they would have 

an adverse affect on the pellet drying and preheat 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 this, 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 waste gas for SNCR would consume 1,650 million cubic 

feet of natural gas per year or almost 90% of the design 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 induration. 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 strong pellet that meets product specifications. 

Another factor affecting the feasibility of FGR is the high levels of oxygen in the pelletizer furnace. 

Normally flue gas is inert and has low levels of oxygen (2% - 3%). At these levels flue injected into 

the combustion zone of a burner effectively dilutes the combustion reactants (fuel and air) so the 

flame temperature can be lowered for NOx control. Pelletizer flue gas has approximately 12% - 15% 

oxygen. At these levels, injection of flue gas into 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 pelletizer flue gas in FGR. 

7.7.3.5 Low NOx Burners (LNB) 

The temperature and oxygen requirements of induration prevent the successful application of 

standard LNB technology to the pellet plant. LNB technology is based on lowering NOx emissions by 

reducing flame temperature. Thermal NOx formation starts at 2,600oF and begins to increase rapidly 

at temperatures above 3,000oF. Pellets must be heated to, and maintained at, a temperature of 2400 - 

2450°F, to produce a completely oxidized, high strength and abrasion resistant pellet. This puts 

induration temperatures near the point where thermal NOx formation begins. Thus, flame 

temperature reductions for NOx control via LNB technology are limited by temperature requirements 

of taconite induration. 
Minnesota Steel Page - 72 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 levels in order to achieve complete pellet 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 NOx Control Technologies by Control 

Effectiveness 

The third of the five steps in the top-down BACT analysis is to rank the remaining control 

technologies by control effectiveness. The remaining 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 NOx Control Technologies 

Each of the most effective control technologies from Table 7-10 are 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 NOx 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 
Minnesota Steel Page - 73 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Table 7-12 Evaluation of Most Effective NOx 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 NOx BACT Selection 

The proposed BACT emission controls for NOx emitted from the pellet plant hood exhaust and waste 

gas steams are good design methods and operating practices. None of the add-on control technologies 

evaluated are technically feasible at this time. 

The proposed BACT NOx mass emission limit for the Hood Exhaust is 165 lb/hr on a 24-hour 

average basis and 45 ppm. The proposed BACT NOx mass emission limit for the Wate Gas Exhaust 

is 464 lb/hr NOx on a 24- hour average basis. 

RBLC listings for NOx controls from taconite processing are listed in Appendix L, Table L-1. Only 

one NOx determination is listed. Ispat Inland Mining installed low NOx burners as BACT. Only a lb 

NOx per hour limit is listed; no performance limit is specified. Per the facility, no performance test 

data were collected prior to installation of the low NOx burners and insufficient information exists to 

determine the effectiveness of low NOx burners in this application. 

For periods of startup and shutdown, Minnesota Steel will follow good operating practices while 

commencing operation of process equipment. However, NOx emissions during startup 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, Table 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 feasible on the waste gas exhaust. If feasible, the data from the trial 
Minnesota Steel Page - 74 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

will also provide the information necessary to accurately estimate the cost and design for a full scale 

installation. This test is necessary because no application of the technology 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 information from non-taconite installations 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 NOxremoved. 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, Minnesota Steel will re-evaluate the application of SCR and investigate 

other emerging control technologies which may become commercially available at that time. 

Although SCR would have lower control effectiveness for NOx than LoTOx, it still would reduce 

NOx emissions. Due to the unanswered questions regarding the application of SCR on a pellet plant 

additional, testing of SCR would also be necessary. At that time the economic feasibility of SCR 

would also be evaluated. 

Based on the low levels of NOx present in the hood exhaust, LoTOx is economically infeasible. At 

$18,183 per ton of NOx removed, the NOx 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 LoTOx vendor’s recommendation to perform an 

optimization study using their LoTOx Mobile Demonstration Trailer. The demo trailer has been 

specifically designed to characterize flue gas streams with injection of ozone for NOx treatment to 

allow proper sizing of equipment to and to evaluate the site specific performance of LoTOx. This 

demo trailer is useful in characterizing highly variable NOx streams, and the effect of other chemical 

compounds (i.e. taconite dust) in the gas stream on the performance 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 that 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. 
Minnesota Steel Page - 75 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 NOx 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 feasibility of LoTOx will be evaluated based on the following criteria: 

• Ability to provide at least a 70% reduction in NOx emissions over a 24-hour period of 

operation at a range of NOx emission 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 SO2 control of the scrubber are unaffected 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 following schedule for conducting the LoTOx 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. 
Minnesota Steel Page - 76 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

• Submit LoTOx trial feasibility report to the MPCA 75 days after completion of testing. 

• The MPCA will have 30 days to review and object to the conclusions of the report. 

• If LoTOx is deemed economically and technically feasible, installation and startup of full 

scale LoTOx system will be completed within 25 months of completion of testing. 

•

• If LoTOx is installed, the estimated NOx emission limit for the Waste Gas Exhaust is 25 ppm 

NOx at 15% O2 and 46 lb/hr NOx 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 Induration 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 emitted through the Waste Gas 

stack. The Hood Exhaust contains up to thirty percent of CO due to leakage between indurating 

furnace zones and the diversion of waste gas for temperature control. 

7.8.2 Identification of Potential 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 particulate emissions are the 

following: 

• Thermal oxidizer (Recuperative and Regenerative) 

• Catalytic oxidizer 
Minnesota Steel Page - 77 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

• 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 feasibility of each technology are discussed in the 

following sections. 

Estimated CO concentrations in the waste gas and hood exhaust are 9 ppm and 2 ppm respectively 

using the CO mass emission rate from the Air Emission 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 would be so small that 

removal would be economically infeasible. 

Application of Good Design and Operating Practices is the only feasible CO emission control method 

for the hood exhaust 
Minnesota Steel Page - 78 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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

Furnace 

CO 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 uses high temperature 

and residence time to oxidize CO to CO2. 

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 gas to thermal oxidizer operating temperatures. Application of a 

thermal oxidizer on the waste gas would have similar energy requirement as the application of SNCR 

downstream of pellet plant pollution control equipment. Based on the 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 present in the hood exhaust. 
Minnesota Steel Page - 79 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.8.4 Ranking of Remaining CO Control Technologies by Control 

Effectiveness 

The third of the five steps in the top-down BACT analysis is to rank the remaining control 

technologies by control effectiveness. The remaining 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 Effective CO Control Technologies 

Each of the most effective control technologies from Table 7-14 are evaluated in Table 7-15 for the 

Indurator Waste Gas Stream and Table 7-16 for the Indurator Hood Exhaust. The detailed control 

cost analyses are located in Attachment A for the 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 
Minnesota Steel Page - 80 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 proposed 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 facility 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 proposed 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 representative of the best level of controls achievable. The mass emission limit is 

based on operation with BACT controls and the facility running at full capacity. 

The CO BACT also includes good combustion practices, 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 taconite plants. 

BACT report Attachment L, Table L -1 is a summary 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 startup 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, Table 1, for a summary of proposed startup/shutdown emission limits 
Minnesota Steel Page - 81 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.8.7 Sources of Induration Furnace VOC Emissions 

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 VOC is generated, are emitted 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 small amount of waste gas for temperature control. 

7.8.8 Identification of Potential 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 particulate 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 technologies for the waste gas stream 

and the hood exhaust. Details regarding the feasibility 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 emission rate from the Air Emission Inventory (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 feasible, the amount removed would be so small that 

removal would be economically infeasible. 

Application of Good Design and Operating Practices is the only feasible emission control method for 

the hood exhaust 
Minnesota Steel Page - 82 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 uses high temperature 

and residence time to oxidize VOC to CO2

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 the induration waste gas because of the inordinate 

amount of energy which would be required to operate a thermal oxidizer for a very large gas stream. 

Natural gas consumption for a thermal oxidizer is estimated to be 1,520 million 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 present in the hood exhaust. 
Minnesota Steel Page - 83 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.8.10 Ranking of Remaining VOC Control Technologies by Control 

Effectiveness 

The third of the five steps in the top-down BACT analysis is to rank the remaining control 

technologies by control effectiveness. The remaining 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 Effective VOC Control Technologies 

Each of the most effective control technologies from Table 7-14 are evaluated in Table 7-15 for the 

Indurator Waste Gas Stream and Table 7-19 for the Indurator Hood Exhaust. The detailed control 

cost analyses are located in Attachment A for the 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 
Minnesota Steel Page - 84 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 Indurating Furnace VOC BACT Selection 

The proposed BACT for the Hood exhaust is no add-on controls. This determination is based on the 

low levels of VOC present in the Hood exhaust. BACT also includes good design methods and 

operating practices for minimizing waste gas migration 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 Gas Stack is 5.9 lb/hr VOC on a 24 hour average basis. No addon controls are recommended to meet 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 practices, 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 VOC emissions from taconite plants. 

BACT report Attachment L, Table L -1 is a summary RBLC search finding for taconite plants. 

The VOC BACT also includes good combustion practices, 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 process is shut down and off line. . However, NOx 

emissions during startup 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 
Minnesota Steel Page - 85 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

steady state conditions are reached, fuel consumption will return to normal. See Attachment M, Table 

1, for a summary of proposed startup/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 emission 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 sufficient temperature exist to liberate fluoride compounds from the 

taconite. The hood exhaust contains a small amount of fluoride due to leakage between induration 

furnace compartments and the diversion of a small amount of waste gas for temperature control. 

7.9.2 Identification of Potential 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 technologies for pellet plant particulate emissions are 

the following: 

• Wet Scrubber 

• Wet ESP 

• Spray dryer absorption 

• Dry sorbent injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design and Operating Practices 

7.9.3 Elimination of Technically Infeasible Fluoride Control Options 

All of the listed technologies are technically feasible in this application for waste gas exhaust given 

that some fluoride emissions control will occur as a co benefit of the SO2 emission controls installed 

as BACT 
Minnesota Steel Page - 86 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Fluoride concentrations in the hood exhaust however 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 feasible for control of fluoride emissions in the waste 

gas. However, fluorides are present only in low concentrations and measurable emission reductions may 

not be quantifiable. 
Minnesota Steel Page - 87 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

 

Application of Good Design and Operating Practices is the only feasible emission control method for 

fluoride emissions from the hood exhaust. Steam 

7.9.4 Ranking of Remaining Fluoride Control Technologies by Control 

Effectiveness 

The remaining control technologies and their control efficiencies are presented 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 

SO2 control efficiencies have been used as a general indicator of the emission control effectiveness 

on fluoride compounds in the waste gas. The listed control efficiencies are for SO2 removal, and are 

presented only for example calculations of the fluoride 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 SO2 gases are acidic, SO2 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 concentrations of fluoride, fluoride 

control efficiency may vary from the overall SO2 control efficiency 

As noted above, fluoride concentrations in the pelletizer exhaust streams are too low for control 

equipment to be considered technically feasible. 
Minnesota Steel Page - 88 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

7.9.5 Evaluation of Most Effective Fluoride Control 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 are approximately 1 ppb; therefore, add on controls are technically 

infeasible. The detailed control cost analyses are located in Attachment A for the hood exhaust and 

Attachment B for the waste gas. 

Table 7-23 Evaluation of Most Effective Fluoride 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 
Minnesota Steel Page - 89 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Table 7-24 Evaluation of Most Effective Fluoride 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 control 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 Furnace Fluoride BACT Selection 

The proposed BACT for the waste gas stack is application of BACT SO2 emission controls to 

minimize fluoride emissions, use of clean fuels (natural gas or its equivalent), and good design 

methods and operating practices for minimizing waste 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 hours (three 1-hour test runs).The BACT review of 

SO2 emissions control for the waste gas stack indicates that SO2 absorption and dry scrubbing are the 

top SO2 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 based BACT emission limits for fluorides are not recommended. 

Since fluoride emissions are related to SO2 emissions, Minnesota Steel proposes to demonstrate 

ongoing control of fluoride emissions by operating its SO2 emissions control equipment in 

accordance with the proposed BACT limit for SO2 and monitoring the fluoride content in the green 

balls.. 
Minnesota Steel Page - 90 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Due to the low concentrations of fluorides in the hood exhaust (< 1 ppb), no add on controls are 

technically feasible. The proposed BACT for the Hood Exhaust is good 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 fluoride emissions from taconite plants. 

BACT report Attachment L, Table L -1 is a summary 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 occur 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 Furnace 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 concentrations of 0.1 ppm and 3 ppm respectively for 

the hood exhaust and waste gas streams. These concentrations are calculated from the SAM mass 

emission rates in the Air Emission Inventory (Appendix 3B.), and stack flow rates from form GI-04. 

Most of the SAM emissions emanate from the waste gas stack as the regions of the induration 

furnace where sufficient temperatures exist to liberate sulfur compounds 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 Potential Sulfuric Acid Mist 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 technologies for pellet plant particulate 

emissions are the following: 

• Wet Scrubber 

• Wet ESP 
Minnesota Steel Page - 91 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

• Spray dryer absorption 

• Dry sorbent injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design and Operating Practices 

7.10.3 Elimination of Technically Infeasible Sulfuric Acid Mist Control 

Options 

All of the listed technologies are technically feasible in this application for waste gas exhaust given 

that some SAM emissions control will occur as a co-benefit of the SO2 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 Emission 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 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 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 
Minnesota Steel Page - 92 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 

SO2 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 trace quantities in the hood exhaust 

and waste gas. Since SO2 gases are also acidic; SO2 control efficiencies are 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 SO2 control 

efficiency 

As noted above, SAM concentrations in the hood exhaust streams are too low for control equipment to be 

considered technically feasible. 

7.10.4 Ranking of Remaining 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 technically infeasible. 

The remaining control technologies and their control efficiencies are presented in Table 7-26. 
Minnesota Steel Page - 93 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 SO2 removal, 

and are presented only for example calculations of the SAM control cost. 

Wet scrubber and spray dryer control efficiencies were provided with the cost estimate by the vendor 

(Environmental Elements). Wet ElectroStatic Precipitator (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 exhaust and Attachment B for the waste gas. 
Minnesota Steel Page - 94 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 Indurating Furnace Sulfuric Acid Mist BACT Selection 

The proposed BACT for the waste gas stack is the application of BACT SO2 emission controls to 

minimize SAM emissions, use of clean fuels (natural gas or its equivalent), and good design methods 

and operating practices for minimizing waste gas migration into the hood exhaust system. The 

BACT review of SO2 emissions control for the waste gas stack indicates that SO2 absorption and dry 

scrubbing are the top SO2 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 average. Compliance will be demonstrated for 
Minnesota Steel Page - 95 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

both limits by performance testing. The averaging period for SAM emissions 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. 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 SO2 emissions control, 

Minnesota Steel proposes to demonstrate control ongoing control of SAM emissions by operating its 

SO2 emissions control equipment in accordance with the proposed BACT limit for SO2. 

Due to the low concentrations of SAM in the hood exhaust (< 1 ppm), no add on controls are 

technically feasible. The proposed SAM BACT for the Hood Exhaust is good 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 SAM emissions from taconite plants. 

BACT report Attachment L, Table L -1 is a summary RBLC search finding for taconite plants. 

For periods of startup and shutdown, Minnesota Steel will put the pellet plant SO2 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 occur 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 Furnace 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) from the taconite pellets. This is caused by the abrasion of pellets 

rubbing against one and other and the process equipment as the pellets move 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 Potential 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 control technologies for pellet plant lead emissions are the following: 
Minnesota Steel Page - 96 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

• 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 Technically 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 Effective 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 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 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 
Minnesota Steel Page - 97 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 control efficiencies are presented 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) 
Minnesota Steel Page - 98 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

Particulate control efficiencies have been used as a general indicator of the emission control 

effectiveness on lead bearing particulates. Lead in the hood exhaust and waste gas is present only in 

trace quantities. Based on the Air Emission Inventory (Appendix B1.), and stack flow rate from form 

GI-04, the calculated lead concentration in the uncontrolled hood exhaust is 0.0001 gr/dscf, and 

0.00005 gr/dscf in the waste gas exhaust. Given the 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 located in Attachment A for the hood exhaust and 

Attachment B for the waste gas. 

Table 7-31 Evaluation of Most Effective Pb Control 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 Control 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 
Minnesota Steel Page - 99 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 can remove particulate matter down to the 0.006 

gr/dscf level as measured by EPA Method 5. All controls are economically feasible. Based on the 

control effectiveness ranking, choosing any of these 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 (SO2 and 

NOx) with minimal additional capital investment. 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 materials 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 Indurating 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 review of PM emissions control for both the hood 

exhaust and waste gas stack indicates 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 plant. 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 control equipment alternative. The proposed emission limit of lead for the hood 

exhaust is 0.013 lb/hr. The proposed emission limit of lead for the waste gas stream is 0.013 lb/hr. 

Compliance demonstration for both limits will be determined by performance 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 (three 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 summary RBLC search finding for taconite plants 
Minnesota Steel Page - 100 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

For periods of startup and shutdown, Minnesota Steel 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 occur 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 Selection 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, SO2, and NOx with a wet scrubber that includes lime addition and 

injection of ozone (LoTOx), 

• Scenario 2 - control of NOx with SCR (on a portion of the waste gas exhaust), and control of 

PM and SO2 with a wet scrubber with lime addition, and 

• Scenario 3 - control of NOx with SCR (on a portion of the waste gas exhaust), control of SO2

with dry absorption, and control of PM with a baghouse or dry or wet ESP. 

In some cases, emission controls have the potential to be used in controlling multiple pollutants. At 

Minnesota Steel, the wet scrubber for the pellet plant has the potential for multi-pollutant control. 

The wet scrubber will control PM, SO2, NOx, as well as the other less significant pollutants (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 additional 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. 
Minnesota Steel Page - 101 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 

(SO2) 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 boilers. Most of the mercury emitted from taconite 

pellet plants is emitted from the waste gas exhaust 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. Ozone 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 testing 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 before designed and implemented. 
Minnesota Steel Page - 102 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

SCR may by a viable alternative to LoTOx should the LoTOx trial fail. In addition, the pelletizer 

wind boxes would have to be reconfigured to accommodate SCR. 

SCR followed by a wet scrubber with lime addition would 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 removal of mercury in the same manner as LoTOx. 

However, just as with NOx, the mercury removal efficiency would 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, ammonia 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 SO2 and PM would add to the need for design modifications to the 

pellet plant, 

• Operating all three innovative control technologies at once, while 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 gases or fluorides nearly as well as the other 

control scenarios. SCR will generate additional sulfuric acid mist due to the conversion of 

SO2 to SAM by the SCR catalyst. 

• Control of oxidized mercury from the SCR unit would be significantly less and additional 

controls would be needed to achieve the same level of control as scenarios 1 and 2, 

Scenario 3 involves the application of 3 innovative technologies and a major redesign of the 

pellet plant. Scenario 3 represents a very risky 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 
Minnesota Steel Page - 103 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

stranded. Scenarios 1 and 2 involve only the application of 1 innovative technology. The wet 

scrubber is a proven technology to control PM and SO2 emissions from taconite pellet plants and, 

regardless of the resulting feasibility of NOx control technologies, can be financed and installed 

as part of the initial pellet plant configuration. By permitting a trial 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 technology 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 taconite pellet screening, pellet conveyor drops, and finished pellet 

coating operations. 

In order to simplify the BACT report, emissions controls for material 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 grinding operations and screening of raw materials 

and intermediate products. Section 11 also contains a list of material handling sources covered by the 

material handling BACT analysis. 

BACT for material handling the pellet plant area of the facility is the use of a wet scrubber or fabric 

filter in conjunction with a ventilated enclosure of the emission source. The proposed BACT limit 

for particulate emissions is for wet scrubbers is 0.005 gr/dscf and for baghouses is 0.0025 gr/dscf as 

measured by EPA Method 5. Attachment N specifies the type of control applied to each emission 

point. Where feasible baghouses have been specified 

For periods of startup and shutdown, Minnesota Steel 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 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. 
Minnesota Steel Page - 104 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 transfers 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 materials 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 Additive 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 particulate emissions from pneumatic transfers of additive materials. The proposed 

BACT limit for particulate emissions (PM/PM10) is 0.0025 gr/dscf as measured by EPA Method 5. 

Minnesota Steel will put the additive handing 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. 

7.15 Pellet Plant Fugitive Dust Emissions BACT Selection Summary 

Fugitive dust emissions are particulate 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 emissions 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 material handing equipment throughout 

the facility are reviewed in Section 15 of the BACT report. Fugitive sources 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 also contains a list of sources 

covered by the fugitive dust BACT analysis. 
Minnesota Steel Page - 105 Pelletizer 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc

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 represent best practices and are consistent with dust control techniques used by other mining 

facilities in the area. 
Minnesota Steel Page - 106 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.0 Direct Reduced Iron Plant 

8.1 Direct Reduced Iron Plant Overview 

8.1.1 Direct Reduced Iron (DRI) Plant 

The direct reduced iron (DRI) 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 reducing gas in the process gas heater. 

In the reduction furnace, iron oxide (primarily hematite, with the chemical composition of Fe2O3) 

reacts with carbon monoxide (CO) and hydrogen (H2) contained in a reducing gas to produce metallic 

iron (Fe) while liberating carbon dioxide (CO2) and water vapor (H2O). The overall reduction 

reactions are: 

Fe2O3 + 3 H2 Æ 2 Fe + 3 H2O 

Fe2O3 + 3 CO Æ 2 Fe + 3 CO2

The second major reaction system within the direct reduction process is the reforming of methane to 

produce the reducing gas. These reactions take place in the DRI process heater and continue in the 

DRI reactor. In the DRI reactor, iron acts as a catalyst for methane reforming reactions. Natural gas 

(CH4), the primary source of energy and reactant for the process, is converted (reformed) to produce 

a reducing gas rich in CO and H2. The important reforming reactions are: 

CH4 + 1⁄2 O2 Æ CO + 2 H2

CH4 + H2O Æ CO + 3 H2 

CO + H2O Æ H2 + CO2
Minnesota Steel Page - 107 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

The iron reduction process is as follows. 

Under normal DRI plant operations, oxide pellets are transferred 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 DRI loading bin, which feeds 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 gas, which converts iron oxide 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 increases the carbon content of the product. The hot metallic iron also acts as a 

catalyst in promoting reforming reactions to convert the natural gas to H2 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 Transport System (PTS). The 

pneumatic transfer gas is a mixture of nitrogen 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 pellets hot as they are pneumatically transported. 

The DRI feed hopper system for the EAF has two depressurization steps. Transfer 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 cleaning, 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 interface bin. Transfer gas vented from 

the interface bin is primarily nitrogen. Gas leaving the interface bin is passed through a quench 

orifice and venturi for cooling and particulate removal. A quench system in the base of the PTS 
Minnesota Steel Page - 108 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

depressurization stack allows for separation 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 cool 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 injected 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 from the cooling gas in the cooling gas separator. 

Additional cooling gas cleaning occurs in the cooling 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 cooled 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 the top gas. Next, natural gas is added to the 

purified top gas to replenish the reducing gases consumed by the DRI process. This step is followed 

by humidification, which aids the reforming process, and controls the carbon 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 H2. 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 CO2 also removes Hydrogen Sulfide (H2S) from the 

top gas. Small amounts of H2S 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 
Minnesota Steel Page - 109 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

erosion by high-heat conditions. An amine scrubbing solution is used for CO2 and H2S removal. 

Amines are organic chemicals which include nitrogen, in a chemical form similar to ammonia, 

bonded to a carbon atom. Amine solutions are commonly used in natural gas processing to remove 

CO2 and H2S. In the absorber tower, amines react with CO2 and H2S 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 droplets and returned to the DRI process gas heater. 

The saturated amine is regenerated in the Top Gas Purification stripper tower. Steam heat is used to 

break the amine-CO2 and amine-H2S bonds. Steam is provided by a natural gas fired package boiler. 

Once regenerated, the amine solution is recycled back to the Top Gas Purification absorber. CO2 and 

H2S 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 scrubber stacks (particulate emissions), which control emissions from both 

mechanical (conveyor) and pneumatic transfers 

• Cooling towers (particulate emissions and CO2/CO blowdown vent) 

• Fugitive air emission sources in the DRI plant include particulate released from handling of 

oxide pellets, DRI product, and remet (off spec pellets to be reprocessed). 

• Emergency diesel engines 

• Emergency flare stacks (combustion emissions). 

Emergency diesel engines are addressed 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 upsets. Its use is consistent with good air pollution control practice 

for minimizing emissions. The flare is not a source of emissions during normal operations, except 

for an insignificant amount of combustion related emissions associated with the operation of the flare 

pilot light. 
Minnesota Steel Page - 110 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.2 DRI Package Boiler 

A natural gas fired package-boiler will provide steam 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 pollutants emitted from the package boilers include: PM, PM10, SO2, 

NOx, CO, VOC. All emissions result from combustion of natural gas. 

8.3 DRI Boiler Particulate MatterPM/PM10 Emission 

Particulate emissions from natural gas combustion are typically low. Particulate matter is generated 

during incomplete combustion. Because the boilers burn natural gas all particulates are assumed to 

be PM10. Uncontrolled PTS Gas Heater emissions were determined using AP-42 emission factors 

(0.0075lb/MMBtu) which are equivalent to a particulate concentration of 0.005 gr/dscf. 

8.3.1 Identification of Potential PM/PM10 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 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 Technically Infeasible PM/PM10 Control Options 

Table 8-1 summarizes the technical feasibility of each particulate control technology on the DRI 

Boilers. At particulate concentrations of 0.005 gr/dscf, use of add-on controls for gas fired 

combustion sources is technically infeasible because this particulate concentration level is at the 

limits of PM emissions control technology. In addition, particulates from natural gas combustion are 

primarily condensable particulates. Condensable PM is not readily removed by these control 
Minnesota Steel Page - 111 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

devices. The particulate concentration of 0.005 gr/dscf was calculated using the AP-42, 5th 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. 

Table 8-1 Technical Feasibility of PM/PM10 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 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 

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 
Minnesota Steel Page - 112 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.3.3 Rank Remaining PM/PM10 Control Technologies by Control 

Effectiveness 

The only remaining control technology for control of PM emission from the DRI boilers is good 

burner design and operating practices. 

Table 8-2 Ranking of Remaining PM/PM10 Control Technologies for DRI Boilers 

PM / PM10 Control Technology Ranking 

Rank Technology % Efficiency 

1 Good Burner Design and 

Operating Practices 

Clean Fuels 

NA 

Base Case 

8.3.4 Evaluation of Most Effective PM Control Technologies 

Since good burner design and operating practices is inherent to the process no additional cost will be 

incurred. 

Table 8-3 Evaluation of Most Effective PM/PM10 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/PM10 BACT Selection 

Good Burner Design and Operating Practices and clean fuels are selected as BACT. 

The proposed BACT PM/PM10 limit for the DRI boilers is 0.0075 lb PM/PM10/MMBtu, good 

combustion practices and use of natural gas. Use of natural gas, a clean fuel, limits potential 

emissions of particulates. The proposed PM/PM10 mass emission limit is 0.7 lbs of PM/PM10 per 

hour on a 24 hour average basis. The proposed limit is based on compliance testing for PM by EPA 

Method 5, and PM10 measured by EPA Methods 201 (or 201A) and 202 (or EPA approved modified 

Method 202 procedures). The mass emission limit is based on operation with BACT controls and the 

facility running at full capacity. 
Minnesota Steel Page - 113 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Attachment L, Tables L-38A and 38B contain a summaries of BACT PM and PM10 determinations 

from the EPA RBLC database for natural gas-fired boilers 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/PM10/MMBtu is consistent with AP-42 and less 

than the median BACT PM/PM10 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 consistent with recent RBLC BACT determinations. 

RBLC PM10 BACT Limits Summary 

BACT-PSD PM10 lb/MMBtu Emission Limits Other (non-BACT) PM10

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/MMBtu

Count

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 
Minnesota Steel Page - 114 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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/MMBtu

Count

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 special permit conditions for startup and shutdown. 

8.4 DRI Package Boiler Visible Emissions 

Visible emissions are the result of incomplete combustion of fuels in the DRI Package Boilers. 

8.4.1 DRI Package Boiler 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/PM10 BACT. 

In the DRI Package Boilers, PM/PM10 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 opacity limit of 3% is consistent with recent RBLC 

determinations for gas fired heaters as shown in the table below. 
Minnesota Steel Page - 115 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Sulfur Dioxide (SO2) emission 

SO2 emissions from natural gas combustion are typically low. Based on use of natural gas as the fuel 

for the DRI boilers, the expected SO2 concentration in the boiler flue gas is expected to be 1 ppm 

SO2. 

8.5.1 Identification of Potential SO2 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 SO2 control technologies are discussed in 

Section 4.0 and Table 9-31. Potential control technologies for SO2 emissions are the following: 

• Wet Scrubber 

• Spray Dryer Absorption 

• Wet Electrostatic Precipitator 

• Dry Sorbent Injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design Methods and Operating Practices 

8.5.2 Elimination of Technically Infeasible SO2 Control Options 

At less than 1 ppm SO2 in the DRI 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. 
Minnesota Steel Page - 116 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-4 Technical Feasibility of SO2 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 SO2 Control Technologies by Control 

Effectiveness 

The remaining control technology for control of SO2 from the DRI boilers is the use of clean fuel and 

good combustion practices. 

Table 8-5 Ranking of Remaining SO2 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 
Minnesota Steel Page - 117 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.5.4 Evaluation of Most Effective SO2 Control Technologies 

Since the use of clean fuel and good combustion practices is an inherent part of the process no 

additional cost will be incurred. 

Table 8-6 Evaluation of Most Effective SO2 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 SO2 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 SO2 emissions to the rated heat input 

capacity of the boilers. 

Minnesota Steel Industries proposed SO2 mass emission limit is 0.1 lbs of SO2 per hour on a 3 hour 

average basis. The proposed limit is based on compliance testing for SO2 by EPA Method 6C, 

determination of SO2 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 SO2 determinations from the EPA RBLC 

database for natural gas-fired boilers 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 SO2/hr is equivalent to 0.0006 lb SO2/MMBtu, and is consistent with AP-42 and the lowest 

BACT SO2 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 and use of natural gas 

with a limit of 0.1 lb SO2/hr as BACT is consistent with recent RBLC BACT determinations. 

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 
Minnesota Steel Page - 118 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Since Minnesota Steel will fire only natural gas in the DRI Boilers, no special permit conditions are 

required to control SO2 emissions during startup and shutdown. 

8.6 DRI Boiler Nitrogen Oxides (NOx) Emissions 

Combustion of gaseous fuels, natural gas and process tail gas, is the primary source of NOx emissions 

from the DRI boilers. NOx emissions from the DRI boilers are primarily thermal NOx. Low NOx

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 emission 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 NOx

emission factor for small boilers is equivalent to 0.05 lb/MMBtu. A burner rating of 0.08 lb 

NOx/MMBtu equates to a NOx 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 DRI boilers NOx emissions are the following: 

• Low Temperature Oxidation 

• Selective Catalytic Reduction 

• Selective Non-Catalytic Reduction 

• Non-selective Catalytic Reduction 

• Ultra Low NOx 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 Technically Infeasible NOx Control Options 

Table 8-7 summarizes the feasibility of potential NOx control technologies for emissions from the 

DRI boilers. Details regarding the technologies that are infeasible are discussed in the subsequent 

sections. 
Minnesota Steel Page - 119 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-7 Technical Feasibility of NOx Control Technologies for the DRI Boilers 

NOx Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Low Temperature Oxidation 

Low Temperature Oxidation is a process where 

NOx 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 NOx control technology in which 

ammonia (NH3) 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 N2 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. NOx and CO react in the 

presence of NSCR catalyst to form nitrogen (N2) 

and carbon dioxide (CO2). It is typically 

employed in clean gas services such as natural 

gas fired turbines. 

No 

Ultra Low NOx Burners or 

Low NOx 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 NOx 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 NOx. 

Yes 

Incorporated 

via the ULNB / 

LNB-EFR 

analysis 

Low-NOx Burners 

Low-NOx burner (LNB) technology utilizes 

advanced burner design to reduce NOx formation 

through the restriction of oxygen, flame 

temperature, and/or residence time. 

Yes 

(Base Case) 
Minnesota Steel Page - 120 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

NOx 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 NOx

formation. 

Yes 

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), 

Burners Out of Service (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 applications. 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 appropriate for large industrial and utility boilers. 

A 100 MMBtu/hr boiler is not large enough to accommodate over fire air. Small boilers usually have 

only one burner; therefore, they do not have spare burners which can be taken out of service. New 

boiler designs can meet low NOx control requirements without the use of air preheat limitations. 

8.6.2 Ranking of Remaining NOx Control Technologies by Control 

Effectiveness 

The remaining control technologies applicable to the DRI boilers are ranked by control effectiveness 

in Table 9-35. 
Minnesota Steel Page - 121 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-8 Ranking of Remaining NOx Control Technologies for the Tunnel Furnace 

NOx Control Technology Ranking 

Rank Technology Estimated % Control 

Efficiency 

1 Selective Catalytic 

Reduction 70 %* 

2 LoTOx 70%* 

3 

Ultra Low NOx Burners or 

Low-NOx 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 equivalent to 18 ppm NOx on a dry basis 

8.6.3 Evaluation of Most Effective NOx Control Technologies 

The detailed control cost analyses are located in Attachment C 

Table 8-9 Evaluation of Most Effective NOx 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 NOx 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 
Minnesota Steel Page - 122 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

SCR, LoTOx, and SNCR are all economically infeasible as their control costs are all significantly 

above $10,000 per ton NOx removed. 

Ultra Low NOx Burners or Low NOx burners with external flue gas recirculation have the next 

highest level of control, and they are economically feasible. Low NOx burners are effective at 

controlling NOx emissions and do not require the use of reagents and catalysts. CO emissions may 

increase slightly with the use 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 NOx. 

Instead, ultra low NOx burners or low NOx burners with flue gas recirculation have been selected as 

BACT for control of NOx emissions. 

8.6.4 DRI Boiler NOx BACT Selection 

Minnesota Steel proposes ultra low NOx burners or low NOx burners with flue gas recirculation, or 

equivalent combustion controls as BACT. Minnesota Steel considers the use of ultra low NOx 

burners or low NOx 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 NOx emission limit of 0.035 lb NOx/MMBtu on a 24 hour average 

basis for the DRI boilers. The proposed NOx mass emission limit is 3.5 lbs of NOx per hour on a 24 

hour average basis. The proposed limit is based on compliance testing for NOx by EPA Method 7E, 

determination of NOx 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-40A contains a summary of BACT determinations from the EPA RBLC 

database for the natural gas-fired boilers and heater rated at 100 MMBtu/hr or less. The RBLC data 

indicates that ultra low NOx burners or low NOx burners with flue gas recirculation have been 

selected as BACT for control of NOx 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 

NOx/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. 
Minnesota Steel Page - 123 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

RBLC NOx BACT Limits Summary 

BACT-PSD NOx lb/MMBtu Emission 

Limits 

Other (non-BACT) NOx

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

0.01

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

lb NOx/MMBtu

Count

Proposed 

BACT Limit 

0.035

Periods of startup, shutdown and malfunction 

For ULNB to effectively control NOx emissions, the DRI Boilers 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. Once the process 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 “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. Good operating practices will include: 
Minnesota Steel Page - 124 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

• 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 NOx 

control by ULNB. 

• Operation of the DRI Boilers in a manner which minimizes the amount of time the heater is 

operated at excess oxygen levels higher than the operating range effective for NOx control by 

ULNB. 

Minnesota Steel will define these periods in its startup, 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 Monoxide (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 concentration in the exhaust of the DRI boilers is 0.08 

lb/MMBtu. This equates to a CO concentration of 111 ppm, which is consistent with good operation 

of low NOx burners. 

8.7.1 Identification of Potential 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 9-52. Potential control technologies 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 Control Options 

Table 9-37 summarizes the feasibility of potential control technologies for CO emissions from the 

DRI boilers. 
Minnesota Steel Page - 125 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

CO Emission Control Technologies Considered for BACT Analysis 

Technology Description Feasible? 

Yes or No 

Thermal Oxidizer 

(Recuperative and 

Regenerative) 

A thermal oxidizer uses high temperature 

and residence time to oxidize CO to CO2. 

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 
Minnesota Steel Page - 126 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.7.4 Evaluation of Most Effective CO Control 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 control costs are well over $10,000 per ton, and are economically 

infeasible. 

Since the use of good combustion controls and good burner design and operating practices are 

inherent parts of the process no additional 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 natural 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 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-41 contains a summary of BACT determinations from the EPA RBLC 

database for natural gas-fired boilers and heaters rated at 100 MMBtu/hr or less. The RBLC data 

indicates Good Combustion Practices and use of natural gas as BACT for CO control. As noted in 

the NOx control analysis, CO emissions from low and ultra low NOx burners are slightly higher than 
Minnesota Steel Page - 127 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

standard burners. Data in Table L-41 shows CO emissions from low and ultra low NOx burners in 

the 0.08 to 0.1 lb CO/MMBtu range. Therefore, specifying good combustion controls as BACT with 

a limit of 0.08 lb CO/MMBtu for ultra low NOx burners is consistent 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/MMBtu

Count

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 special permit conditions for startup and shutdown. 

8.8 DRI Boiler Volatile Organic 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. 
Minnesota Steel Page - 128 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.8.1 Identification of Potential 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 9-40. Potential control technologies 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 control technologies for control of VOC emissions 

from the DRI boilers. At 13 ppm VOC in the DRI boiler 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 uses high temperature 

and residence time to oxidize VOC to water 

and CO2. 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 
Minnesota Steel Page - 129 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Thermal and catalytic oxidation control devices are considered technically 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. See 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 Effective VOC Control Technologies 

Since the use of good combustion controls and good burner design and operating practices are 

inherent parts of the process no additional cost will be incurred. 

Table 8-15 Evaluation of Most Effective VOC 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 natural gas, a clean fuel, in combination with good 

combustion practices limits potential VOC emissions from the boilers. 
Minnesota Steel Page - 130 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Minnesota Steel proposes a BACT VOC emission limit of 0.006 lb VOC/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. 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 boilers and heaters rated at 100 MMBtu/hr or less. The RBLC data 

indicates Good Combustion Practices 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/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/MMBtu

Count

Proposed BACT 

Limit 0.006
Minnesota Steel Page - 131 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 special permit conditions for startup and shutdown. 

8.9 DRI Process Heaters 

The DRI Process Heater is used heat DRI top gas for 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 use 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, SO2, NOx, 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 Particulate Matter (PM/PM10) Emissions 

8.10.1 Identification of Potential PM/PM10 Control Technologies 

The DRI vendor’s value for particulates emitted in the process heater’s exhaust gas is 0.01 gr/dscf. 

Based on the duty and design stack flow of process heaters, this equates to 0.015 lb 

PM/PM10/MMBtu. Add-on controls will be evaluated using this as the control device inlet 

concentration basis. At these low levels of particulate loading, add-on controls are typically not 

economically feasible. 

The DRI Process Heater exhaust 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 various PM control technologies are discussed in 

Section 4.0, and Table 8-16. Potential control technologies for DRI Process Heater particulate 

emissions are the following: 

• Fabric filter 

• Wet scrubber 

• Electrostatic precipitator 

• Wet Electrostatic Precipitator 
Minnesota Steel Page - 132 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

• Centrifugal Separation (e.g. Cyclones) 

• Inertial separators (drop out box) 

• Good design methods and operating practices 

8.10.2 Elimination of Technically Infeasible PM/PM10 Control Options 

Table 8-16 lists the particulate control technologies and their feasibility 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 sources whose exhaust is composed primarily of 

condensable particulate matter. Condensable PM is not readily removed by these control devices. 

Fabric filters and wet scrubbers are also infeasible in this application due to low particulate 

concentrations in the DRI process heater exhaust. 
Minnesota Steel Page - 133 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-16 Technical Feasibility of PM Control 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 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 

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 
Minnesota Steel Page - 134 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.10.3 Ranking of Remaining PM/PM10 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 scrubbing control technologies. 

Table 8-17 Remaining PM/PM10 Control Technologies and Control Effectiveness for the DRI 

Process Heaters 

PM / PM10 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 reductions, capital and annual operating costs, and the 

corresponding cost per ton of particulate 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/PM10 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 202 or EPA approved modified Method 202 procedures 
Minnesota Steel Page - 135 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.10.5 DRI Process Heater PM/PM10 BACT Selection 

Use of inherent controls, clean fuels and good combustion practices are recommended 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 inherent part of the process. At over $45,000 per ton 

of PM removed, add-on controls following the internal particulate scrubber are economically 

infeasible. 

The proposed BACT PM/PM10 limit for the DRI Process Heaters is 0.015 lb PM/PM10/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 gas is derived from natural gas, and is scrubbed prior 

to combustion to prevent DRI particulates from being emitted. The proposed PM/PM10 mass emission 

limit is 8.8 lbs of PM/PM10 per hour on a 24 hour average basis. The proposed limit is based on 

compliance testing for PM by EPA Method 5, and PM10 measured by EPA Methods 201 (or 201A) 

and 202 (or EPA approved modified Method 202 procedures). 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. Therefore, 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 limit for material handling sources. i.e. the total of particulates 

from combustion and material handling. The DRI plant 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/PM10 concentration of 0.005 gr/dscf is equivalent to an 

emission rate 0.0075 lb PM/PM10/MMBtu in the DRI process heater exhaust. The proposed BACT 

for particulates emitted from the DRI Boilers and PTS heaters is 0.0075 lb PM/PM10/MMBtu. The 

proposed PM/PM10 BACT for DRI Process Heaters is 0.015 lb PM/PM10/MMBtu, the sum of these 

two limits. 

For periods of startup and shutdown, Minnesota Steel will operate plant’s inherent particulate emission 

control equipment. These controls are an integral part of the DRI process, they are used to protect process 
Minnesota Steel Page - 136 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

equipment and the DRI plant cannot operate without them. So, they will be put into service when 

commencing operation of process equipment, and will keep operating until the process is shut down. 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. 

8.11 DRI Process Heater Visible Emissions 

Visible emissions are the result of incomplete combustion of fuels in the DRI Process Heaters. 

8.11.1 DRI Process 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/PM10 BACT. 

In the DRI Process Heaters, PM/PM10 emissions are controlled by good combustion practices. 

A 3% opacity limit is recommended as BACT for visible 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 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. 

8.12 DRI Process Heater Sulfur Dioxide (SO2) Emissions 

8.12.1 Identification of Potential SO2 Control Technologies 

The evaluation of add-on controls is based on vendor data citing a process heater exhaust SO2

concentration of 1 ppm SO2 on a wet basis. This is also consistent with SO2 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 which is derived from natural gas. 
Minnesota Steel Page - 137 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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. Potential control technologies for DRI Process Heater SO2 emissions are the 

following: 

• Wet Scrubber 

• Wet Electrostatic Precipitator 

• Spray Dryer Absorption 

• Dry Sorbent Injection 

• Clean Fuel / Good Combustion Practices (Base Case) 

8.12.2 Elimination of Technically Infeasible SO2 Control Options 

At 1 ppm SO2 in the DRI Process Heater exhaust gas, all add-on controls are technically infeasible 

because 1 ppm is at or below the exhaust concentrations that can be achieved with theses controls. 
Minnesota Steel Page - 138 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-19 Technical Feasibility of SO2 Control Technologies for DRI Process Heaters 

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 either purified tail gas or natural gas Yes 

8.12.3 Ranking of Remaining SO2 Control Technologies by Control 

Effectiveness 

Since all add on control options for SO2 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 SO2 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 
Minnesota Steel Page - 139 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.12.4 Evaluation of Most Effective DRI Process Heater SO2 Control 

Technologies 

There are no additional costs associated 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 SO2 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 SO2 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 SO2 

emissions to the rated heat input capacity of the Process Heaters. 

The proposed SO2 mass emission limit is 1 lb of SO2 per hour on a 3 hour average basis. The 

proposed limit is based on compliance testing for SO2 by EPA Method 6C, determination of SO2 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 SO2 BACT limit. The BACT 

determination was for combustion of residual fuel oil, 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 SO2 determinations from the EPA RBLC 

database for natural gas-fired boilers 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 SO2/hr is equivalent to 0.0006 lb SO2/MMBtu, and is consistent with AP-42 for natural gas 

combustion, vendor’s specifications and the lowest BACT SO2 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, use of clean fuels and a mass emission limit 1 lb SO2/hr is 

consistent with recent RBLC BACT determinations. 
Minnesota Steel Page - 140 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 top gas at all times the DRI plant is operating, no 

special permit conditions are required to control SO2 emissions during startup and shutdown. 

8.13 DRI Process Heater Nitrogen Oxides (NOx) Emissions 

8.13.1 Identification of Potential NOx Control Technologies 

Combustion of gaseous fuels, process tail gas and natural gas, is the primary source of emissions 

from the DRI Process Heater exhaust. NOx emissions from the DRI Process Heaters are primarily 

thermal NOx. 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, NOx concentrations in 

the DRI Process Heater exhaust gas are estimated to be 66 ppm NOx on a dry basis. Low NOx

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. Potential control technologies for pellet plant NOx emissions are the following: 

• Low Temperature Oxidation 

• Selective Catalytic Reduction 

• Selective Non-Catalytic Reduction 

• Non-selective Catalytic Reduction 

• External Flue Gas Recirculation 

• Ultra Low NOx Burners / Low-NOx Burners and Flue Gas Recirculation (ULNB / LNB-FGR) 

• Oxyfuel Burners 

• Low Excess Air (LEA) 

• Other Combustion Controls 

• Inherently Lower Emitting DRI Process Designs 
Minnesota Steel Page - 141 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.13.2 Elimination of Technically Infeasible NOx Control Options 

Table 8-22 summarizes the technical feasibility of each of the potential NOx control technologies. 

Details regarding the technologies that are not technically feasible are discussed in the subsequent 

section. 

Table 8-22 Technical Feasibility of NOx Control Technologies for the DRI Process Heaters 

NOx Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Low Temperature Oxidation 

(LoTOx) 

Low Temperature Oxidation is a process where 

NOx 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 NOx control technology in which 

ammonia (NH3) 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 N2 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. NOx and CO react in the 

presence of NSCR catalyst to form nitrogen (N2) 

and carbon dioxide (CO2). 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 NOx. 

Yes 

Incorporated via 

the ULNB / 

LNB-EFR 

analysis 
Minnesota Steel Page - 142 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

NOx Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Ultra Low NOx Burners or 

Low-NOx Burners and Flue 

Gas Recirculation 

Low-NOx burner (LNB) technology utilizes 

advanced burner design to reduce NOx 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 NOx formation. 

Yes 

Low-NOx Burners 

Low-NOx burner (LNB) technology utilizes 

advanced burner design to reduce NOx 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 NOx

formation. 

Yes 

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), 

Burners Out of Service (BOOS) and Load 

Reduction and Reduced Combustion Air 

Temperature. 

No 

Inherently Lower Emitting 

DRI Process Designs 

Process designs which have lower NOx 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 Environmental 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 natural gas-fired combined cycle turbine using water 

injection. The performance of the system is sensitive 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 infeasible for application at the DRI Process Heaters. 
Minnesota Steel Page - 143 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Other Combustion Controls 

There are other combustion control methods typically 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 combustion controls are typically applied on utility 

boilers which have large fireboxes. Large fireboxes provide the extra space and residence time 

needed for overfire air. Overfire air would be ineffective 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 preheat is required for energy efficiency. 

8.13.3 Ranking of Remaining NOx Control Technologies by Control 

Effectiveness 

Four technologies that are technically feasible for control of NOx on the DRI Process Heaters are 

ranked in Table 8-23. 

Table 8-23 Ranking of Remaining NOx 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 NOx Burners or 

Low-NOx 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 equivalent to 18 ppm NOx on a dry basis 
Minnesota Steel Page - 144 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.13.4 Evaluation of Most Effective 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 NOx 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 NOx

Burners or LowNOx 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 NOx emissions control options are both economically infeasible 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. Application 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 and potential issues. LoTOx requires a source of oxygen in order to 

make ozone, the NOx reduction reagent for the LoTOx process. Under many circumstances oxygen 

can be expensive. In Minnesota Steel’s case, the 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 production will be relatively low compared to its use at a facility that 

would not already have oxygen generating capabilities on site. No DRI plants listed in the RBLC 

have specified LoTOx for NOx emission control. 
Minnesota Steel Page - 145 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

SCR systems can be designed to achieve the same level of NOx in the DRI Process Heater exhaust as 

LoTOx (25 ppm); therefore, SCR is also a viable NOx control option. SCR has the advantage of not 

requiring water to operate, nor does 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 NOx burners are an effective control technology which reduces NOx 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 available DRI process designs which utilize natural gas as the reductant. 

Minnesota Steel has selected the DRI process design base case which has the lowest NOx 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 NOx burners. The other design could not 

accommodate low NOx burners. 

8.13.5 DRI NOx BACT Selection 

Ultra Low NOx Burners (ULNB) are the proposed NOx 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 NOx emissions. 

Minnesota Steel proposes a BACT NOx emission limit of 0.04 lb NOx/MMBtu on a 24 hour average 

basis for the DRI Process Heaters. The proposed NOx mass emission limit is 24 lbs of NOx per hour 

on a 24 hour average basis. The proposed limit is based on compliance testing for NOx by EPA 

Method 7E, determination of NOx by instrumental methods. The mass emission limit is based on 

operation with BACT controls and the facility running at full capacity. 

While LoTOx is technically feasible, ULNB is selected 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 wet scrubber on the DRI unit 

represents a 3% to 4% increase in water consumption 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 
Minnesota Steel Page - 146 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Environmental Impact Study (EIS), water appropriation 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 incremental control cost of SCR is $65,974/ton NOx 

removed, and SCR only reduces NOx emissions 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 NOx BACT limits. The BACT 

determinations were for combustion of residual fuel oil, and are not applicable 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 with the proposed BACT limits was never verified. 

The suggested BACT NOx limit of 0.04 lb NOx/MMBtu and 24 lb/hr NOx 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 boilers 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. The RBLC data indicates that ultra 

low NOx burners or low NOx burners with flue gas recirculation have been selected as BACT for 

control of NOx 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 infeasible. Therefore, specifying ultra low NOx burners at 

0.04 lb NOx/MMBtu as BACT is consistent with recent RBLC BACT determinations. 

RBLC NOx BACT Limits Summary 

BACT-PSD NOx lb/MMBtu Emission Limits 

 

Other (non-BACT) NOx

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 
Minnesota Steel Page - 147 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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/MMBtu

Count

Proposed BACT 

Limit 0.04

Periods of startup, shutdown and malfunction

For ULNB to effectively control NOx 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 appropriate operating conditions, 

the ULNB will be able to control NOx emissions as designed. 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 “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. Good operating practices will include: 

 Operation of the DRI Process Heaters in a manner which minimizes the amount of time each 

heater is operated at temperatures and firing rates which are outside the operating range effective 

NOx control by ULNB. 

 Operation of the DRI Process Heaters in a manner which minimizes the amount of time each 

heater is operated at excess oxygen levels higher than the operating range effective for NOx

control by ULNB. 
Minnesota Steel Page - 148 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Minnesota Steel will define these periods in its startup, 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 Potential CO Control Technologies 

Combustion of gaseous fuels (process tail gas and natural 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 gas and/or natural gas. Based on AP-42 emission factors, the estimated 

CO concentration in the exhaust of the DRI boilers 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. Potential 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 Technically Infeasible CO Control Options 

All CO control technologies are considered technically feasible. 

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

CO Emission Control Technologies Considered for BACT Analysis 

Technology Description Feasible? 

Yes or No 

Thermal Oxidizer 

(Recuperative and 

Regenerative) 

A thermal oxidizer uses high temperature 

and residence time to oxidize CO to CO2. 

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 
Minnesota Steel Page - 149 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

CO Emission Control Technologies 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 Reforming Heater exhaust gas is 111 ppm CO. This is 

very good performance for a low NOx 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 Effective 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 process already inherently controls CO emissions, the 

potential for CO emission reductions by add on controls is relatively small. Based on the economic 

analysis, add-on CO controls are economically infeasible. 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. 
Minnesota Steel Page - 150 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 (natural gas and process tail gas), Good Combustion 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 per 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, ethane 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 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 boilers 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 Practices and use of natural gas as BACT 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 
Minnesota Steel Page - 151 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

in the 0.08 to 0.1 lb CO/MMBtu range. Therefore, specifying good combustion controls as BACT 

with a limit of 0.08 lb CO/MMBtu for ultra low NOx burners is consistent 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/MMBtu

Count

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 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. 
Minnesota Steel Page - 152 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.15 DRI Process Heater Volatile Organic Compound (VOC) 

Emissions 

8.15.1 Identification of Potential VOC Control Technologies 

Combustion of gaseous fuels (process tail gas and natural 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 calculated 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 Technically Infeasible VOC Control Options 

As noted above, VOC concentration in the DRI Process 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. 
Minnesota Steel Page - 153 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-28 Technical Feasibility of VOC Control 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 uses high temperature 

and residence time to oxidize VOC to water 

and CO2. 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 combustion 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 Effective VOC Control Technologies 

Because good combustion controls is an inherent part of the process there are no additional costs for 

this control technology. 
Minnesota Steel Page - 154 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 limit 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 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. 

There were no BACT determinations listed in the RBLC for VOC 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-42 contains a summary of BACT determinations from the EPA RBLC 

database for natural gas-fired boilers 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 Practices 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/MMBtu. Therefore, specifying good 

combustion controls as BACT with a limit of 0.006 lb VOC/MMBtu is consistent with recent RBLC 

BACT determinations. 
Minnesota Steel Page - 155 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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/MMBtu

Count

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 special permit conditions for startup and shutdown. 

8.16 DRI Process Heater Fluoride (F) Emissions 

8.16.1 Identification of Potential Fluoride Control Technologies 

Fluoride compounds may be emitted in trace quantities from the DRI Process Heaters as the result of 

trace amounts of fluoride in the taconite ore pellets and the natural gas 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 based 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 
Minnesota Steel Page - 156 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

the DRI gas scrubber systems provide. The evaluation of add-on controls will be based on a DRI 

Process Heater exhaust fluoride concentration 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. Potential control technologies for pellet plant fluoride emissions are the following: 

• Wet Scrubber 

• Wet Electrostatic Precipitator 

• Spray Dryer Absorption 

• Dry Sorbent Injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design Methods and Operating Practices (Base Case) 

8.16.2 Elimination of Technically Infeasible Fluoride Control Options 

At < 1 ppb, fluoride in the DRI Process Heater exhaust gas, all add-on controls are technically 

infeasible because 5.0 e-7 gr/dscf is at or below the exhaust concentrations that can be achieved with 

theses controls. 
Minnesota Steel Page - 157 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

Fluoride Emission Control Technologies 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 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 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 Fluoride 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 
Minnesota Steel Page - 158 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.16.4 Evaluation of Most Effective Fluoride Control 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 million 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 fluoride compounds. As discussed in 8.1 the DRI process 

includes a top gas scrubber as part of the process 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 performance testing and measurement of fluorides in the raw materials 

feeding the DRI plant. The averaging period for fluoride emissions is 3 hours (three 1-hour test 

runs). 

Attachment L, Table L-2 contains a summary of BACT determinations for DRI operations from the 

EPA RBLC database. Fluoride emission controls are not included 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 required to control F- emissions during startup and 

shutdown. 
Minnesota Steel Page - 159 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.17 DRI Process Heater Lead (Pb) Emissions 

8.17.1 Identification of Potential 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. Emissions are primarily due to the attrition 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 DRI 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 discussed 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 will be based on a Process Heater exhaust lead 

concentration of 3.6 e-7 gr/dscf. This concentration 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 various PM control technologies are discussed in 

Section 4.0, and Table 8-16. Potential 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 Technically Infeasible Pb Control Options 

Table 8-16 lists the lead bearing particulate control technologies and their feasibility for control 

emissions from the DRI Process Heater. 
Minnesota Steel Page - 160 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 the exhaust concentrations that can be achieved with 

theses controls. 

Table 8-34 Technical Feasibility of Pb Control 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 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. 

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 
Minnesota Steel Page - 161 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.17.3 Ranking of Remaining Pb Control Technologies by Control 

Effectiveness 

The only remaining emission control technology for 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 additional emission control costs 

will be incurred. 

Table 8-36 Evaluation of Most Effective Pb Control 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% control efficiency was calculated as an example. The 

example calculation yields control costs of $655 million 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 
Minnesota Steel Page - 162 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 particulate 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 occur 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 (CO2) 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 H2). The DRI Top Gas Purification system is 

designed to purify the reducing gas by removing the CO2. This is accomplished by using an amine 

based sorption/desorption system. CO2 captured in the CO2 absorber is then vented to the 

atmosphere in the amine stripper (desorption). 

Another byproduct of the DRI process is hydrogen sulfide (H2S). Sulfur compounds in the DRI 

reactor are converted to H2S by the reducing gas. The source of sulfur 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 H2S as well as CO2. H2S is then vented along with the CO2 in the 

exhaust from the CO2 stripper. 
Minnesota Steel Page - 163 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.19 DRI Top Gas Purification Hydrogen Sulfide (H2S) Emissions 

8.19.1 Identification of Potential H2S 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. Potential control technologies for pellet plant 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 Technically Infeasible H2S Control Options 

With the exception of catalytic oxidation, all H2S control systems are technically feasible as shown in 

Table 8-37. 
Minnesota Steel Page - 164 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-37 Technical Feasibility of H2S Control Technologies for DRI Top Gas Purification 

SO2 Emission Control Technology 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 H2S. 

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 uses high temperature 

and residence time to oxidize H2S to water 

and SO2. 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 uses high temperature 

and residence time to oxidize VOC to water 

and CO2. 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 SO2 generated by the oxidation of H2S 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 SO2 and removes it 

Yes 

Catalytic oxidation is not technically feasible because H2S is a poison for oxidation catalyst. 

8.19.3 Ranking of Remaining H2S Control Technologies by Control 

Effectiveness 

The control technology rankings for technically feasible H2S control are listed below in Table 8-38. 
Minnesota Steel Page - 165 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-38 Remaining H2SControl 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 SO2 emitted 

* A 92.3% control efficiency is equivalent to 5 ppm H2S on a wet basis in the Top Gas 

Purification exhaust 

8.19.4 Evaluation of Most Effective H2S Control Technologies 

The effectiveness of H2S 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 H2S 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 H2S removed, all H2S control technologies are economically 

infeasible. 

8.19.5 DRI Top Gas Purification H2S BACT Selection 

Based on excessive costs, no add on controls are recommended as BACT for H2S control from the 

Top Gas Purification System. The proposed BACT emission limit is 8.2 lb H2S/hr on a 3-hour 
Minnesota Steel Page - 166 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

average basis. Compliance will be demonstrated by performance testing using EPA Method 11. 

Ongoing compliance will be monitoring the addition rate of dimethyl-disulfide to the process. 

No BACT performance standard is recommended because H2S 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 RBLC does not contain any H2S BACT limits. 

Minnesota Steel does not require special permit conditions for control of H2S emissions during 

startup and shutdown. 

8.20 Pneumatic Transport System (PTS) Gas Heaters 

The DRI plant is equipped with a pneumatic system 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 the transport purge bin contains particulates, and must be scrubbed 

before being compressed for the next transfer cycle. Wet scrubbing is used to remove theses 

particulates. However, wet scrubbing cools off the transfer gas In order 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, SO2, NOx, CO, VOC. All emissions result from combustion of natural gas and 

process gas. 

8.21 PTS Gas Heater Particulate MatterPM/PM10 Emission 

Particulate emissions from natural gas combustion are typically low. Particulate matter is generated 

during incomplete combustion. All particulates are assumed to be PM10. Uncontrolled PTS Gas 

Heater emissions were determined using AP-42 emission factors (0.0075lb/MMBtu) which equates to 

a particulate concentration of 0.005 gr/dscf. 

8.21.1 Identification of Potential PM/PM10 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 are discussed in 
Minnesota Steel Page - 167 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Technically Infeasible PM/PM10 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/PM10 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 
Minnesota Steel Page - 168 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 particulate concentration level is at the limits of PM 

emissions control technology. In addition, particulates from natural gas combustion are primarily 

condensable particulates. Condensable PM is not readily removed by these control devices. The 

particulate concentration of 0.005 gr/dscf was calculated using the AP-42, 5th 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. 
Minnesota Steel Page - 169 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-41 Ranking of Remaining PM/PM10 Control Technologies for PTS Gas Heaters 

PM / PM10 Control Technology Ranking 

Rank Technology % Efficiency 

1 Good Burner Design and 

Operating Practices 

NA 

Base Case 

8.21.3 Evaluation of Most Effective PM Control Technologies 

Since good burner design and operating practices are inherent 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/PM10 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/PM10 BACT Selection 

Good Burner Design and Operating Practices are selected as BACT for control of particulates from 

the PTS Gas Heater. 

The proposed BACT PM/PM10 limit for the PTS Heaters is 0.0075 lb PM/PM10/MMBtu, good 

combustion practices and use of natural gas. Use of natural gas, a clean fuel, limits potential 

emissions of particulates. The proposed PM/PM10 mass emission limit is 0.09 lbs of PM/PM10 per 

hour on a 24 hour average basis. The proposed limit is based on compliance testing for PM by EPA 

Method 5, and PM10 measured by EPA Methods 201 (or 201A) and 202 (or EPA approved modified 

Method 202 procedures). The mass emission limit is based on operation with BACT controls and the 

facility running at full capacity. 

Attachment L, Tables L-38A and 38B contain a summaries of BACT PM and PM10 determinations 

from the EPA RBLC database for natural gas-fired boilers 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/PM10/MMBtu is consistent with AP-42 and less 
Minnesota Steel Page - 170 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

than the median BACT PM/PM10 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 consistent with recent RBLC BACT determinations. 

RBLC PM10 BACT Limits Summary 

BACT-PSD PM10 lb/MMBtu Emission 

Limits 

Other (non-BACT) PM10 

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/MMBtu

Count

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 
Minnesota Steel Page - 171 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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/MMBtu

Count

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 from 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/PM10 BACT. 

In the DRI PTS Heaters, PM/PM10 emissions are controlled by good combustion practices. 

A 3% opacity limit is recommended as BACT for visible emissions from the DRI PTS Heaters. i.e. the 

average opacity of a heater cannot exceed 3% for 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. 
Minnesota Steel Page - 172 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 (SO2) emissions 

SO2 emissions from natural gas combustion are typically low. Based on use of natural gas as the fuel 

for the vacuum degasser boiler, the expected SO2 concentration in the boiler flue gas are expected to 

be less than 1 ppm SO2. 

8.23.1 Identification of Potential SO2 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 SO2 control technologies are discussed in 

Section 4.0 and Table 9-31. Potential control technologies for SO2 emissions are the following: 

• Wet Scrubber 

• Spray Dryer Absorption 

• Wet Electrostatic Precipitator 

• Dry Sorbent Injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design Methods and Operating Practices 

8.23.2 Elimination of Technically Infeasible SO2 Control Options 

At less than 1 ppm SO2 in the PTS Gas Heater 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. 
Minnesota Steel Page - 173 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-43 Technical Feasibility of SO2 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 SO2 Control Technologies by Control 

Effectiveness 

The remaining control technology for control of SO2 from the PTS Gas Heaters is the use of clean 

fuel and good combustion practices. 

Table 8-44 Ranking of Remaining SO2 Control Technologies for the PTS Gas Heaters 

SO2 Control Technology Ranking 

Rank Technology Estimated Control 

Efficiency

1 

Clean Fuel/ Good 

Combustion Practices 

(Base Case) 

NA 

 Inherent to the process 
Minnesota Steel Page - 174 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.23.4 Evaluation of Most Effective SO2 Control Technologies 

Since the use of clean fuel and good combustion practices are an inherent part of the process, no 

additional cost will be incurred. 

Table 8-45 Evaluation of Most Effective SO2 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 

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 SO2 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 SO2 emissions to the rated heat input 

capacity of the boilers. 

The proposed SO2 mass emission limit is 0.024 lbs of SO2 per hour on a 3 hour average basis. The 

proposed limit is based on compliance testing for SO2 by EPA Method 6C, determination of SO2 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 SO2 determinations from the EPA RBLC 

database for natural gas-fired boilers 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 SO2/hr is equivalent to 0.0006 lb SO2/MMBtu, and is consistent with AP-42 and the lowest 

BACT SO2 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 and use of natural gas 

with a limit of 0.024 lb SO2/hr as BACT is consistent with recent RBLC BACT determinations. 
Minnesota Steel Page - 175 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 times the DRI Boilers are operating, no special permit 

conditions are required to control SO2 emissions during startup and shutdown. 

8.24 PTS Gas Heater Nitrogen Oxides (NOx) Emissions 

Combustion of natural gas is the primary source of emissions from the PTS Gas Heaters. NOx

emissions from the PTS Gas Heaters are primarily thermal NOx. Low NOx 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 conservatively high emission rate assumption for LNBs 

relative to the AP-42 NOx emission factor for small boilers, which is equivalent to 0.05 lb/MMBtu. 

A burner rating of 0.08 lb NOx/MMBtu equates to a NOx 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 NOx emissions are the following: 

• Low Temperature Oxidation 

• Selective Catalytic Reduction 

• Selective Non-Catalytic Reduction 

• Non-selective Catalytic Reduction 

• Ultra Low NOx 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 
Minnesota Steel Page - 176 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.24.1 Elimination of Technically Infeasible NOx Control Options 

Table 9-34 summarizes the feasibility of potential NOx control technologies for emissions from the 

PTS Gas Heaters. Details regarding the technologies that are infeasible are discussed in the 

subsequent sections. 

Table 8-46 Technical Feasibility of NOx Control Technologies for the PTS Heater 

NOx Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Low Temperature Oxidation 

Low Temperature Oxidation is a process where 

NOx 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 NOx control technology in which 

ammonia (NH3) 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 N2 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. NOx and CO react in the 

presence of NSCR catalyst to form nitrogen (N2) 

and carbon dioxide (CO2). It is typically 

employed in clean gas services such as natural 

gas fired turbines. 

No 

Ultra Low NOx Burners or 

Low-NOx 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 NOx 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 
Minnesota Steel Page - 177 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

NOx 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 NOx. 

analysis 

Low-NOx Burners 

Low-NOx burner (LNB) technology utilizes 

advanced burner design to reduce NOx 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 NOx

formation. 

Yes 

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), 

Burners Out of Service (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 applications. In addition, the same level of emission control 

can be achieved with SCR or LoTOx. 

 Other Combustion Controls 

Overfire air and burners out of service are appropriate for large industrial 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 meet low NOx control requirements 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. 
Minnesota Steel Page - 178 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-47 Ranking of Remaining NOx Control Technologies for the PTS Gas Heaters 

NOx Control Technology Ranking 

Rank Technology 

Estimated % Control 

Efficiency 

1 Selective Catalytic 

Reduction 

70 % * 

2 LoTOx 70% * 

3 

Ultra Low NOx Burners or 

Low-NOx 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 equivalent to 18 ppm NOx on a dry basis 

8.24.3 Evaluation of Most Effective NOx Control Technologies 

The detailed control cost analyses are located in Attachment F. 

Table 8-48 Evaluation of Most Effective NOx 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 
Minnesota Steel Page - 179 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

SCR, LoTOx, and SNCR are all economically infeasible as their control costs are all above $10,000 

per ton NOx removed. 

Ultra Low NOx Burners, or Low NOx burners with external flue gas recirculation is the next highest 

level of control. 

An analysis of the RBLC indicates that small gas fired heaters, similar to the PTS Gas Heaters, listed 

in Attachment L Table L-40A do not have add-on devices to control NOx. Only two of ninety seven 

BACT entries had add-on controls for NOx. Instead, low NOx burners or low NOx burners with flue 

gas recirculation have been predominately selected as BACT for control of NOx emissions. 

8.24.4 PTS Gas Heater NOx BACT Selection 

Minnesota Steel proposes ultra low NOx burners or low NOx burners with flue gas recirculation, or 

equivalent combustion controls as BACT. Minnesota Steel considers the use of ultra low NOx 

burners or low NOx 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 NOx emission limit of 0.035 lb NOx/MMBtu. The proposed NOx

mass emission limit is 0.4 lbs of NOx per hour on a 24 hour average basis. The proposed limit is 

based on compliance testing for NOx by EPA Method 7E, determination of NOx 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-40A contains a summary of BACT determinations from the EPA RBLC 

database for the natural gas-fired boilers and heater rated at 100 MMBtu/hr or less. The RBLC data 

indicates that ultra low NOx burners or low NOx burners with flue gas recirculation have been 

selected as BACT for control of NOx emissions from gas fired boilers and heaters. Statistical 

analyses of the RBLC data are summarized in the table and bar graph below. The proposed BACT 

limit of 0.035 lb NOx/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. 
Minnesota Steel Page - 180 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

RBLC NOx BACT Limits Summary 

BACT-PSD NOx lb/MMBtu Emission 

Limits 

Other (non-BACT) NOx

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

0.01

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

lb NOx/MMBtu

Count

Proposed 

BACT Limit 

0.0035

Periods of startup, shutdown and malfunction 

For ULNB to effectively control NOx emissions, the PTS 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. 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 “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. Good operating practices will include: 
Minnesota Steel Page - 181 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

• 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 NOx

control by ULNB. 

• Operation of the PTS heaters in a manner which minimizes the amount of time the heater is 

operated at excess oxygen levels higher than the operating range effective for NOx control by 

ULNB. 

Minnesota Steel will define good operating practices for minimizing emissions in its startup, 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. 

8.25 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 estimated 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 NOx burners. 

8.25.1 Identification of Potential 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 9-52. Potential control technologies 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 Control Options 

Table 8-49 summarizes the feasibility of potential control technologies for CO emissions from the 

PTS Gas Heater. 
Minnesota Steel Page - 182 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

CO Emission Control Technologies Considered for BACT Analysis 

Technology Description Feasible? 

Yes or No 

Thermal Oxidizer 

(Recuperative and 

Regenerative) 

A thermal oxidizer uses high temperature 

and residence time to oxidize CO to CO2. 

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 
Minnesota Steel Page - 183 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.25.4 Evaluation of Most Effective CO Control 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 economically infeasible. 

Since the use of good combustion controls and good burner design and operating practices are 

inherent parts of the process no additional 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 natural 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 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-41 contains a summary of BACT determinations from the EPA RBLC 

database for natural gas-fired boilers and heaters rated at 100 MMBtu/hr or less. The RBLC data 

indicates Good Combustion Practices and use of natural gas as BACT for CO control. As noted in 
Minnesota Steel Page - 184 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 in 

the 0.08 to 0.1 lb CO/MMBtu range. Therefore, specifying good combustion controls as BACT with 

a limit of 0.08 lb CO/MMBtu for ultra low NOx burners is consistent 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/MMBtu

Count

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 Organic 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 concentration in the uncontrolled flue gases of the PTS 

Gas Heater is .0054 lb/MMBTU. This equates to a VOC concentration of 13 ppm. 
Minnesota Steel Page - 185 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

8.26.1 Identification of Potential 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 9-40. Potential control technologies 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 control 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 exhaust concentrations that can be 

achieved with theses controls. 

Table 8-52 Technical Feasibility of VOC Control 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 uses high temperature 

and residence time to oxidize VOC to water 

and CO2. 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 
Minnesota Steel Page - 186 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Thermal and catalytic oxidation with add on control devices is considered 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 calculations 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 Effective VOC Control Technologies 

Since the use of good combustion controls and good burner design and operating practices are 

inherent parts of the process no additional 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 heaters. Use of natural gas, a clean fuel, in combination with good 

combustion practices limits potential VOC emissions from the boilers. 
Minnesota Steel Page - 187 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Minnesota Steel proposes a BACT VOC emission 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 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 boilers and heaters rated at 100 MMBtu/hr or less. The RBLC data 

indicates Good Combustion Practices 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/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/MMBtu

Count

Proposed BACT 

Limit 0.006
Minnesota Steel Page - 188 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 and process humidifier. QCW is circulated through a cooling 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 CO2 are absorbed by the cooling 

water. The blowdown vents provide place for the cooling water to release dissolved 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 from the DRI process operating pressure. The flow 

rate and pressure fluctuations of the lock hoppers, cause the CO and CO2 concentrations in the 

cooling water to fluctuate too. This, in turn, causes fluctuations in the flow rate and concentrations of 

CO and CO2 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 pellets begin the reduction 

process 
Minnesota Steel Page - 189 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 technologies for CO emissions are the following: 

• Add on controls (e.g. flares, thermal and catalytic oxidizers) 

• Good Design Methods and Operating Practices 

8.27.4 Elimination of Technically Infeasible Cooling Tower Blowdown Vents 

Control Options 

Table 9-22 summarizes the technical feasibility of potential pollution control technologies for the 

cooling tower blowdown vents. Details regarding the technologies that are not feasible are discussed 

in the subsequent sections. 

Table 8-55 Technical Feasibility of Emission Control 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/CO2 off 

gas with vent to safe location.

Yes 

As noted above, the flow rates of cooling tower 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 maintain 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 Cooling 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. 
Minnesota Steel Page - 190 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 8-56 Ranking of Remaining Preheater 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 cooling 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 Blowdown Vents BACT Selection 

The proposed BACT for CO emissions the cooling water system is installation and proper operation 

of the cooling water blowdown system. Add on controls 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 
Minnesota Steel Page - 191 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

process water cooling system. If testing is feasible, three hour compliance test (or longer if needed) 

using EPA Method 10 is proposed due to the highly variable flow rates from these sources. The mass 

emission limit is based on operation with BACT controls and the facility running at full 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 Steel 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 Handling Process Description 

In the DRI section of the plant, material handling equipment includes taconite ore and DRI pellet 

conveyor drops, storage bin vents and taconite and DRI pellet screening. DRI material handling 

systems also include the Pneumatic Transfer System (PTS) which is used for the transfer of hot DRI 

pellets from the DRI plant 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 proposed 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 material 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 includes particulate emissions from conveyor drops, 

crushing and grinding operations and 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 facility 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 required for safety reasons. The proposed BACT limit for particulate 

emissions is 0.005 gr/dscf for web scrubbers and 0.0025 gr/dscf for baghouses as measured by EPA 

Method 5. Attachment N specifies the type of control for each emission point. Where feasible, 

baghouses are specified. 
Minnesota Steel Page - 192 DRI Plant 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

For periods of startup and shutdown, Minnesota Steel 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 down and off line. Therefore, Minnesota Steel is not proposing any 

special permit conditions for startup and shutdown. 

For control of emissions from additive handling, Minnesota Steel will put the additive handing 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. 

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 material 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 basins, unpaved roads, storage piles, loading and 

unloading operations, and material drops from mobile equipment. 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 these 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 - 193 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 following steel making processes: 2 electric arc 

furnaces (EAF), 2 ladle metallurgy furnaces (LMF), ladle preheaters, ladle dryers, 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. Pebble lime and limestone are added to remove impurities from the 

steel and to form a slag. Carbon is added to create 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 electrodes, 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 
Minnesota Steel Page - 194 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 are also used to inject carbon and lime. The EAF is 

covered by a roof, which is ventilated to a direct shell evacuation system and to a baghouse. 

When the iron and additives melt in the EAF they separate into a molten steel layer at the bottom and 

a molten slag layer on top. Minnesota Steel will use 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 hearth refractory wear by shielding arc radiation, 

and improves heat transfer. This process will produce additional chemical energy along with CO due 

to the oxidation of the injected carbon. The slag layer also absorbs deoxidation products (e.g., SiO2

and Al2O3), removes impurities, provides de-phosphorizing, protects the 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, SO2, NOx 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 SO2. NOx is generated by the oxy-fuel burners 

when they are used to heat the EAF. NOx is also formed by the high operating temperatures of the 

EAF. Molten steel is 2,700°F - 3100°F. At these temperatures NOx 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 “4th Hole” direct evacuation system. 

Particulate emissions from EAFs are most commonly controlled by baghouses. The extreme 

temperature (~2,000o

F) conditions of the gas stream immediately 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 allows for the introduction of combustion air when 

the roof is in place and the EAF is in operation. During EAF operation the exhaust stream contains a 

high concentration of carbon monoxide (CO). CO is oxidized to CO2 when it mixes with combustion 

air introduced at the gap in the 4th-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 providing a residence time for more complete CO 

combustion. EAF off gases leaving the water cooled duct are in the neighborhood of 1,200o F. 
Minnesota Steel Page - 195 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Additional cooling is needed before emission controls can 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 temperature (< 400o F) for particulate 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 SO2, NOx, CO, and particulates. Most of these compounds are 

released as a result of the refining process. NOx may also be formed by oxidation of atmospheric 

nitrogen by the hot molten steel. 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 reduce 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 carbon monoxide emissions. Steam eductors are used to 

generate the vacuum. A natural gas fired boiler will be used to generate 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 lifted in the ladles and 

allowed to flow into two tundishes. The tundishes are shallow refractory-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 continuous caster mold. The molten steel solidifies as it passes through the 

mold and emerges as a continuous slab of seven to ten inch thickness. After complete solidification, 
Minnesota Steel Page - 196 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

the continuous slab is cut into appropriate 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 the 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 NOx 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 tundishes. The preheat burners are a source of NOx emissions. 

Emissions of other criteria pollutants are minimal due to the use of natural gas as fuel. 

One caster (i.e., one line) will be served by a tunnel furnace, which provides the holding time needed 

to achieve an equalized temperature distribution at about 2,100o

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 NOx burners are positioned along the entire 

length heat the tunnel furnaces. 

The temperature equalized slabs exit the tunnel furnace and enter the rolling mill. From the mill 

entry section the slab will be rolled 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 shipment. The tunnel furnace is a source of NOx emissions. 

Emissions of other criteria pollutants are minimal due to the use of natural gas as fuel. 

The steel mill EAFs will use hot DRI as it is discharged 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 lower the overall NOx 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 per EAF heat to add more scrap as each charge is 

melted down. DRI pellet addition will occur via a chute 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, which suggests significantly less 

fugitive emissions into the melt shop interior. Periodically, accumulated in house scrap will have to 

be added to the EAFs via an open EAF roof. In addition, each cold start of the EAF following 
Minnesota Steel Page - 197 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 next batch; so, a 100% DRI charge 

is feasible. 

Air pollutants generated during steel production can be summarized as follows: 

Source Pollutants Emitted 

EAF PM, PM10, SO2, NOx, CO, VOC, SAM, Fand Pb 

LMF PM, PM10, SO2, NOx, CO, VOC 

Ladle and Tundish preheaters PM, PM10, SO2, NOx, CO and VOC 

Tundish and Continuous Caster PM, PM10 

Tunnel Furnace PM, PM10, SO2, NOx, 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 batch cycles are not considered startup or shutdown 

conditions for BACT. 

9.3 EAF Particulate Matter (PM and PM10) Emissions 

About 90% of the PM emissions are solidified metal 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. These particulates are in 

a solid state when emitted and are classified as filterable particulates. 

The melt shop also contains a small amount of condensable particulate matter. The condensable 

particulates are primarily inorganic compounds like sulfates and 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 from burning natural gas in the oxyfuel burners 

and the ladle and tundish preheaters 
Minnesota Steel Page - 198 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.3.1 Identification of Potential PM/PM10 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 are discussed in 

Section 4.0 and Table 9-1. 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 

9.3.2 Elimination of Technically Infeasible PM/PM10 Control Options 

Table 9-1 summarizes the technical feasibility of each particulate 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/PM10 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 
Minnesota Steel Page - 199 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 applications involving exhaust streams with particulates 

containing a high concentration of iron compounds. The electromagnetic properties of small charged 

particles of iron compounds cause the particles to adhere very strongly 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 
Minnesota Steel Page - 200 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

EAFs, dry or wet ESP’s are considered technically infeasible for controlling particulate emission 

from the melt shop. 

9.3.3 Rank Remaining PM/PM10 Control Technologies by Control 

Effectiveness 

The remaining particulate control technologies applicable to the melt shop are ranked by control 

effectiveness in Table 9-2. 

Table 9-2 Ranking of Remaining PM/PM10 Control Technologies for Melt Shop 

PM / PM10 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/PM10 Control Technologies 

Fabric Filter 

Fabric filters are technically feasible for collecting 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 particulate 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/PM10 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 associated 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 a wet scrubber. 
Minnesota Steel Page - 201 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Based on the fact that fabric filters are the top control 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 Workshop 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/PM10 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 evaluation of recent BACT 

determinations in the RBLC resulted in emission limits of 0.0018 grains per dscf using EPA Method 

5 (filterable particulates), and 0.0030 gr/dscf using test Methods 5 (filterable particulates) and 202 or 

EPA approved modified Method 202 procedures (condensable particulates). 

The proposed mass emission limits are 16 lb/hr PM10 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 shop operations from the EPA RBLC database. 

Statistical analyses of the RBLC data are summarized in the tables below. Note that the minimum 

value in most cases is 0.0018 gr/dscf, and the maximum value is 0.0052 gr/dscf. This is in part due 

to the incorporation of condensable PM into the analysis. Historically, 0.0052 gr/dscf as filterable 

PM was the New Source Performance 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 listing for melt shop BACT 

limits for PM and Filterable PM for the Nucor facility with RBLC ID IN-0108 (Tables I- 17 and 19). 

It is also documented in the CF & I permit (RBLC 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 particulate matter. The proposed BACT PM- limit is based on the Co-Steel 

Raritan (RBLC ID NJ-0040) PM BACT of 0.003 gr/dscf. Stack test showed PM emissions of 0.0029 

gr/dscf
Minnesota Steel Page - 202 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

EAF RBLC PM10 BACT Limits Summary 

BACT-PSD PM10 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 PM10 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 Filterable 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 
Minnesota Steel Page - 203 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

RBLC data for LMFs was not included in this analysis as some of the reported limits were not 

consistent with emissions from the entire melt shop whereas EAF 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 occur 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/PM10 BACT. 

For EAF and melt shop sources, PM/PM10 emissions are controlled by fabric filters (baghouses). 

A 3% opacity limit is recommended as BACT for visible 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 baghouse 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. 
Minnesota Steel Page - 204 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.5 EAF Sulfur Dioxide (SO2) Emissions 

SO2 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 SO2 in the presence of heat from the EAF or LMF and 

oxygen from ambient air. 

9.5.1 Identification of Potential SO2 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 SO2 control technologies are discussed in 

Section 4.0 and Table 9-3. Potential control technologies for SO2 emissions are the following: 

• Wet Scrubber 

• Spray dryer Absorption 

• Wet Electrostatic Precipitator 

• Dry Sorbent Injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design Methods and Operating Practices 

9.5.2 Elimination of Technically Infeasible SO2 Control Options 

Table 9-3 summarizes the technical feasibility of potential SO2 control technologies. Details 

regarding the technologies that are not feasible are provided in the subsequent sections. 
Minnesota Steel Page - 205 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-3 Technical Feasibility of SO2 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 SO2 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 SO2 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 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 

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) 

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 SO2 emissions. 

Use foaming slag process. Basic material, such 

as lime in the foaming slag froth scrubs SO2. 

Yes 

Flue Gas Desulfurization 

Due to the expected low concentrations of SO2 (~5 ppm) in the melt shop exhaust gas stream and the 

variable flow conditions5

, 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 SO2 emissions from an EAF. No 

recent BACT determinations have identified add-on FGD as a viable control method. See 

Attachment L Table L-6 for recent BACT determinations for SO2 emissions from EAFs. 

 

5

 See Section 9.5 of this report for information on EAF operating conditions. 
Minnesota Steel Page - 206 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.5.3 Ranking of Remaining SO2 Control Technologies by Control 

Effectiveness 

The remaining SO2 control technologies applicable to the melt shop are ranked by control 

effectiveness in Table 9-4. 

Table 9-4 Ranking of Remaining SO2 Control Technologies for Melt Shop 

SO2 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 SO2 Control Technologies 

Table 9-5 Evaluation of Most Effective SO2 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 SO2 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 SO2 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 SO2. So, minimizing the amount of sulfur in these streams minimizes SO2 emissions. Good 

design and operating practices often include low sulfur charge carbon and scrap metal to reduce SO2

emissions. Foaming slag is also used to minimize SO2 emissions. Limestone and other basic 
Minnesota Steel Page - 207 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

compounds in the slag can capture some of the SO2 released in the EAF. Minnesota Steel uses only 

clean outside scrap metal (“bushling”) as EAF charge material during cold restarts. 

9.5.5 EAF SO2 BACT Selection 

Because clean fuels such as low sulfur carbon and good combustion practices are the only feasible SO2

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 SO2/ton of liquid steel produced 

on a 30 operating day rolling average basis and mass emission rate limit of 33 lb/hr SO2 on a 3 hour basis 

for each melt shop. The proposed BACT limit is based on sulfur balance data for EAFs. A comparison 

of the proposed limit with RBLC listings for EAFs and melt shops shows that the proposed limit of 0.15 

lb SO2 per ton of steel is consistent the maximum achievable emissions reductions as demonstrated by the 

fact that it is: 

• Equal to the minimum BACT SO2 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 analysis 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 data suggest that the LMF determinations were only 

for LMFs and did not include EAF emissions. 

MS and EAF RBLC SO2 and SOx BACT Limits Summary 

BACT-PSD SO2 and SOx 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 
Minnesota Steel Page - 208 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Attachment L, Tables L-5, 12 and 20 contain summaries of SO2 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 43. 

RBLC data for LMFs was not included in this analysis as some of the reported limits were not 

consistent with emissions from the entire melt shop whereas EAF and MS limits were consistent with 

total melt shop emissions. 

A thirty operating day rolling average is proposed for the BACT performance limit due to the 

variability of emissions on a daily basis. The chart below shows the highest 24 hour average lb/hr 

SO2 emission rate vs. the 30 day average SO2 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 SO2/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

Date

Daily 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

0.16

30-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. 
Minnesota Steel Page - 209 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

The proposed limit is based on operating days so that the average emission rate is not aversely 

affected by periods when steel is not being produced. 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 initial 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, SO2 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 SO2/ton steel emission 

rates than occur during normal operation. 

Until the EAF reaches the proper operating conditions, Minnesota Steel cannot comply with the 

BACT limits for normal operation due to the reasons noted above. Therefore, Minnesota Steel 

proposes “Good Air Pollution Control Practices for Minimizing Emissions” and limiting 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 minimizes the amount of time each EAF is operates 

with scrap metal feed in order to establish liquid metal levels in the EAF prior to commencing 

DRI pellet feed. 

Minnesota Steel will define good operating practices for minimizing emissions in its startup, 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. 
Minnesota Steel Page - 210 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.6 EAF Nitrogen Oxides (NOx) Emissions 

Thermal NOx is formed by the high operating temperatures of the EAF. Molten steel is 2,700°F - 

3100°F. At these temperatures NOx 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 NOx is generated by the oxy-fuel burners when they are used to heat the 

EAF. Natural gas use in the EAF burners has minimal fuel bound to nitrogen; eliminating fuel bound 

NOx as a source of NOx emissions. 

9.6.1 Identification of Potential 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 NOx control technologies are discussed in 

Section 4.0 and Table 9-6. Potential control technologies for NOx emissions are the following: 

• Low Temperature Oxidation 

• Selective Catalytic Reduction 

• Selective Non-Catalytic Reduction 

• Non-selective Catalytic 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 NOx control technologies. Additional 

details are discussed for those technologies that are not feasible in the subsequent sections. 
Minnesota Steel Page - 211 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

NOx Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Low Temperature Oxidation 

Low Temperature Oxidation is a process where 

NOx 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 NOx control technology in which 

ammonia (NH3) 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 N2 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. NOx and CO react in the 

presence of NSCR catalyst to form nitrogen (N2) 

and carbon dioxide (CO2). 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 NOx. 

No 

Low-NOx Burners and 

Induced Flue Gas 

Recirculation Burners 

Low-NOx burner (LNB) technology utilizes 

advanced burner design to reduce NOx 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 NOx formation. 

No 
Minnesota Steel Page - 212 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

NOx 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 

NOx 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 NOx

formation. 

No 

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), 

Burners Out of Service (BOOS) and Load 

Reduction and Reduced Combustion Air 

Temperature. 

No 

Good Design Methods and 

Operating Practices 

EAF roof 4th hole ventilated by Direct-shell 

Evacuation Control system (DEC). This system 

minimizes air infiltration and reduces the amount 

of nitrogen available for NOx 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 conditions is a principle concern in application of NOx

controls. This issue is documented in the paper6

 Infeasibility of Non-selective 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 article, EAF exhaust flow rates vary from 150,000 acfm 

to 400,000 acfm in a period of 5 minutes. Figure 5 shows that NOx 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 NOx concentrations makes the use of add on controls infeasible because of the 

difficulty in controlling reagent injection rates to match process flow rates and NOx concentrations. 

 

6

 “Infeasibility of Non-selective Catalytic Reduction (SNCR) for Control of NOx Emissions from an Electric Arc 

Furnace” is a paper written by Wesselmand, Rahu and Askins; it was presented at the 2005 AISTech convention. 
Minnesota Steel Page - 213 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Another issue which affected the viability of NOx 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 particulate matter, which would adversely affect NOx catalysts. 

So, the particulates must be cleaned from the EAF exhaust gas before it would be feasible to employ 

catalytic NOx 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 other 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 NOx concentration is in the baghouse exhaust is too low for effectively 

control. 

Conventional heat exchangers are not feasible to cool the EAF exhaust gas stream because of the 

high particulate content. The particulates 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 variability 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 NOx emissions from melt shops. 

Therefore, based on the technical reasons discussed above, 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 concentrations present in the melt shop’s exhaust gas stream would 

cause several operating issues with the application of SCR directly downstream of the EAF. The 

potential problems include catalyst poisoning, fouling, and masking 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 prevent 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. 
Minnesota Steel Page - 214 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Consequently, it would be necessary to place the SCR system downstream of the particulate control 

device (baghouse) because of potential poisoning, masking, and fouling problems. Placing a SCR 

unit downstream of a particulate control device would be unacceptable because: 

1. NOx concentrations at the baghouse exhaust are in the 10 ppm to 15 ppm range. The 

concentration is too low for SCR catalyst to remove any significant amount of NOx. 

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 NOx concentration of 

the exhaust gas will vary widely over the melt cycle. Constantly changing flow rates and 

temperature would make operation of SCR infeasible. 

In view of the above limitations, SCR is not technically feasible to apply 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, when 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 low. Finally, the concentration of NOx at the exhaust of the 

baghouse on the EAF is too low to achieve effective control using NSCR. NSCR can not reduce NOx

concentrations below the 15ppm expected to be in the exhaust. For these reasons, NSCR is not 

technically feasible. 

Selective Non-Catalytic Reduction (SNCR) 

SNCR provides effective NOx control for operations in which the NOx concentration and temperature 

are relatively stable. The melt shop operates in batch mode which result in short bursts of NOx in 

high concentrations followed by extended periods of low concentrations. The temperature of the 

EAF exhaust gas will vary widely during the melt cycle 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 NOx control. The water cooled duct on the outlet of the 
Minnesota Steel Page - 215 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 seconds. This is insufficient time for the SNCR reactions to occur 

at rate which is effective in controlling NOx emissions. In view of these operating conditions, SNCR 

is not technically feasible. 

Low Temperature Oxidation (LTO) 

Although LTO is suited to the temperatures downstream of the melt shop baghouse, it is infeasible 

because: 

1. NOx concentrations at the baghouse exhaust are in the 10 ppm to 15 ppm range. The 

concentration is too low for LTO to remove any significant amount of NOx. 

2. Since an EAF operates in a batch mode, the temperature, flow rate and NOx concentrations of 

the exhaust gas will vary widely over the melt cycle. Constantly changing flow rates, 

temperatures and NOx concentrations will make it difficult to maintain proper reagent 

addition rates, and to keep the HNO3 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 temperature; which in turn reduces NOx. 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 due to the difficulty of maintaining the proper flue gas dilution ratio 

as the auxiliary burners only operate for short periods and flow rates can fluctuate rapidly during the 

EAF operational cycles. 

Low-NOx Burners and Induced Flue Gas Recirculation Burners

EAF operation requires extremely high operating temperatures. Molten steel in the EAF is 2,700°F - 

3100°F. Under these conditions, high flame temperatures are required to meet the temperature 

requirements of the EAF. Low NOx burners work by reducing peak flame temperatures; so, they 

loose NOx control effectiveness in high temperature applications. Oxyfuel burner technology is 

typically employed in these applications. Oxyfuel burners provide NOx emissions control by 
Minnesota Steel Page - 216 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

substituting pure oxygen for combustion air. This significantly reduces the introduction of 

atmospheric nitrogen into the EAF where it can form NOx. 

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 NOx 

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 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. 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 feasible 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 NOx 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 
Minnesota Steel Page - 217 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.6.4 Evaluation of Most Effective NOx Control Technologies 

Due to the cyclic nature of the flow from the EAF, add-on controls for NOx removal are not feasible, 

but combustion controls represent a technically feasible means of reducing NOx emissions. An 

analysis of recently established BACT selections based on a review of the RACT/BACT/LAER 

Clearinghouse (RBLC) database indicates that the steel mills listed in Appendix L, Table L-7 do not 

have add-on devices to control NOx emissions from EAFs. Instead, oxy-fuel burners and Direct-shell 

Evacuation Controls (DEC) lead to acceptable NOx 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 Evacuation Control system (DEC) are the only feasible 

NOx control options and are routinely selected as BACT 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 NOx BACT limit for Nucor Auburn Steel (RBLC ID NY0094). Nucor has a NOx 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 shops shows that the proposed limit of 0.26 lb NOx 

per ton of steel is consistent the maximum achievable emissions reductions as demonstrated by the fact 

that it is: 
Minnesota Steel Page - 218 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

• 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 NOx emission limits which have been demonstrated in practice by a facility 

with a recent BACT determination. This facility 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 quartile 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 providing a small allowance for variations in site specific 

operating conditions. The statistical analysis of RBLC data was performed on a set of 26 emission limits 

for EAFs and melt shops. A table summarizing the statistical 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 this 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 NOx BACT determinations for EAF operations 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 
Minnesota Steel Page - 219 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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]). Neither facility was able to comply with the NOx

BACT limits listed in the RBLC. CF&I is currently seeking a higher NOx limit. Republic Technologies 

received a higher NOx limit after it could not meet the lb/hr limit for EAF #7; this limit is equivalent to 

0.1 lb NOx per ton steel produced. Nucor Auburn Steel (RBLC ID NY-0094) has a NOx 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 NOx 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 analysis as some of the reported limits were not 

consistent with emissions from the entire melt shop whereas EAF and MS limits were consistent with 

total melt shop emissions. 
Minnesota Steel Page - 220 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

Date

Daily Max 24-hr Rolling Avg NOx Emission Rate (lb/hr)

0

0.05

0.1

0.15

0.2

0.25

0.3

30-day Rolling Avg NOx Emission Rate (lb/ton)

Daily Max of

24 hour rolling

average

(lb/hr)

30 day rolling

average

(lb/ton)

Facility 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 proposed for the BACT performance 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 NOx emission rate vs. the 30 day average NOx emission rate on a lb/ton steel basis for a 

six month period. 

The proposed limit is based on operating days so that the average emission rate is not aversely 

affected by periods when steel is not being produced. 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 initial 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 

after weekly and annual maintenance outages will include about 50% clean steel scrap followed by the 
Minnesota Steel Page - 221 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

addition of DRI pellets. Therefore, NOx 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 NOx/ton steel emission 

rates than occur during normal operation. 

Until the EAF reaches the proper operating conditions, Minnesota Steel cannot comply with the 

BACT limits for normal operation due to the reasons noted above. Therefore, Minnesota Steel 

proposes “Good Air Pollution Control Practices for Minimizing Emissions” and limiting 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 minimizes the amount of time each EAF is operates 

with scrap metal feed in order to establish liquid metal levels in the EAF prior to commencing 

DRI pellet feed. 

Minnesota Steel will define good operating practices for minimizing emissions in its startup, 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. 

9.7 EAF Carbon Monoxide (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 Potential 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 9-9. Potential control technologies for CO emissions are the following: 

• Thermal Oxidizer (Recuperative and Regenerative) 
Minnesota Steel Page - 222 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

• 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 feasibility 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 Technologies Considered for BACT Analysis 

Technology Description Feasible? 

Yes or No 

Thermal Oxidizer 

(Recuperative and 

Regenerative) 

A thermal oxidizer uses high temperature 

and residence time to oxidize CO to CO2. 

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 4th 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 
Minnesota Steel Page - 223 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 recovery devices and cause excessive pressure drops and fuel use. 

Without heat recovery, a thermal oxidizer would 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 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 phosphorous 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. 
Minnesota Steel Page - 224 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Post Baghouse Oxidizer 

Installation of an oxidizer downstream of the EAF baghouse presents the following problems: 

1. CO 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 natural 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. 

9.7.3 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 Effective CO Control Technologies 

The use of good design for EAFs typically includes an EAF roof exhaust vented to Direct-shell 

Evacuation Control (DEC) system which includes air 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. 
Minnesota Steel Page - 225 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Since good design and good combustion controls are inherent to the process no additional cost will 

be incurred. 

Table 9-11 Evaluation of Most Effective 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-shell Evacuation Control (DEC), with air injection followed by a 

drop out box to be BACT for CO emissions from the 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 determinations for CO emissions 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 (See also Attachment L, Table 45). Minnesota Steel is proposing a 

CO limit of 2.0 lb CO per ton 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 determinations is 2.0 lb CO/ton steel produced. 

• The proposed BACT is within the top half of the upper quartile (top 12%) of recent PSD permits. 

• The limit is based on emission controls consistent with recent BACT determinations. 

Minnesota Steel proposes a limit of 2.0 lb CO/ton steel produced because of the large number of 

units permitted at 2.0 lb CO/tons steel produced and because this is in the top 12 percent of 

determinations in the RBLC. The proposed BACT limit is also consistent with actual emissions from 

a steel mill recently listed in the RBLC as shown in the chart on the following page. 
Minnesota Steel Page - 226 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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. 
Minnesota Steel Page - 227 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

Date

Daily Max of 8-hr Rolling Avg CO Emission Rate (lb/hr)

0

0.5

1

1.5

2

2.5

30-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 smaller and therefore the lb/hr 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 emissions from the entire melt shop, whereas EAF and MS 

limits were consistent with total melt shop emissions. 

A thirty operating day rolling average is proposed for the BACT performance 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 emission rate on a lb/ton steel basis for a six month 

period. 

The proposed limit is based on operating days so that the average emission rate is not aversely 

affected by periods when steel is not being produced. An operating day is a calendar day in which 

the EAF is operating for at least 18 hours. 
Minnesota Steel Page - 228 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Periods of Startup, Shutdown and Malfunction 

Startup and shutdown periods only include the initial 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 startup 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 conditions, Minnesota Steel cannot comply with the 

BACT limits for normal operation due to the reasons noted above. Therefore, Minnesota Steel 

proposes “Good Air Pollution Control Practices for Minimizing Emissions” and limiting 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 minimizes the amount of time each EAF is operates 

with scrap metal feed in order to establish liquid metal levels in the EAF prior to commencing 

DRI pellet feed. 

• Operation of the EAF in a manner which minimizes the amount of time the EAF is operated at 

temperatures that are below the oxidation temperature of CO during startup and shutdown of an 

EAF. 

Minnesota Steel will define good operating practices for minimizing emissions in its startup, 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. 
Minnesota Steel Page - 229 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Potential 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 9-12. Potential control technologies 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 control technologies for the melt 

shop. Details regarding the technologies that are not feasible are discussed in the subsequent 

sections. 
Minnesota Steel Page - 230 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 uses high temperature 

and residence time to oxidize VOC to CO2 

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 4th 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. 
Minnesota Steel Page - 231 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

3. Particulates will foul heat recovery devices and cause excessive pressure drops and fuel use. 

Without heat recovery, a thermal oxidizer would 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 phosphorous 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 natural 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. 
Minnesota Steel Page - 232 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Effective 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 for 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 process no additional cost will be incurred. 

Table 9-14 Evaluation of Most Effective 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 Evacuation 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 VOC/ton steel to be BACT for VOC emissions. These controls at 

the proposed emission limit are consistent with recent BACT determinations for VOC emissions 

from EAFs as shown in Attachment L, Tables L-8 and 23. A mass emission rate of 27 lb/hr VOC on 

a 24 hour average for each melt shop is also recommended as BACT. 
Minnesota Steel Page - 233 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Attachment L, Tables L-8 and 23 contain summaries 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 indicated by the median of EAF VOC limits. Examination of the RBLC 

data shows that many of the BACT determinations at 0.15 lb VOC/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 analysis as some of the reported limits were not 

consistent with emissions from the entire melt shop whereas EAF and MS limits were consistent with 

total melt shop emissions. 

A thirty operating day rolling average is proposed for the BACT performance 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 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. 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 that the average emission rate is not aversely 

affected by periods when steel is not being produced. An operating day is a calendar day in which 

the EAF is operating for at least 18 hours. 
Minnesota Steel Page - 234 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Periods of Startup, Shutdown and Malfunction 

Startup and shutdown periods only include the initial 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 emissions during startup and shutdown 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 conditions, Minnesota Steel cannot comply with the 

BACT limits for normal operation due to the reasons noted above. Therefore, Minnesota Steel 

proposes “Good Air Pollution Control Practices for Minimizing Emissions” and limiting 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 minimizes the amount of time each EAF is operates 

with scrap metal feed in order to establish liquid metal levels in the EAF prior to commencing 

DRI pellet feed. 

• Operation of the EAF in a manner which minimizes the amount of time the EAF is operated at 

temperatures that are below the oxidation temperature of VOC during startup and shutdown of an 

EAF. 

Minnesota Steel will define good operating practices for minimizing emissions in its startup, 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 
Minnesota Steel Page - 235 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.9 EAF Fluoride (F) Emissions 

Fluoride emissions may be generated from trace amounts of fluorides in the DRI pellets, additives 

and natural gas used in the EAF. The most significant source of fluorides in the EAF is fluorspar. 

Fluorspar is used as an additive for slag formation. Based on the nature of EAF slag, and the 

temperature of the melt shop exhaust stream, F- compounds are expected to be particulates which are 

incorporated in the slag dust from the EAF. 

9.9.1 Identification of 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 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 Infeasible Fluoride Control Options 

Table 9-15 summarizes the feasibility of potential controls for fluorides contained in particulate 

matter from the EAF. Details regarding the technologies that were determined to be infeasible are 

discussed in the subsequent sections. 
Minnesota Steel Page - 236 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-15 Technical Feasibility of Fluoride 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 
Minnesota Steel Page - 237 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Electrostatic Precipitator 

Since fluoride compounds in the EAF exhaust are mixed with all the other particulate matter in the 

EAF exhaust, the general properties of the EAF exhaust stream will govern control device feasibility. 

ESP’s have proven to be unsuitable for applications involving exhaust streams with particulates 

containing a high concentration of iron. The electromagnetic properties of small charged particles of 

iron compounds cause the particles to adhere very strongly 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 infeasible for controlling particulate emissions from the melt 

shop. 

9.9.3 Ranking of Remaining Fluoride 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 formation. Based on the Air Emission 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 
Minnesota Steel Page - 238 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

low concentrations of fluoride; fluoride control efficiency may vary from the overall particulate 

control efficiency 

9.9.4 Evaluation of Most Effective Fluoride Control Technologies 

Fabric Filter 

Since fluoride compounds in the EAF exhaust are mixed with all the other particulate matter in the 

EAF exhaust, the general properties of the EAF 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 achieve the highest control efficiencies from EAFs 

and other types of furnaces that have high particulate 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 equivalent. Baghouses are the preferred method of control as the variable 

nature of EAF operation could adversely affect a wet scrubber. 

Based on the fact that fabric filters are the top control option and are routinely determined as BACT 

for melt shop s, Minnesota Steel Industries considers fabric filters to be BACT. As specified in the 

EPA’s New Source Review Workshop 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 determinations in the RBLC did not list any performance standards for 

control of fluorides; only mass emission limits were listed (BACT report Attachment L, Table L -9). 

Due to the low concentrations of fluorides in the uncontrolled EAF baghouse exhaust (0.0001 gr/dscf 

to 0.00001 gr/dscf), a BACT performance standard limit 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 demonstrate ongoing control of fluoride emissions. The proposed mass emission 

limit for fluorides from each EAF is 0.6 lb/hr as determined by performance testing for particulate 
Minnesota Steel Page - 239 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Steel 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 occur 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 Emission Inventory (Appendix 3B.), and stack flow rate from form 

GI-04. 

9.10.1 Identification of Potential 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 various SAM control technologies are discussed in 

Section 4.0 and Table 9-17. Potential control technologies for SAM emissions are the following: 

• Wet Scrubber 

• Spray dryer Absorption 

• Wet Electrostatic Precipitator 

• Dry Sorbent Injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design Methods and Operating Practices 
Minnesota Steel Page - 240 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.10.2 Elimination of Technically 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 discussed 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 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 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. Basic 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 FGD system is both technically and economically infeasible. This 
Minnesota Steel Page - 241 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

includes 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 SAM emissions 

from an EAF. The RBLC does not have any listings of BACT determinations for SAM emission 

from EAFs; however, it does list SOx emissions. No recent BACT determinations for SOx (or SO2) 

have identified add-on FGD as a viable control method. See Attachment L Table L-6 for recent 

BACT determinations for SO2 emissions from EAFs. 

9.10.4 Ranking of Remaining SAM Control Technologies by Control 

Effectiveness 

The remaining SAM control technologies applicable 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 Effective SAM Control Technologies 

Due to the cyclic nature of the flow from the EAF, add-on controls for SAM removal 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 SOx emissions from EAFs. Since the same types of add on controls 

are used to control both SAM and SO2, 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 annual maintenance. Clean scrap 

(bushlings) will be purchased for this purpose. 
Minnesota Steel Page - 242 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 content is consistent with SO2 emission limits in recent BACT determinations for 

EAFs which list low sulfur charge carbon for SO2 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 (SO2 and SAM), Minnesota Steel suggests compliance with the 

proposed BACT SO2 limits for ongoing compliance with the BACT limit for SAM emissions. The 

proposed mass emission limit for SAM emissions from 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 insufficient to accurately measure, in which case the 

averaging period will be the time it takes to collect 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 operations were found in the EPA RBLC database. 

Attachment L, Table L-6 contains a summary of BACT determinations for SO2 and SOx 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 normal operations. However, reduced production rates 

during startup and shutdown may result in higher lb SAM (SO2)/ton steel emission rates than occur 

during normal operation. Therefore, Minnesota Steel proposes “Good Air Pollution Control 
Minnesota Steel Page - 243 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Practices for Minimizing Emissions” and limiting 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 minimizes the amount of time each EAF is operates 

with scrap metal feed in order to establish liquid metal levels in the EAF prior to commencing 

DRI pellet feed. 

Minnesota Steel will define good operating practices for minimizing emissions in its startup, 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. 

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 particulates are generated during charging and 

tapping. The tundishes and continuous casters are also a source of lead 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 Potential 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 PM control technologies are discussed in 

Section 4.0 and Table 9-1. Potential control technologies 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 
Minnesota Steel Page - 244 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.11.2 Elimination of Technically Infeasible Pb Control Options 

Table 9-1 summarizes the technical feasibility of each particulate 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 
Minnesota Steel Page - 245 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 applications involving exhaust streams with particulates 

containing a high concentration of iron compounds. The electromagnetic properties of small charged 

particles of iron compounds cause the particles to adhere very strongly 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 infeasible 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 technologies applicable to the melt shop are ranked by 

control effectiveness in Table 9-2. 
Minnesota Steel Page - 246 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 uncontrolled EAF exhaust is 0.000055 gr/dscf. 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 collecting fine lead bearing 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 particulate 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/PM10 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 associated 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. 
Minnesota Steel Page - 247 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Based on the fact that fabric filters are the top control option and are routinely determined as BACT 

for melt shop s, Minnesota Steel Industries considers fabric filters to be BACT. As specified in the 

EPA’s New Source Review Workshop 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-shell 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 uncontrolled 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 measurement 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 controls for lead oxide emissions. Barr Engineering Co. 

was able to contact representatives of Republic Technologies (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 
Minnesota Steel Page - 248 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 analysis as some of the reported limits were not 

consistent with emissions from the entire melt shop whereas EAF and MS limits were consistent with 

total melt shop emissions. 

For periods of startup and shutdown, Minnesota Steel 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 occur 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/tundish preheaters are open flame burners 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 addition, 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, SO2, NOx, 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 along with other melt shop “fugitive” emissions. 
Minnesota Steel Page - 249 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 evaluation 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. Descriptions 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. wet scrubbers or selective 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 Infeasible Ladle/Tundish Pre-heater Control 

Options 

Table 9-22 summarizes the technical feasibility of potential pollution control technologies for the 

Ladle and Tundish preheaters. Details regarding the technologies that are not feasible are discussed 

in the subsequent sections. 
Minnesota Steel Page - 250 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-22 Technical Feasibility of Emission Control 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 NOx 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 directly 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 pollutants from the burners directly to a control device. As noted 

above, these emissions are routed to the melt shop baghouse with other melt shop “fugitive” 

emissions. 

Good Combustion Controls 

The Ladle/Tundish pre-heater burners are open flame burners where the 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 boilers are not feasible for the same reasons as add on controls. 

9.12.5 Ranking of Remaining Ladle/Tundish 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. 
Minnesota Steel Page - 251 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-23 Ranking of Remaining Preheater Emission Control Technologies 

Emission Control Technologies 

Rank Technology Estimated % Control 

Efficiency

1 Inherently Lower Polluting 

Equipment 

Low NOx 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 emissions, low NOx burners are the only inherently 

lower polluting equipment that can be applied in this application. The typical control efficiency for 

low NOx 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 maintenance of the low NOx 

burners. 

9.12.6 Evaluation of Most Effective Ladle/Tundish Pre-heater Control 

Technologies 

Low NOx burners are effective at reducing NOx emissions and should not adversely affect emission 

rates for other pollutants in this application. In some cases, low NOx burners emit slightly more CO 

than standard burners. 

Natural gas is the clean fuel selected for this application. Use of natural gas will minimize SO2 and 

NOx 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 NOx

burners can be utilized to minimize PM, PM10, CO and VOC emissions. 
Minnesota Steel Page - 252 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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, emission control options are limited. 

Because the preheaters are not enclosed, add-on control devices cannot be used (e.g. SCR for NOx

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 NOx style burners can be used to reduce NOx emissions. 

Minnesota Steel does not propose specific BACT emission limits on the Ladle/Tundish pre-heaters. 

These sources are vented to the melt shop ventilation system and emissions from the pre-heaters are 

accounted for in the emission limits 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 continue this practice until the process is shut down and 

off line. Therefore, Minnesota Steel is not proposing any special permit conditions for PM, PM10, NOx, 

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 SO2

emissions during startup and shutdown. 

Attachment L, Tables L-25 -29 contains a summary of BACT determinations for Ladle and Tundish 

Pre-heater (LTP) operations from the EPA RBLC database. RBLC Ladle and Tundish preheater 

limits are summarized below: 
Minnesota Steel Page - 253 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 
Minnesota Steel Page - 254 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.13 Vacuum Degasser 

9.13.1 Vacuum Degasser Process Description 

Depending upon final steel specification requirements, some “heats” may be processed with a 

vacuum degassing step. In this process the LMF and the steel “heat” it contains are placed 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 degassing system will be routed to a 

control device. The vacuum is provided by a series 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 Potential CO Control Technologies 

The vacuum degasser process is a source of carbon monoxide (CO) emissions. Partial oxidation of 

carbon is the source of CO emissions from the degasser. CO emissions occur as the steel carbon 

content is reduced in the degasser. The vacuum degasser has an estimated CO emission rate of 390 

lb/hr as the carbon content of the steel is reduced 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 control technologies for Vacuum Degasser CO emissions are the 

following: 

• Thermal Oxidizer (Recuperative and Regenerative) 

• Catalytic Oxidizer 

• Flare 

• Good Combustion Controls 
Minnesota Steel Page - 255 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.14.2 Elimination of Technically 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. Constantly 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 the variable flow rates present in the degasser. 

• CO control by good combustion practices is not feasible 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 for Vacuum Degasser 

CO Emission Control Technologies Considered for BACT Analysis 

Technology Description Feasible? 

Yes or No 

Thermal Oxidizer 

(Recuperative and 

Regenerative) 

A thermal oxidizer uses high temperature 

and residence time to oxidize CO to CO2. 

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 
Minnesota Steel Page - 256 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.14.3 Ranking of Remaining CO Control Technologies by Control 

Effectiveness 

Flaring is the only technically 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 Effective CO Control Technologies 

A flare is a relatively simple emission control device. 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 combustion 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 per ton of pollutant removed. The detailed control 

cost analyses are located in Attachment G. 

Table 9-27 Evaluation of Most Effective CO Control 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 for CO emissions from vacuum degasser. Other addon controls are technically infeasible. 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 shut down and off line. No excess emissions will occur as a result of 
Minnesota Steel Page - 257 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Columbus, 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 pollutants emitted from the Vacuum Degasser 

Boiler include: PM, PM10, SO2, NOx, CO, VOC. All emissions result from combustion of natural 

gas. 

9.16 Vacuum Degasser Boiler Particulate MatterPM/PM10 Emission 

Particulate emissions from natural gas combustion are typically low. Particulate matter is generated 

during incomplete combustion. All particulates are assumed to be PM10. 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/PM10 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 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 
Minnesota Steel Page - 258 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.16.2 Elimination of Technically Infeasible PM/PM10 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/PM10 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 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 

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 
Minnesota Steel Page - 259 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

At particulate concentrations of 0.005 gr/dscf, use of add-on controls for gas fired combustion 

sources is technically infeasible because this particulate concentration level is at the limits of PM 

emissions control technology. In addition, particulates from natural gas combustion are primarily 

condensable particulates. Condensable PM is not readily removed by these control devices. The 

particulate concentration of 0.005 gr/dscf was calculated using the AP-42, 5th 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/PM10 Control Technologies by Control 

Effectiveness 

The only remaining control technology for control of PM emissions from the Vacuum Degasser 

Boiler is good burner design and operating practices. 

Table 9-29 Ranking of Remaining PM/PM10 Control Technologies for Vacuum Degasser Boiler 

PM / PM10 Control Technology Ranking 

Rank Technology % Efficiency 

1 Good Burner Design and 

Operating Practices 

NA 

Base Case 

9.16.4 Evaluation of Most Effective PM Control Technologies 

Since good burner design and operating practices is inherent to the process no additional cost will be 

incurred. 

Table 9-30 Evaluation of Most Effective PM/PM10 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 
Minnesota Steel Page - 260 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.16.5 Vacuum Degasser Boiler PM/PM10 BACT Selection 

Good Burner Design and Operating Practices are selected as BACT. 

The proposed BACT PM/PM10 limit for the Degasser Boiler is 0.0075 lb PM/PM10/MMBtu, good 

combustion practices and use of natural gas. Use of natural gas, a clean fuel, limits potential 

emissions of particulates. The proposed PM/PM10 mass emission limit is 0.7 lbs of PM/PM10 per 

hour on a 24 hour average basis. The proposed limit is based on compliance testing for PM by EPA 

Method 5, and PM10 measured by EPA Methods 201 (or 201A) and 202 (or EPA approved modified 

Method 202 procedures). The mass emission limit is based on operation with BACT controls and the 

facility running at full capacity. 

Attachment L, Tables L-38A and 38B contain a summaries of BACT PM and PM10 determinations 

from the EPA RBLC database for natural gas-fired boilers 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/PM10/MMBtu is consistent with AP-42 and less 

than the median BACT PM/PM10 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 consistent with recent RBLC BACT determinations. 

RBLC PM10 BACT Limits Summary 

BACT-PSD PM10 lb/MMBtu Emission Limits Other (non-BACT) PM10

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 
Minnesota Steel Page - 261 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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/MMBtu

Count

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/MMBtu

Count

Propsed BACT 

Limit 0.0075
Minnesota Steel Page - 262 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 from 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 Boiler Visible Emissions 

Visible emissions are the result of incomplete combustion of fuels in the Vacuum Degasser Boiler. 

9.17.1 Vacuum Degasser Package Boiler 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/PM10 BACT. 

In the Vacuum Degasser Boiler, PM/PM10 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. 
Minnesota Steel Page - 263 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.18 Vacuum Degasser Boiler Sulfur Dioxide (SO2) emission 

SO2 emissions from natural gas combustion are typically low. Based on use of natural gas as the fuel 

for the vacuum degasser boiler, the expected SO2 concentration in the boiler flue gas are expected to 

be less than 1 ppm SO2. 

9.18.1 Identification of Potential SO2 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 SO2 control technologies are discussed in 

Section 4.0 and Table 9-31. Potential control technologies for SO2 emissions are the following: 

• Wet Scrubber 

• Spray Dryer Absorption 

• Wet Electrostatic Precipitator 

• Dry Sorbent Injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design Methods and Operating Practices 

9.18.2 Elimination of Technically Infeasible SO2 Control Options 

At less than 1 ppm SO2 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. 
Minnesota Steel Page - 264 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-31 Technical Feasibility of SO2 Control 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 SO2 Control Technologies by Control 

Effectiveness 

The remaining control technology for control of SO2 from the Vacuum Degasser Boiler is the use of 

clean fuel and good combustion practices. 

Table 9-32 Ranking of Remaining SO2 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 
Minnesota Steel Page - 265 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.18.4 Evaluation of Most Effective SO2 Control Technologies 

Since the use of clean fuel and good combustion practices is an inherent part of the process no 

additional cost will be incurred. 

Table 9-33 Evaluation of Most Effective SO2 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 SO2 BACT Selection 

Use of clean fuels (natural gas) and good combustion practices are selected as BACT for the Vacuum 

Degasser boilers. Use of natural gas, a clean fuel, limits potential SO2 emissions to the rated heat 

input capacity of the boilers. 

The proposed SO2 mass emission limit is 0.1 lbs of SO2 per hour on a 3 hour average basis. The 

proposed limit is based on compliance testing for SO2 by EPA Method 6C, determination of SO2 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 SO2 determinations from the EPA RBLC 

database for natural gas-fired boilers 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 SO2/hr is equivalent to 0.0006 lb SO2/MMBtu, and is consistent with AP-42 and the lowest 

BACT SO2 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 and use of natural gas 

with a limit of 0.1 lb SO2/hr as BACT is consistent with recent RBLC BACT determinations. 
Minnesota Steel Page - 266 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 times the DRI Boilers are operating, no special permit 

conditions are required to control SO2 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. NOx

emissions from the Vacuum Degasser Boiler are primarily thermal NOx. Low NOx 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 conservatively high emission rate 

assumption for LNBs relative to the AP-42 NOx emission factor for small boilers, which is equivalent 

to 0.05 lb/MMBtu. A burner rating of 0.08 lb NOx/MMBtu equates to a NOx 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 Vacuum Degasser Boiler NOx emissions are the 

following: 

• Low Temperature Oxidation 

• Selective Catalytic Reduction 

• Selective Non-Catalytic Reduction 

• Non-selective Catalytic Reduction 

• Ultra Low NOx Burners / Low-NOx Burners and Flue Gas Recirculation (ULNB / LNB-FGR) 

• External Flue Gas Recirculation 

• Low NOx Burners 

• Low Excess Air (LEA) 
Minnesota Steel Page - 267 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

• Other Combustion Controls 

9.19.1 Elimination of Technically Infeasible NOx Control Options 

Table 9-34 summarizes the feasibility of potential NOx 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 NOx Control Technologies for the Vacuum Degasser Boiler 

NOx Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Low Temperature Oxidation 

Low Temperature Oxidation is a process where 

NOx 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 NOx control technology in which 

ammonia (NH3) 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 N2 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. NOx and CO react in the 

presence of NSCR catalyst to form nitrogen (N2) 

and carbon dioxide (CO2). It is typically 

employed in clean gas services such as natural 

gas fired turbines. 

No 

Ultra Low NOx Burners or 

Low-NOx 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 NOx 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
Minnesota Steel Page - 268 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

NOx 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 NOx. 

d via the 

ULNB / 

LNB-EFR 

analysis 

Low-NOx Burners 

Low-NOx burner (LNB) technology utilizes 

advanced burner design to reduce NOx 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 NOx

formation. 

Yes 

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), 

Burners Out of Service (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 applications. In addition, the same level of emission control 

can be achieved with SCR or LoTOx. 

• Other Combustion Controls 

Overfire air and burners out of service are appropriate for large industrial 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 the Vacuum Degasser Boiler are ranked by control 

effectiveness in Table 9-35. 
Minnesota Steel Page - 269 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-35 Ranking of Remaining NOx Control Technologies for the Vacuum Degasser Boiler 

NOx Control Technology Ranking 

Rank Technology 

Estimated % Control 

Efficiency 

1 Selective Catalytic 

Reduction 

70 % * 

2 LoTOx 70% * 

3 

Ultra Low NOx Burners or 

Low-NOx 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 NOx Control Technologies 

Table 9-36 Evaluation of Most Effective NOx 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 NOx Burners 

or Low-NOx 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 economically 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. 
Minnesota Steel Page - 270 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 NOx. Only two of 

ninety seven BACT entries had add-on controls for NOx. Instead, low NOx burners or low NOx 

burners with flue gas recirculation have been predominately selected as BACT for control of NOx

emissions. 

9.19.4 Vacuum Degasser Boiler NOx BACT Selection 

Minnesota Steel proposes ultra low NOx burners (ULNB) or low NOx burners with flue gas 

recirculation, or equivalent combustion controls as BACT. Minnesota Steel considers the use of ultra 

low NOx burners or low NOx 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 NOx emission limit of 0.035 lb NOx/MMBtu. The proposed NOx

mass emission limit is 3.5 lbs of NOx per hour on a 24 hour average basis. The proposed limit is 

based on compliance testing for NOx by EPA Method 7E, determination of NOx 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-40A contains a summary of BACT determinations from the EPA RBLC 

database for the natural gas-fired boilers and heater rated at 100 MMBtu/hr or less. The RBLC data 

indicates that ultra low NOx burners or low NOx burners with flue gas recirculation have been 

selected as BACT for control of NOx 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 

NOx/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 NOx BACT Limits Summary 

BACT-PSD NOx lb/MMBtu Emission Limits Other (non-BACT) NOx 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 
Minnesota Steel Page - 271 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

RBLC NOx BACT Limits

Small Gas Fired Heaters & Boilers 

0

5

10

15

20

25

30

35

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

lb NOx/MMBtu

Count

Proposed 

BACT Limit 

0.0035

Periods of Startup, Shutdown and Malfunction 

For periods of startup, shutdown and malfunction, 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 NOx emissions, the DRI Boilers 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. Once the process 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 “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. Good operating practices 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 NOx 

control by ULNB. 
Minnesota Steel Page - 272 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

• Operation of the Degasser Boiler in a manner which minimizes the amount of time the heater is 

operated at excess oxygen levels higher than the operating range effective for NOx control by 

ULNB. 

Minnesota Steel will define good operating practices for minimizing emissions in its startup, 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. 

9.20 Vacuum Degasser Boiler Carbon 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 equates to a CO concentration of 111 ppm, which is 

consistent with good operation of low NOx burners. 

9.20.1 Identification of Potential 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 9-52. Potential control technologies 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 Control Options 

Table 9-37 summarizes the feasibility of potential control technologies for CO emissions from the 

Vacuum Degasser Boiler. 
Minnesota Steel Page - 273 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

CO Emission Control Technologies Considered for BACT Analysis 

Technology Description Feasible? 

Yes or No 

Thermal Oxidizer 

(Recuperative and 

Regenerative) 

A thermal oxidizer uses high temperature 

and residence time to oxidize CO to CO2. 

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 
Minnesota Steel Page - 274 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.20.4 Evaluation of Most Effective CO Control Technologies 

Table 9-39 Evaluation of Most Effective CO 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 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 operating practices are 

inherent parts of the process no additional 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 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 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-41 contains a summary of BACT determinations from the EPA RBLC 

database for natural gas-fired boilers and heaters rated at 100 MMBtu/hr or less. The RBLC data 

indicates Good Combustion Practices and use of natural gas as BACT for CO control. As noted in 
Minnesota Steel Page - 275 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 in 

the 0.08 to 0.1 lb CO/MMBtu range. Therefore, specifying good combustion controls as BACT with 

a limit of 0.08 lb CO/MMBtu for ultra low NOx burners is consistent 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/MMBtu

Count

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 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. 
Minnesota Steel Page - 276 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 calculated 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 Potential 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 9-40. Potential control technologies 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 control 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. 
Minnesota Steel Page - 277 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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

VOC Emission Control Technologies Considered for BACT Analysis 

Technology Description Feasible? 

Yes or No 

Thermal Oxidizer 

(Recuperative and 

Regenerative) 

A thermal oxidizer uses high temperature 

and residence time to oxidize VOC to water 

and CO2. 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 devices 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. See 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 
Minnesota Steel Page - 278 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.21.4 Evaluation of Most Effective VOC Control Technologies 

Since the use of good combustion controls and good burner design and operating practices are 

inherent parts of the process no additional 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 practices 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 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. 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 boilers and heaters rated at 100 MMBtu/hr or less. The RBLC data 

indicates Good Combustion Practices 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/MMBtu. Therefore, specifying good 

combustion controls as BACT with a limit of 0.006 lb VOC/MMBtu is consistent with recent RBLC 

BACT determinations. 
Minnesota Steel Page - 279 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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/MMBtu

Count

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) continuous casters. Casters are used to form liquid 

steel into continuous lengths of solid steel. The liquid steel flows through drain holes in the tundish 

and fills a continuous flow, water-cooled copper mold. The liquid steel solidifies 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 
Minnesota Steel Page - 280 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

metal fumes and casting powders released during casting. Air pollutants emitted during the casting 

processes include PM and PM10. Emissions from the caster are routed to the melt shop baghouse 

system. 

9.22.2 Continuous slab Casters BACT Selection 

Since the continuous caster particulate 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 temperature 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 temperature 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 stands 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, SO2, NOx, 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 
Minnesota Steel Page - 281 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.24 Tunnel Furnace Particulate Matter (PM/PM10) Emissions 

9.24.1 Identification of Potential PM Control Technologies 

Particulate matter emissions from the Tunnel Furnace are the result of natural gas combustion. 

Based on vendor information, the calculated PM/PM10 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/PM10 control technologies are discussed in 

Section 4.0 and Table 9-43. Potential control technologies for PM/PM10 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 Technically Infeasible PM/PM10 Control Options 

Table 9-43 summarizes the feasibility of potential PM control technologies on the Tunnel Furnace. 

Details regarding the technologies that are technically infeasible are discussed in the subsequent 

sections. 
Minnesota Steel Page - 282 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-43 Technical Feasibility of PM/PM10 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 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 

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/PM10 concentration of 0.006 gr/dscf in the Tunnel Furnace exhaust, the use of add-on 

controls is technically infeasible because this concentration is at the limits of PM/PM10 emissions 

control technology. The emissions for the Tunnel Furnace are based on vendor information. 
Minnesota Steel Page - 283 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.24.3 Ranking of Remaining PM/PM10 Control Technologies by Control 

Effectiveness 

The only remaining control technology for control of PM/PM10 emission from the Tunnel Furnace is 

good burner design and operating practices. 

Table 9-44 Ranking of Remaining PM/PM10 Control Technologies for the Tunnel Furnace 

PM / PM10 Control Technology Ranking 

Rank Technology % Efficiency 

1 Good Burner Design and 

Operating Practices 

NA 

Base Case 

9.24.4 Evaluation of Most Effective PM/PM10 Control Technologies 

Since good burner design and operating practices is inherent to the process no additional cost will be 

incurred. 

Table 9-45 Evaluation of Most Effective PM/PM10 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/PM10 BACT Selection 

Good Burner Design and Operating Practices are selected as BACT. 

The proposed BACT PM/PM10 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/PM10 emissions. 

The proposed mass emission limit for the Tunnel Furnace is 1 lb/hr of PM/PM10. The proposed limit 

is based on compliance testing for PM by EPA Method 5, and PM10 measured by EPA Methods 201 

(or 201A) and 202 (or EPA approved modified Method 202 procedures). The mass emission limit is 

based on operation with BACT controls and the facility running at full capacity. 
Minnesota Steel Page - 284 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 BACT determinations for 

tunnel furnaces boilers have specified use of natural gas as BACT for PM/PM10 controls. Therefore, 

specifying good combustion controls and use of natural gas as BACT is consistent 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 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. 

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 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/PM10 BACT. 

At the Tunnel Furnace, PM/PM10 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. 
Minnesota Steel Page - 285 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Sulfur Dioxide (SO2) Emissions 

9.26.1 Identification of Potential SO2 Control Technologies 

Based on use of natural gas as the fuel for the Tunnel Furnace, the expected SO2 concentration in the 

flue gas from this heater is less than 1 ppm SO2. 

Control technologies available for each emitted pollutant must be identified as the first step in a topdown BACT analysis. Descriptions of the various SO2 control technologies are discussed in 

Section 4.0 and Table 9-46. Potential control technologies for SO2 emissions are the following: 

• Wet Scrubber 

• Spray Dryer Absorption 

• Wet Electrostatic Precipitator 

• Dry Sorbent Injection 

• Clean Fuel/ Good Combustion Practices (Base Case) 

• Good Design Methods and Operating Practices 

9.26.2 Elimination of Technically Infeasible SO2 Control Options 

At less than 1 ppm SO2 in the Tunnel Furnace, all add-on controls are technically infeasible because 

1 ppm is at or below the exhaust concentrations that can be achieved with these controls. 
Minnesota Steel Page - 286 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-46 Technical Feasibility of SO2 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 SO2 Control Technologies by Control 

Effectiveness 

The only remaining control technologies for control of SO2 from the Tunnel Furnace are the use of 

clean fuel and good combustion practices 

Table 9-47 Ranking of Remaining SO2 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 
Minnesota Steel Page - 287 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.26.4 Evaluation of Most Effective SO2 Control Technologies 

Since the use of clean fuel and good combustion practices is an inherent part of the process no 

additional cost will be incurred. 

Table 9-48 Evaluation of Most Effective SO2 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 SO2 BACT Selection 

Use of clean fuels (natural gas) and good combustion practices are selected as BACT for the Tunnel 

Furnace. 

The proposed BACT SO2 limit for Tunnel Furnace is to follow good combustion practices and to 

combust natural gas. Use of natural gas, a clean fuel limits potential SO2 emissions. 

The proposed SO2 mass emission limit for the Tunnel Furnace is 0.1 lbs of SO2 per hour on a 3 hour 

average basis. The proposed limit is based on compliance testing for SO2 by EPA Method 6C, 

determination of SO2 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-30 contains the single SO2 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 SO2 controls. Therefore, 

specifying use of natural gas as BACT is consistent with recent 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 times when the Tunnel Furnace is operating, no special 

permit conditions are required to control SO2 emissions during startup and shutdown. 
Minnesota Steel Page - 288 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.27 Tunnel Furnace Nitrogen Oxides (NOx) Emissions 

9.27.1 Identification of Potential NOx Control Technologies 

NOx emissions from the Tunnel Furnace are the result of thermal NOx associated with natural gas 

combustion. Based on vendor information, the calculated NOx 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 NOx control technologies are discussed in 

Section 4.0 and Table 9-49. Potential control technologies for NOx emissions are the following: 

• Selective Catalytic Reduction 

• Low Temperature Oxidation 

• Selective Non-Catalytic Reduction 

• Non-Selective Catalytic Reduction 

• External Flue Gas Recirculation 

• Low-NOx Burners and Induced Flue Gas Recirculation Burners 

• Oxy-fuel Burners 

• Low Excess Air (LEA) 

• Other Combustion Controls 

9.27.2 Elimination of Technically Infeasible NOx Control Options 

Table 9-49 summarizes the feasibility of potential NOx control technologies for emissions from the 

Tunnel Furnace. Details regarding the technologies that are infeasible are discussed in the 

subsequent sections. 

Table 9-49 Technical Feasibility of NOx Control Technologies for the Tunnel Furnace 

NOx Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Low Temperature Oxidation 

Low Temperature Oxidation is a process where 

NOx 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 
Minnesota Steel Page - 289 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

NOx Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Selective Catalytic 

Reduction 

Selective catalytic reduction (SCR) is a postcombustion NOx control technology in which 

ammonia (NH3) 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 N2 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. NOx and CO react in the 

presence of NSCR catalyst to form nitrogen (N2) 

and carbon dioxide (CO2). 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 NOx. 

No 

Low-NOx Burners and 

Induced Flue Gas 

Recirculation Burners 

Low-NOx burner (LNB) technology utilizes 

advanced burner design to reduce NOx 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 NOx 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 NOx

formation. 

No 

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), 

Burners Out of Service (BOOS) and Load 

Reduction and Reduced Combustion Air 

Temperature. 

No 
Minnesota Steel Page - 290 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Selective Catalytic Reduction (SCR) 

SCR systems require relatively stable flow rates and gas temperatures to work effectively. Tunnel 

furnaces operate in a cyclic manner with non-steady flow and temperature conditions. In March 

2004, the Arkansas Department of Environmental Quality (AR DEQ) determined in its technical 

support document for the BIR Steel permit that the overall emission reduction 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 NOx 

control. In its review, the AK DEQ referenced an Indiana Department of Environmental 

Management (IDEM) permit determination 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 application and IDEM revised the emission limit for this source from 

0.014 lb NOx/MMBtu to 0.077 lb NOx/MMBtu. Based on manufacturer’s data, estimated NOx

emissions from the Tunnel Furnace equipped with low NOx burners is 0.06 lb NOx/MMBtu, which is 

similar the Beta Steel NOx 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 NOx control for operations in which the NOx 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 make application of NSCR infeasible. 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. The Tunnel Furnace exhaust is 1160°F. 

Low Temperature Oxidation (LTO) 

Variability in Tunnel Furnace operation will also make application of LTO infeasible due to the 

difficulty in controlling reagent addition. In the case of LTO, the control system would have to 
Minnesota Steel Page - 291 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

control both ozone injection rates and the operation of the ozone generator. Given that this could not 

be accomplished for SCR, which 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 NOx emissions from tunnel furnaces. Therefore, Minnesota Steel 

Industries concluded that it is not technically feasible to apply LTO technologies (Tri-NOx 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 NOx

generation. Given the process variability 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 recirculation is technically infeasible for the Tunnel Furnace. 

Other Combustion Controls 

There are other combustion control methods typically employed on large existing sources such as 

utility boilers which have relatively constant operating conditions. They are relatively inexpensive 

NOx controls, 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. The Tunnel Furnace is a direct fired heater with operations that cycle with each steel 

casting processed. The Tunnel Furnace does not approach the size and operating 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. 
Minnesota Steel Page - 292 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-50 Ranking of Remaining NOx Control Technologies for the Tunnel Furnace 

NOx Control Technology Ranking 

Rank Technology Estimated % Control 

Efficiency 

1 

Low-NOx 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 NOx Control Technologies 

Due to the cyclic nature of the flow, NOx mass emission rates and stack temperatures from the 

Tunnel Furnace, add-on controls for NOx removal are not feasible. Low NOx burners, which are an 

inherent part of the process design, represent a technically feasible means of reducing NOx

emissions. 

Table 9-51 Evaluation of Most Effective NOx 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 add-on devices to control NOx. Instead, low NOx burners or oxy-fuel burners 

have been selected as BACT for control of NOx emissions. 

9.27.5 Tunnel Furnace NOx BACT Selection 

Based on the determination that low NOx burners are the only feasible NOx control option, and have 

been selected as BACT in recent determinations, Minnesota Steel considers the use of low NOx

burners to be BACT. 
Minnesota Steel Page - 293 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Minnesota Steel proposes a BACT NOx emission limit of 0.1 lb NOx/MMBtu. The proposed NOx

mass emission limit is 5.0 lbs of NOx per hour on a 24 hour average basis. The proposed limit is 

based on compliance testing for NOx by EPA Method 7E, determination of NOx by instrumental 

methods. The mass emission limit is based on operation with BACT controls and the facility running 

at full capacity. 

Consistent with recent BACT determinations as shown in Attachment L, Table L-30, Minnesota Steel 

proposes a BACT NOx limit of 0.1 lb NOx/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 NOx burners to effectively control NOx emissions, the Tunnel Furnace must be at sufficient 

load for effective operation of the low NOx burners and for combustion controls to maintain low 

levels of excess combustion air. Once the Tunnel Furnace has reached the appropriate operating 

conditions; the Low NOx burners 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 “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. Good operating practices will include: 

• Operation of the Tunnel Furnace 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 NOx 

control by low NOx burners. 

• Operation of the Tunnel Furnace in a manner which minimizes the amount of time the heater is 

operated at excess oxygen levels higher than the operating range effective for NOx control by low 

NOx burners. 
Minnesota Steel Page - 294 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Minnesota Steel will define good operating practices for minimizing emissions in its startup, 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. 

9.28 Tunnel Furnace Carbon Monoxide (CO) Emissions 

CO emissions from the Tunnel Furnace are the result of incomplete natural gas combustion. Based 

on vendor information, the calculated CO concentration in the stack of the Tunnel Furnace is 23 ppm. 

9.28.1 Identification of Potential 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 9-52. Potential control technologies 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 Control 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 Furnace, all add-on controls are technically infeasible 

because 23 ppm is at or below the exhaust concentrations that can be achieved with theses controls. 

As noted in the NOx review, variability in furnace operating conditions also makes add-on controls 

infeasible. 
Minnesota Steel Page - 295 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 9-52 Technical Feasibility of CO Control Technologies for 

the Tunnel Furnace 

CO Emission Control Technologies Considered for BACT Analysis 

Technology Description Feasible? 

Yes or No 

Thermal Oxidizer 

(Recuperative and 

Regenerative) 

A thermal oxidizer uses high temperature 

and residence time to oxidize CO to CO2. 

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 Effective CO Control Technologies 

Since the use of good burner design and operating practices are inherent parts of the process no 

additional cost will be incurred. 

It should be noted that low NOx and ULNB burner designs have higher CO emissions that standard 

burners. This is due to the fact that the combustion conditions (e.g. reduced flame temperatures) 
Minnesota Steel Page - 296 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

needed to effectively reduce NOx 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 selected 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 emission 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 specified good combustion controls and use of natural gas as BACT for CO. Therefore, 

specifying the use of good combustion controls and natural gas as BACT is consistent 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 will 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. 
Minnesota Steel Page - 297 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

9.29 Tunnel Furnace Volatile Organic Compound (VOC) Emissions 

VOC emissions from the Tunnel Furnace are the result of incomplete natural gas combustion. Based 

on vendor information, the estimated VOC concentration in the stack of the Tunnel Furnace is 10 

ppm. 

9.29.1 Identification of Potential 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 9-55. Potential control technologies 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 control technologies for control of VOC emissions 

from the Tunnel Furnace. At 10 ppm VOC in the Tunnel Furnace, all add-on controls are technically 

infeasible because 10 ppm is at or below the exhaust concentrations that can be achieved with theses 

controls. 
Minnesota Steel Page - 298 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 uses high temperature 

and residence time to oxidize VOC to water 

and CO2. 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 Effective VOC Control Technologies 

Since the use of good burner design and operating practices are inherent parts of the process no 

additional cost will be incurred. 

It should be noted that low NOx and ULNB burner designs have higher CO emissions that standard 

burners. This is due to the fact that the combustion conditions (e.g. reduced flame temperatures) 

needed to effectively reduce NOx emissions are not as effective at controlling CO emissions as 
Minnesota Steel Page - 299 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

standard burner designs. Because CO and VOC control requires similar combustion conditions, 

control of VOCs may also be reduced with application of low NOx and ultra low NOx 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 Furnace VOC BACT Selection 

Good Burner Design and Operating Practices are selected 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 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. 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 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 controls and use of natural gas as BACT for VOC. 

Therefore, specifying the use of good combustion controls 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 continue this practice until the furnace is shut down and 
Minnesota Steel Page - 300 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

off line. Therefore, Minnesota Steel is not proposing 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 sumps, 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. See 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 trucks to storage bins and transfers 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 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 Additive 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 particulate emissions from pneumatic transfers of additive materials. The proposed 

BACT limit for particulate emissions (PM/PM10) is 0.0025 gr/dscf as measured 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. 
Minnesota Steel Page - 301 Steel Mill 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 controls for fugitive emission sources throughout the 

facility are reviewed in Section 15.0 of the BACT report. Fugitive dust sources reviewed in Section 

15.0 includes particulate emissions from mining operations, tailings basins, unpaved roads, storage 

piles, loading and unloading operations, and material 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 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. 
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 process 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 drops, unpaved roads, storage piles, loading and 

unloading operations, and material drops from mobile equipment. 

In order to simplify the BACT report, emissions controls for fugitive emission sources throughout the 

facility are reviewed in Section 15.0 of the BACT report. Fugitive dust sources reviewed in 

Section 15.0 includes mining operations, 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 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. 
Minnesota Steel Page - 303 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

11.0 Material Handling – Transfers of Raw 

Materials Between Processes 

11.1 Raw Material Handling Process Description 

Material handling and crushing emission units are grouped and considered together for the BACT 

review. These sources represent continuous movement of materials between process areas or 

between unit operations within a process 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 Inventory, Appendix B, lists the material handling emission units, 

stack numbers, and their associated potential to emit (PTE) particulate matter. 

Material handling vents do not include combustion sources or ore/steel process vents. Therefore, 

material handling emission points are not sources of condensable particulate matter. 

11.2 Material Handling Particulate Matter (PM/PM10) Emissions 

11.2.1 Identification of Potential PM/PM10 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 are discussed in 

Section 4.0 and Table 11-1. Each of the technologies 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) 
Minnesota Steel Page - 304 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

11.2.2 Elimination of Technically Infeasible PM/PM10 Control Options 

Table 11-1 summarizes the feasibility of potential particulate control technologies for material 

handling operations. All controls are considered technically feasible. 

Table 11-1 Technical Feasibility of PM/PM10 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 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. 

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 
Minnesota Steel Page - 305 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

The air from finished pellet handling contains too much moisture to effectively and reliably apply a 

baghouse. Condensation of moisture and condensable particulates will 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 failures if air temperatures 

the filter material temperature limits. 

Dry iron dust is combustible, and presents a safety 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/PM10 Control Technologies by Control 

Effectiveness 

Particulate control technologies applicable to material handling operations are ranked based on 

control effectiveness in Table 11-2. 

Table 11-2 Ranking of Remaining PM/PM10 Control Technologies for Material Handling 

PM / PM10 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/PM10 Control Technologies 

Material handling will be performed by conveyor belt or similar mechanical device. These are fixed 

sources and particulate emission points that can be enclosed for collection and control of particulate 

emissions. Baghouses, wet scrubbers and ESP’s are all capable 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 
Minnesota Steel Page - 306 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

scrubbing is the preferred option for safety reasons. Dry iron dusts 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/PM10 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/PM10 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/PM10 BACT Selection 

Consistent with recent BACT determinations for material handling as listed in Appendix I, 

Tables I-31 and 32, and the Taconite MACT standard for new sources, Minnesota Steel proposes a 
Minnesota Steel Page - 307 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 particulate matter limits found in the RBLC for this source category. The BACT 

limit may be met by baghouses, wet scrubbers, ESPs or WESPs. BACT mass emission limits for 

individual material handling sources 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 Steel 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 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. 

11.3 Material Handling Visible Emissions 

Visible emissions are the result of particulate materials which are generated during material handling 

operations. 
Minnesota Steel Page - 308 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

11.3.1 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/PM10 BACT. 

For material handling sources, PM/PM10 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 filters 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 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 material handling equipment where PM/PM10 emissions are 

controlled by wet scrubbers. Wet scrubber exhaust contains droplets of entrained scrubber water and the 

exhaust gas is saturated with water vapor. The water vapor condenses for form additional water droplets 

when the exhaust plume comes in contact 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 material handling sources controlled by wet scrubbers. 

Proper operating practices and monitoring of the wet 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 
Minnesota Steel Page - 309 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

scrubber operating parameters will enable 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 Potential F- Control Technologies 

Fluoride salts are present in trace quantities in the iron ore. It is emitted as a particulate along with 

taconite ore and DRI pellet dust during material transfer operations. PM controls will also be used to 

control fluoride particulate emissions. Descriptions of the various fluoride (PM) control technologies 

are discussed in Section 4.0 and Table 11-1. Each of the technologies 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 technologies for material handling 

operations. All controls are considered technically feasible. 
Minnesota Steel Page - 310 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 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. 

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- Control Technologies by Control 

Effectiveness 

Fluoride emission technologies applicable to material handling operations are ranked based on 

control effectiveness in Table 11-6. 
Minnesota Steel Page - 311 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Effective F- Control Technologies 

Material handling will be performed by conveyor belt or similar mechanical device. These are fixed 

sources and particulate emission points can be enclosed for collection and control of particulate 

emissions. Baghouses, wet scrubbers and ESP’s are all capable 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. Dry iron dusts 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. 
Minnesota Steel Page - 312 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 BACT determinations for material handling listed in Appendix I, Tables I-31 

and 32, and the Taconite MACT standard for new sources, Minnesota Steel proposes a F- 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 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 listed 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 commencing operation of process equipment, and keep 
Minnesota Steel Page - 313 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 quantities in the iron ore; therefore, lead is emitted as a particulate 

along with ore dust during material transfer operations. PM controls will also be used to control lead 

particulate emissions. Descriptions of the various lead (PM) control technologies are discussed in 

Section 4.0 and Table 11-1. Each of the technologies 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 considered technically feasible. 
Minnesota Steel Page - 314 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 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. 

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 

 * 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 
Minnesota Steel Page - 315 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

11.5.3 Ranking of Remaining Pb Control Technologies by Control 

Effectiveness 

Lead emission technologies applicable to material handling operations 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 Effective Pb Control Technologies 

Material handling will be performed by conveyor belt or similar mechanical device. These are fixed 

sources and particulate emission points can be enclosed for collection and control of lead (PM) 

emissions. Baghouses, wet scrubbers and ESP’s are all capable 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 plant, wet scrubbing is the preferred 

option for safety reasons. Dry iron dusts 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 in the 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. 
Minnesota Steel Page - 316 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Lead 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 BACT determinations for material handling 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 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 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 sources are listed in Attachment N to the BACT report. 
Minnesota Steel Page - 317 Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 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. 

 
Minnesota Steel Page - 318 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

12.0 Additive Material Handling 

12.1 Additive Material Handling Process Description 

Additive receiving and handling includes the railcar or truck unloading of additives such as 

limestone, hydrated lime, and carbon, transfer to the additive storage 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 materials. The individual emission units and stack 

numbers of additive material handling sources are listed in the Air Emissions Inventory, Appendix 

B3. 

Additive material handling vents do not include combustion sources or ore/steel process vents. 

Therefore, material handling emission points are not sources of condensable particulate matter. 

12.2 Additive Material Handling Particulate Matter (PM) Emissions 

12.2.1 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 various PM control technologies are discussed in Section 

4.0 and Table 12-1. Potential control technologies for PM/PM10 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. 
Minnesota Steel Page - 319 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 12-1 Technical Feasibility of PM/PM10 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 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. 

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 
Minnesota Steel Page - 320 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Technologies for Additive Material Handling 

PM / PM10 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 Effective PM Control Technologies 

Additive receiving and handling will 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 PM10 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 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 
Minnesota Steel Page - 321 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

particulate matter from material transfers into silos and storage bins and are routinely selected as 

BACT. Fabric filters are the preferred method of control as the variable nature of additive transfer 

could adversely affect the performance of a wet scrubber or electrostatic precipitator. In addition, 

most additive material transfer sources are too small for cost effective installation of a scrubber or 

ESP. 

12.2.5 Additive Material Handling PM BACT Selection 

Fabric filters are a top particulate emission control option and are routinely selected as BACT for 

additive material transfers; therefore, 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 BACT limit of 0.005 gr/dscf, as measured by EPA 

Method 5, for additive material transfers. BACT mass emission limits for individual material 

handling sources 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 

Minnesota Steel will put the additive handing 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. 
Minnesota Steel Page - 322 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

12.3 Additive Material Handling Visible Emissions 

Visible emissions are the result of particulate materials 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/PM10 BACT. 

For additive material handling sources, PM/PM10 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 average 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 opacity limit of 5% is consistent with recent RBLC 

determinations for material handling sources in the 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/PM10 emissions are 

controlled by wet scrubbers. Wet scrubber exhaust contains droplets of entrained scrubber water and the 

exhaust gas is saturated with water vapor. The water vapor condenses for form additional water droplets 

when the exhaust plume comes in contact 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 
Minnesota Steel Page - 323 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

visible emission standard is recommended for additive material handling sources controlled by wet 

scrubbers. 

Proper operating practices and monitoring of the wet 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 enable Minnesota Steel to identify conditions where visible emissions 

could occur, and to take corrective measures. 

12.4 Additive Material Handling Fluoride (F-) Emissions 

12.4.1 Identification of Potential F- Control Technologies 

Fluoride salts are present in fluorspar (calcium fluorite CaF2); it is not present in any of the other 

additives used at Minnesota Steel. It is emitted 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 fluoride (PM) control technologies are discussed in 

Section 4.0 and Table 12-4. Each of the technologies 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 technical feasibility of fluoride control technologies for emissions from 

additive material handling operations. All controls are considered technically feasible. 
Minnesota Steel Page - 324 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 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. 

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- Control Technologies by Control 

Effectiveness 

Particulate control technologies applicable to additive receiving and handling operations are ranked 

based on control effectiveness in Table 12-5. 
Minnesota Steel Page - 325 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 12-5 Ranking of Remaining Control Technologies 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 Effective F- Control Technologies 

Additive receiving and handling will 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 BACT 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- Control 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 additive storage bin. So, the fluoride control costs for the balance of 

the storage bins will be ten to one hundred times higher that the fluorspar bin control cost. 
Minnesota Steel Page - 326 Additive Material Handling 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 preferred method of control as the variable nature of additive transfer 

could adversely affect the performance of a wet scrubber or electrostatic precipitator. In addition, 

most additive material transfer sources are too small for cost effective installation of a scrubber or 

ESP. 

12.4.5 Additive Material Handling F- BACT Selection 

Based on the fact that fabric filters 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 listed 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 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. 
Minnesota Steel Page - 327 Cooling Towers 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

13.0 Cooling Towers 

13.1 Cooling Tower Process Description 

The DRI plant, melt shop and rolling mill use water as a cooling medium to control process 

temperatures. The DRI plant and steel mill cooling water systems consists of sumps, circulation 

pumps, cooling towers and a clarifier system. This system supplies cooling water to the direct 

contact coolers and process water uses including the 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 temperature of water in the cooling water system by evaporative cooling. 

A cooling tower consists of a fan, water distribution system, drift eliminator, contact tower and water 

sump. Hot cooling water enters the top of the cooling tower through a water distribution system and 

flows down through a contact tower and into a recovery sump. Some of the water evaporates as it 

flows through the contact tower, and 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 contact tower is filled with contact 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 the cooling tower draws these droplets towards the 

fan. These water droplets are vented to the atmosphere 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 particulate 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 cooling water. To counteract this, some water is 

removed from the tower (blowdown) and is replaced with fresh waster. Good operating 
Minnesota Steel Page - 328 Cooling Towers 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

practices are employed to balance water consumption via blowdown against acceptable TDS 

concentrations. 

13.2 Cooling Towers Particulate Matter (PM) Emissions 

13.2.1 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 various PM control technologies are discussed in 

Section 4.0. Potential control technologies for PM emissions are the following: 

• Drift Eliminators (Base Case) 

• Follow good operating practices for limiting Total 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 technically infeasible control 

technology options. For the DRI and Steel Mill cooling 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 Effective PM Control Technologies 

Because the drift eliminator and cooling water TDS control are the only viable control option, no 

comparative performance, cost and other impacts analysis was conducted. 

In order to reduce the TDS content of cooling water, some cooling water must be removed from the 

cooling system and replaced with fresh water. Good operating practices are employed to balance 

water consumption via blowdown 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 cooling towers is listed below. 
Minnesota Steel Page - 329 Cooling Towers 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

CT RBLC PM BACT Limits Summary 

BACT-PSD PM %drift 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 circulation rates are available at this time to specify mass 

emission limits. 

The summary of the RBLC search information for Minnesota Steel’s cooling towers is in Attachment L 

Table L-37. 

Minnesota Steel will follow the BACT operating practices 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 entrained 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/PM10 BACT. 

In cooling towers, PM/PM10 emissions are controlled by mist eliminators. Cooling tower exhaust 

contains droplets of entrained cooling water and the exhaust gas is saturated with water vapor. The water 

vapor condenses for form additional water droplets when the exhaust plume comes in contact 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, a visible emission limt of 20% is recommended for the 

cooling towers. 
Minnesota Steel Page - 330 Cooling Towers 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Proper operating practices and maintenance of the cooling tower mist eliminators will minimize the 

amount of particulate emitted. Monitoring of cooling tower operating parameters will enable Minnesota 

Steel to identify conditions where visible emissions could occur, and to take corrective measures. 
Minnesota Steel Page - 331 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

14.0 Emergency Generators & Pumps 

14.1 Emergency Generators and Pumps Overview 

Minnesota Steel will have a number of diesel powered emergency generators and pumps. This 

emergency equipment is needed to supply electricity, 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 facility. 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 infrequent. 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 technologies referenced in Section 4, the control technology review for 

diesel powered emergency generators and pumps will include 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 circumstances such as emergency conditions and 

periodic testing. 

As noted in Section 3.5.4, EPA has recently promulgated NSPS Subpart IIII emission standards for 

stationary diesel engines. The new standard limits PM, NOx, CO and VOC emissions 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 IIII has emission limits based on the service of the stationary diesel. The 

service classifications include separate categories for emergency fire pump engines and non-fire 

emergency use engines. SO2 emissions will be limited by Subpart IIII fuel specifications. The 

emergency use classification is for engines operated for 100 hours per year or less. The BACT 

control analysis is based on 500 hr/year of operation. It is still valid at 100 hr/yr because emission 

controls on a $/ton basis are more expensive at lower emission rates. 
Minnesota Steel Page - 332 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

14.2 Emergency Generators and Pumps Particulate 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 various PM control technologies are discussed in 

Section 4.0. Potential control technologies 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. 
Minnesota Steel Page - 333 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 emergency 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 
Minnesota Steel Page - 334 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

14.2.4 Evaluation of Most Effective PM Control Technologies and 

Documentation of Results 

Oxidation catalyst and diesel filters can be eliminated as control technologies based on excessive 

dollar per ton control cost values for engines limited to emergency use. The detailed control cost 

analyses are located in Attachment K. 

Table 14-3 Evaluation of Most Effective PM / PM10 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, Emergency Generator Classification combined with Good 

Combustion Practices is BACT for control of PM emissions. 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 Generators and Pumps Visible Emissions 

Visible emissions from emergency generators and pumps are the result particulate emissions associated 

with incomplete combustion in the diesel engines which power the emergency equipment. 

14.3.1 Emergency Generators and Pumps 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/PM10 BACT. 
Minnesota Steel Page - 335 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

On emergency pumps and generators, PM/PM10 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 emergency diesel exhaust cannot exceed 5% for more the one 6-

minute period during an hour. If Minnesota Steel identifies visible emissions from emergency generators 

and pumps in excess of 5%, it will take corrective action as soon as it is practicable to do so. When this 

equipment is operating under emergency conditions, corrective action may be delay until the emergency 

condition is over. Emergency equipment is exempt from opacity limits during startup until the time that 

the diesel engine reaches proper operating temperatures. 

14.4 Emergency Generators and Pumps SO2 Emission Controls 

SO2 is created by combustion of low sulfur No.2 fuel oil containing elemental sulfur. 

14.4.1 Identification of Potential SO2 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 SO2 control technologies are discussed in 

Section 4.0. Potential control technologies for SO2 emissions are the following: 

• Low Sulfur Fuel

• Operating Limitations

• Add-on controls

14.4.2 Elimination of Technically Infeasible SO2 Control Options 

Table 14-4 summarizes the technical feasibility of SO2 control technologies for emissions from 

emergency generators. RACT/BACT Clearinghouse search indicated no add-on controls for SO2 

BACT control for emergency generators. Low sulfur fuel oil and emergency generator classification 

are both technically feasible. 
Minnesota Steel Page - 336 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 14-4 Technical Feasibility of SO2 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 SO2 Control Technologies by Control 

Effectiveness 

SO2 control technologies applicable to emergency generators are ranked based on control 

effectiveness in Table 14-5. 

Table 14-5 Ranking of Remaining SO2 Control Technologies for 

Emergency Generators and Pumps 

SO2 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 SO2 Control Technologies and Document 

Results 

The combination of Emergency Generator Classification (operating limitation) and low sulfur fuel is 

the top control efficiency technology. 
Minnesota Steel Page - 337 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 SO2 BACT Selection 

Emergency Generator Classification combined with Low Sulfur Fuel is ranked as the highest control 

efficiency technology. Therefore, Emergency Generator Classification combined with Low Sulfur 

Fuel (less than or equal to 0.05% sulfur) is BACT for control of SO2 emissions. Minnesota Steel 

Industries will also comply with NSPS Subpart IIII fuel specifications 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 SO2 emissions during 

startup and shutdown. 

14.5 Emergency Generators NOx Emission Controls 

NOx emissions are created by combustion of low sulfur No. 2 fuel oil. 

14.5.1 Identification of Potential 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 NOx control technologies are discussed in 

Section 4.0. Potential control technologies for NOx emissions are the following:

• Good Combustion Practices 

• Emergency Generator Classification 

• Selective Catalytic Reduction (SCR) 

• Non Selective Catalytic Reduction (NSCR) 
Minnesota Steel Page - 338 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

14.5.2 Elimination of Technically Infeasible NOx Control Options 

Table 14-7 summarizes the technical feasibility of control technologies for NOx emissions from 

emergency generators. NSCR control technology is technically infeasible. Diesel engines are leanburn engines with an oxygen rich exhaust. Only rich burn engines can be controlled by NSCR due to 

the need for an oxygen lean exhaust. The remaining 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 

NOx control technologies applicable to emergency generators are ranked based on control 

effectiveness in Table 14-8 
Minnesota Steel Page - 339 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Table 14-8 Ranking of Remaining NOx Control Technologies for 

Emergency Generators and Pumps 

NOx 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 Technologies and Document 

Results 

An hours of operation limitation combined with Good Combustion Practices is the top control 

technology for emergency generators and pumps. Control costs are 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, Emergency Generator Classification combined with Good 

Combustion Practices is BACT for control of NOx emissions. 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 Page - 340 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

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 Generators 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 various VOC and CO control technologies are discussed 

in Section 4.0. Potential control technologies for VOC and CO emissions are the following:

• Good Combustion Practices 

• Emergency Generator Classification 

• Oxidation Catalyst 

14.6.2 Elimination of Technically Infeasible VOC and CO Control Options 

Table 14-10 summarizes the technical feasibility of VOC and CO control technologies for emissions 

from emergency generators. All identified 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 
Minnesota Steel Page - 341 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

14.6.3 Ranking of Remaining VOC and CO Control Technologies by Control 

Effectiveness 

VOC and CO control technologies applicable to emergency generators are ranked 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, Emergency Generator Classification combined with Good 
Minnesota Steel Page - 342 Emergency Generators & Pumps 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Combustion Practices is BACT for control of VOC and CO emissions. 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. 
Minnesota Steel Page - 343 Fugitive Dust 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

15.0 Fugitive Dust 

15.1 Fugitive Dust Process Description 

Fugitive dust emissions are particulate 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 material 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/PM10 BACT Selection 

Minnesota Steel will follow industry best practices for controlling fugitive dust emissions. 

Minnesota Steel’s fugitive dust control plan is located in Appendix O of the BACT report. The 

control plan describes the measures Minnesota Steel will take to control dust emissions. Dust control 

measures listed in the plan are consistent with dust control techniques used by other mining facilities 

in the area. 

The proposed dust control measures selected are based on control effectiveness and the practicality 

of implementing such measures at each particular fugitive dust source taking into account location, 

availability water or other dust suppressants, weather, nature of the mining equipment used and the 

type of operation being performed. 

The RBCL clearinghouse information for these sources is summarized in Attachment L, Tables 31, 

32 and 33 for fugitive dust sources and in Tables L-35 and 36 for slag handling. 
Minnesota Steel Page - 344 Fugitive Dust 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

Minnesota Steel will follow BACT operating practices for controlling fugitive 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 emissions will occur as a result of equipment 

startup/shutdown. No special permit conditions are needed for startup and shutdown of fugitive emission 

sources. 

15.3 Fugitive Dust Visible Emissions 

Visible emission associated with fugitive dust emissions 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/PM10 BACT. 

For fugitive dust sources, PM/PM10 emissions are controlled by the fugitive dust management plan. 

The proposed opacity limits for fugitive 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 corrective action under the fugitive dust management plan as 
Minnesota Steel Page - 345 Fugitive Dust 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

soon as it is practicable to do so. The proposed opacity limits are consistent with recent RBLC 

determinations for fugitive dust sources in the 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 fugitive 

dust and material handling equipment 

15.4 Fugitive Fluoride Dust (F-) BACT Selection 

Fluoride salts are present in trace quantities in the iron ore used at Minnesota Steel. It is emitted as a 

particulate along with dust emitted from fugitive sources. Minnesota Steel will follow industry best 

practices for controlling fugitive dust emissions to control F- 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. Dust 

control measures selected are based on control effectiveness and the practicality of implementing 

such measures at each particular fugitive dust source taking into account location, availability water 

or other dust suppressants, weather, nature of the mining equipment used and the type of operation 

being performed. 

Minnesota Steel will follow BACT operating practices for 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 startup/shutdown. No special permit conditions are 

needed for startup and shutdown of fugitive emission sources. 
Minnesota Steel Page - 346 Fugitive Dust 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

The RBCL clearinghouse information for these sources is summarized in Attachment L, Table 13 for 

material handling and fugitive dust control, and Attachment L, Table 14 for slag handling. 

15.5 Fugitive Lead (Pb) Dust BACT Selection 

Lead salts are present in trace quantities 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 controlling 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 these emissions. Dust control measures listed in the 

plan are consistent with dust control techniques used 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 fugitive dust source taking into account location, availability water 

or other dust suppressants, weather, nature of the mining equipment used and the type of operation 

being performed. The fugitive dust control measures 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 for 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 fugitive emissions will occur as a result of equipment 

startup/shutdown. No special permit conditions are needed for startup and shutdown of fugitive emission 

sources. 
Minnesota Steel Page - 347 Insignificant Activities 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

16.0 Insignificant Activities 

16.1 Insignificant Activities Process Description 

Insignificant activities are small sources with low emissions rates that have negligible impacts on the 

environment (e.g. water heaters). The Minnesota Pollution Control 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 associated with mining activities 

 Material handling and material storage 

 Cooling Towers 

 Diesel powered emergency generators and pumps 

 Diesel and gasoline storage tanks 

 Space heaters 

16.2 Insignificant Actives Addressed within the 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 

\\CORPDATA\new projects\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 2007)\Appendix C -

BACT\BACT Report Updated May 3.doc 

16.3 Insignificant Activities Requiring Review 

Petroleum Storage Tanks 

Minnesota Steel will have two 900,000 gallon diesel storage tanks and one 10,000 gasoline storage 

tank. They are sources of VOC emissions. These tanks will be used to supply the fuels needed to 

operate mobile equipment 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 tanks have low VOC emission rates. No VOC emission 

controls are required for diesel storage tanks under New Source Performance Standards (40 CFR 

Part 60) or Maximum Achievable Control Technology (40 CFR Part 63) standards. 

No VOC emission controls are recommended as BACT for the gasoline storage tank. At 10,000 

gallons, the gasoline tank is relatively small. So, installation of VOC controls would not be cost 

effective. The proposed gasoline storage tank is one half of the de minimus size (20,0000 gallons) 

for tanks requiring emission controls 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 MACT 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 space 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 heaters 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 controls to be cost effective. In Section 9.17, low 

NOx burners are recommended as BACT for the Degassing Boiler. If low NOx burners are 

commercially available for space heaters, they should be considered as BACT for NOx control. 
Attachment A 

Indurator Hood Exhaust 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment A - Emission Control Cost AnalysisTable A-1: Cost Summary - Indurator Hood Exhaust

PM/PM10 Control Cost Summary *

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Incremental Control Cost $/ton Air Toxic's & AQRV's? Energy Impacts? 

Wet Scrubber 0.012 

gr/dscf 177.5 1058.8 $3,299,221 $1,648,867 $1,061 NA None High W

Dry ElectroStatic Precipitator (ESP)

0.012 

gr/dscf 177.5 1058.8 $8,890,668 $1,894,712 $1,789 NA None Low 

Wet Wall ElectroStatic Precipitator (WWESP)

0.012 

gr/dscf 177.5 1058.8 $21,923,877 $4,238,597 $4,003 NA None Low W

Uncontrolled 0% 1236.3* Based on highest emission rate if PM not equal to PM10

SO2 Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Absorber 90.0% 13.4 120.3 $15,113,965 $2,703,203 $22,475 NA WESP is inferior control None Low W

Baghouse w/Dry Scrubber 85.0% 20.0 113.6 $32,876,241 $5,637,085 $49,625 $209,293 None Low Wet Wall ElectroStatic Precipitator (WWESP) 80.0% 26.7 106.9 $21,923,877 $4,238,597 $39,646 NA None Low WUncontrolled 0% 133.6

NOx Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

LoTOx 60% 244.2 366.3 $19,139,941 $6,661,302 $18,183 NA None Medium W

Uncontrolled 0% 610.6

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 A - Hood Exhaust Mar 2007 RevisionCost Summary 3/8/2007 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment A - Emission Control Cost AnalysisTable A-1: Cost Summary - Indurator Hood Exhaust

Sulfuric Acid Mist Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Absorber 90% 0.1 1.0 $15,113,965 $2,703,203 $2,727,229 NA WESP is inferior control None Low W

Baghouse w/Dry Scrubber 90% 0.1 1.0 $32,876,241 $5,637,085 $5,687,189 NA None Low Wet Wall ElectroStatic Precipitator (WWESP) 90% 0.1 1.0 $21,923,877 $4,238,597 $4,276,271 NA None Low WWet Scrubber (PM) 50% 0.6 0.6 $3,299,221 $1,648,867 $2,040,224 NA None High WUncontrolled 0% 1.1

Fluoride Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Absorber 93% 4.8E-02 6.4E-01 $15,113,965 $2,703,203 $4,217,690 NA WESP is inferior control None Low W

Baghouse w/Dry Scrubber 93% 4.8E-02 6.4E-01 $32,876,241 $5,637,085 $8,795,300 NA None Low Wet Wall ElectroStatic Precipitator (WWESP) 93% 4.8E-02 6.4E-01 $21,923,877 $4,238,597 $6,613,300 NA None Low Wuncontrolled 0% 6.9E-01

Lead Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Wet Scrubber 93% 4.9E-02 6.6E-01 $3,299,221 $1,648,867 $2,509,625 NA None High W

Dry ElectroStatic Precipitator (ESP) 93% 4.9E-02 6.6E-01 $8,890,668 $1,894,712 $2,883,810 NA None Low Wet Wall ElectroStatic Precipitator (WWESP) 93% 4.9E-02 6.6E-01 $21,923,877 $4,238,597 $6,451,274 NA None Low WUncontrolled 0% 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 Summary

Pollutant Control Eff % Annualized Operating Cost $/yr Pollution Control Cost $/ton Incremental Operating Cost $/yr Incremental Control Cost $/ton

Particulate Matter (PM) 0.012 gr/dscf $1,648,867 $1,061 Base Case Base Case

Sulfur Dioxide (SO2) 90% $2,703,203 $22,475 $1,054,336 $8,766

Nitrogen Oxides (NOx) 60% $6,661,302 $18,183 $3,958,099 $10,804

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 A - Hood Exhaust Mar 2007 RevisionCost Summary 3/8/2007 
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 Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 500 $/ft3 Cormetech, Inc.

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual 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

acfm basis 250°F process equipment exhaust

temperature

Standardized Flow Rate 515,557 scfm @ 68o F

Dry Std Flow Rate 467,095 dscfm @ 68o F

Max Emis

Pollutant Lb/Hr 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 (SO2) 8 ppm 36.2

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 unit

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 2007)\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/Hr 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 (SO2) 133.6 36.2 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 water 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 ft2 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 control efficiencies.

13 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance 

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 A - Hood Exhaust Mar 2007 Revision

PM-Pb-SO2-SA-F- Wet ESP 3/8/2007 Page 4 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

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 Management

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% utilization 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

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 A - Hood Exhaust Mar 2007 Revision

PM-Pb-SO2-SA-F- Wet ESP 3/8/2007 Page 5 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

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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft2

1.94E-03 kW/ft2294.7 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 Disch 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 $/ft2 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 Neutralization 1.64 $/mgal 141.6 gpm 62,776 102,896 $/mgal, 142 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 A - Hood Exhaust Mar 2007 Revision

PM-Pb-SO2-SA-F- Wet ESP 3/8/2007 Page 6 of 21
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/Hr 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 (SO2) 133.6 36.2 133.6 - 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 inflation.

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 ft2 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 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 A - Hood Exhaust Mar 2007 Revision

PM-Pb Dry ESP 3/8/2007 Page 7 of 21
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 Management

Electricity 0.05 $/kwh, 857 kW-hr, 7946 hr/yr, 93% utilization 320,622

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, 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

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 A - Hood Exhaust Mar 2007 Revision

PM-Pb Dry ESP 3/8/2007 Page 8 of 21
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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft2

1.94E-03 kW/ft2294.7 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 Disch 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 $/ft2 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 A - Hood Exhaust Mar 2007 Revision

PM-Pb Dry ESP 3/8/2007 Page 9 of 21
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/Hr 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 (SO2) 133.6 36.2 133.6 - 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 = 444, 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 control efficiencies.

5 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance 

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 A - Hood Exhaust Mar 2007 Revision

PM-PB Wet Scrubber 3/8/2007 Page 10 of 21
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment A - Emission Control Cost Analysis

Table A-5: PM Control - Wet Scrubber

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 Management

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% utilization 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

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 A - Hood Exhaust Mar 2007 Revision

PM-PB Wet Scrubber 3/8/2007 Page 11 of 21
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 $/ft3

Amount Required 0 ft3

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 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, 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 Neutralization 1.64 $/mgal 141.6 gpm 62,776 102,896 $/mgal, 142 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 A - Hood Exhaust Mar 2007 Revision

PM-PB Wet Scrubber 3/8/2007 Page 12 of 21
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/Hr 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 (SO2) 133.6 36.2 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 Chapter 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 per 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 SO2 removed

8 The 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 A - Hood Exhaust Mar 2007 Revision

SO2-SA-F- BH Dry Scrub 3/8/2007 Page 13 of 21
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 Management

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

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 A - Hood Exhaust Mar 2007 Revision

SO2-SA-F- BH Dry Scrub 3/8/2007 Page 14 of 21
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 $/ft3

Amount Required 0 ft3

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 Labor 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 Cost 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 ft2 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 ft2

Cages 10 ft long 5 in dia 13.42 area/cage ft2 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 A - Hood Exhaust Mar 2007 Revision

SO2-SA-F- BH Dry Scrub 3/8/2007 Page 15 of 21
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) 6,869,984

 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/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) 165.2 610.6 610.6 - NA

Sulfur Dioxide (SO2) 133.6 36.2 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 control efficiencies.

7 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance 

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 A - Hood Exhaust Mar 2007 Revision

SO2-SA-F- Absorber 3/8/2007 Page 16 of 21
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% 6,869,984

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 Management

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% utilization 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

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 A - Hood Exhaust Mar 2007 Revision

SO2-SA-F- Absorber 3/8/2007 Page 17 of 21
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 $/ft3

Amount Required 0 ft3

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 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, 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 Neutralization 1.64 $/mgal 141.6 gpm 62,776 102,896 $/mgal, 142 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 A - Hood Exhaust Mar 2007 Revision

SO2-SA-F- Absorber 3/8/2007 Page 18 of 21
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 Rate 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

Pollutant 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 (SO2) 133.6 36.2 133.6 - 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 = 444, 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 

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 A - Hood Exhaust Mar 2007 Revision

NOx LoTOx 3/8/2007 Page 19 of 21
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 Cost 19,139,941

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 Management

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 assumptions

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 A - Hood Exhaust Mar 2007 Revision

NOx LoTOx 3/8/2007 Page 20 of 21
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 LoTOx8

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 500 $/ft3

Amount Required 0 ft3

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 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, 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 O3 1,339

Total 2591.3

Reagent Use & Other Operating Costs

Ozone Needed 1.8 lb O3/lb NOx lb/hr O3 297.4

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 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 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 Neutralization 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 ft3 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

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 A - Hood Exhaust Mar 2007 Revision

NOx LoTOx 3/8/2007 Page 21 of 21
Attachment B 

Indurator Waste Gas Stack 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment B - Emission Control Cost AnalysisTable B-1: Cost Summary - Indurator Waste Gas Exhaust

PM/PM10 Control Cost Summary *

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Incremental Control Cost $/ton Air Toxic's & AQRV's? Energy Impacts? 

Wet Scrubber 0.012 

gr/dscf 120.1 1116.2 $2,609,897 $1,246,444 $729 NA None High W

Dry ElectroStatic Precipitator (ESP)

0.012 

gr/dscf 120.1 1116.2 $7,033,094 $1,450,822 $1,300 NA None Low 

Wet Wall ElectroStatic Precipitator (WWESP)

0.012 

gr/dscf 120.1 1116.2 $17,343,207 $3,459,351 $3,099 NA None Low W

Uncontrolled 0% 1236.3* Based on highest emission rate if PM not equal to PM10

SO2 Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Absorber 90.0% 38.0 342.3 $11,956,125 $2,108,175 $6,158 NA WESP is inferior control None Low W

Baghouse w/Dry Scrubber 85.0% 57.1 323.3 $26,007,235 $4,419,559 $13,670 -$50,490 None Low Wet Wall ElectroStatic Precipitator (WWESP) 90.0% 38.0 342.3 $17,343,207 $3,459,351 $10,106 NA None Low WUncontrolled 0% 380.4

NOx Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

LoTOx 90% 171.4 1543.0 $18,710,779 $7,330,492 $4,751 NA None Medium W

Uncontrolled 0% 1714.5

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 B - Indurator Waste Gas Mar 2007 RevisionCost Summary 3/13/2007 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment B - Emission Control Cost AnalysisTable B-1: Cost Summary - Indurator Waste Gas Exhaust

Sulfuric Acid Mist Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Absorber 90% 0.3 2.8 $11,956,125 $2,108,175 $747,294 NA WESP is inferior control None Low W

Baghouse w/Dry Scrubber 90% 0.3 2.8 $26,007,235 $4,419,559 $1,566,620 #DIV/0! None Low Wet Wall ElectroStatic Precipitator (WWESP) 90% 0.3 2.8 $17,343,207 $3,459,351 $1,226,251 NA None Low WUncontrolled 0% 3.1

Fluoride Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Absorber 95% 9.2E-01 1.7E+01 $11,956,125 $2,108,175 $121,264 NA WESP is inferior control None Low W

Baghouse w/Dry Scrubber 95% 9.2E-01 1.7E+01 $26,007,235 $4,419,559 $254,216 $349,802 None Low Wet Wall ElectroStatic Precipitator (WWESP) 80% 3.7E+00 1.5E+01 $17,343,207 $3,459,351 $236,294 NA None Low Wuncontrolled 0% 1.8E+01

Lead Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions 

T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Wet Scrubber 95% 4.9E-02 9.4E-01 $2,609,897 $1,246,444 $1,326,561 NA None High W

Dry ElectroStatic Precipitator (ESP) 95% 4.9E-02 9.4E-01 $7,033,094 $1,450,822 $1,544,076 NA None Low Wet Wall ElectroStatic Precipitator (WWESP) 95% 4.9E-02 9.4E-01 $17,343,207 $3,459,351 $3,681,707 NA None Low WUncontrolled 0% 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 Summary

Pollutant Control Eff % 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 (SO2) 90% $2,108,175 $6,158 $861,731 $2,517

Nitrogen Oxides (NOx) 90% $7,330,492 $4,751 $5,222,317 $3,384

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 B - Indurator Waste Gas Mar 2007 RevisionCost Summary 3/13/2007 
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 Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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

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 $/ft3 Cormetech, Inc.

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual 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

acfm basis 250°F process equipment exhaust

temperature

Standardized Flow Rate 348,843 scfm @ 68o F

Dry Std Flow Rate 316,052 dscfm @ 68o F

Max Emis

Pollutant Lb/Hr 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 (SO2) 33 ppm 102.9

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 unit

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 2007)\Attachments\Attach B - Indurator Waste Gas Mar 2007 Revision

Utility Chem$ Data 3/13/2007 Page 3 of 21
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/Hr 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 (SO2) 380.4 102.9 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 water 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 ft2 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 control efficiencies.

13 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance 

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 B - Indurator Waste Gas Mar 2007 Revision

PM-Pb-SO2-SA-F- Wet ESP 3/13/2007 Page 4 of 21
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 Management

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% utilization 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

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 B - Indurator Waste Gas Mar 2007 Revision

PM-Pb-SO2-SA-F- Wet ESP 3/13/2007 Page 5 of 21
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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft2

1.94E-03 kW/ft2199.4 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 Disch 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 $/ft2 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 Neutralization 1.64 $/mgal 95.8 gpm 42,476 69,623 $/mgal, 96 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 B - Indurator Waste Gas Mar 2007 Revision

PM-Pb-SO2-SA-F- Wet ESP 3/13/2007 Page 6 of 21
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) 3,139,774

 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 7,033,094

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/Hr 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 (SO2) 380.4 102.9 380.4 - 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 inflation.

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 ft2 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 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 B - Indurator Waste Gas Mar 2007 Revision

PM-Pb Dry ESP 3/13/2007 Page 7 of 21
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% 3,139,774

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 7,033,094

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,033,094

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 Management

Electricity 0.05 $/kwh, 580 kW-hr, 7946 hr/yr, 93% utilization 216,943

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, 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

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 B - Indurator Waste Gas Mar 2007 Revision

PM-Pb Dry ESP 3/13/2007 Page 8 of 21
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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft2

1.94E-03 kW/ft2199.4 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 Disch 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 $/ft2 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 B - Indurator Waste Gas Mar 2007 Revision

PM-Pb Dry ESP 3/13/2007 Page 9 of 21
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) 1,246,444

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 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 (SO2) 380.4 102.9 380.4 - 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 = 444, 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 control efficiencies.

5 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance 

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 B - Indurator Waste Gas Mar 2007 Revision

PM-PB Wet Scrubber 3/13/2007 Page 10 of 21
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 2,131,644

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 Management

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% utilization 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) 1,246,444

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 2007)\Attachments\Attach B - Indurator Waste Gas Mar 2007 Revision

PM-PB Wet Scrubber 3/13/2007 Page 11 of 21
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 $/ft3

Amount Required 0 ft3

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 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, 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 Neutralization 1.64 $/mgal 95.8 gpm 42,476 69,623 $/mgal, 96 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 B - Indurator Waste Gas Mar 2007 Revision

PM-PB Wet Scrubber 3/13/2007 Page 12 of 21
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/Hr 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 (SO2) 380.4 102.9 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 Chapter 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 per 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 SO2 removed

8 The 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 B - Indurator Waste Gas Mar 2007 Revision

SO2-SA-F- BH Dry Scrub 3/13/2007 Page 13 of 21
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 Management

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

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 B - Indurator Waste Gas Mar 2007 Revision

SO2-SA-F- BH Dry Scrub 3/13/2007 Page 14 of 21
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 $/ft3

Amount Required 0 ft3

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 Labor 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 Cost 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 ft2 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 ft2

Cages 10 ft long 5 in dia 13.42 area/cage ft2 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 B - Indurator Waste Gas Mar 2007 Revision

SO2-SA-F- BH Dry Scrub 3/13/2007 Page 15 of 21
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/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) 464.0 1,714.5 1714.5 - NA

Sulfur Dioxide (SO2) 380.4 102.9 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 control efficiencies.

7 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance 

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 B - Indurator Waste Gas Mar 2007 Revision

SO2-SA-F- Absorber 3/13/2007 Page 16 of 21
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 Management

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% utilization 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

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 B - Indurator Waste Gas Mar 2007 Revision

SO2-SA-F- Absorber 3/13/2007 Page 17 of 21
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 $/ft3

Amount Required 0 ft3

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 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, 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 Neutralization 1.64 $/mgal 95.8 gpm 42,476 69,623 $/mgal, 96 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 ft3 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

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 B - Indurator Waste Gas Mar 2007 Revision

SO2-SA-F- Absorber 3/13/2007 Page 18 of 21
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 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) 4,375,224

 Purchased Equipment Total (B) 22% of control device cost (A) 5,315,898

 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) 1,860,564

Total Capital Investment (TCI) = DC + IC 18,710,779

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) 7,330,492

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 334.6 1,236.3 1236.3 - NA

Total Particulates 1,236. 334.6 1236. 3 3 N - A

Nitrous Oxides (NOx) 464.0 1,714.5 90% 171.4 1,543.0 4,751 

Sulfur Dioxide (SO2) 380.4 102.9 380.4 - 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 - 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 = 444, 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 

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 B - Indurator Waste Gas Mar 2007 Revision

NOx LoTOx 3/13/2007 Page 19 of 21
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) 437,522

MN Sales Taxes 6.5% of control device cost (A) 284,390

Freight 5% of control device cost (A) 218,761

Purchased Equipment Total (B) 22% 5,315,898

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) 53,159

Piping 30% of purchased equip cost (B) 1,594,769

Insulation 1% of purchased equip cost (B) 53,159

Painting 1% of purchased equip cost (B) 53,159

Installation Subtotal Standard Expenses 85% 4,518,513

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 4,518,513

Total Direct Capital Cost, DC 9,834,411

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 531,590

Construction & field expenses 10% of purchased equip cost (B) 531,590

Contractor fees 10% of purchased equip cost (B) 531,590

Start-up 1% of purchased equip cost (B) 53,159

Performance test 1% of purchased equip cost (B) 53,159

Model Studies NA 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 18,710,779

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 18,710,779

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 Management

Electricity 0.05 $/kwh, 4,606 kW-hr, 7946 hr/yr, 93% utilization 1,723,166

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 - 

NA NA - 

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 Costs 4,785,860

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 Costs Sum indirect oper costs + capital recovery cost 2,544,632

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,330,492

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 2007)\Attachments\Attach B - Indurator Waste Gas Mar 2007 Revision

NOx LoTOx 3/13/2007 Page 20 of 21
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 LoTOx8

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 500 $/ft3

Amount Required 0 ft3

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 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, Scrubber 469,275 10 0.7 - 784.4 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

LTO Electric Use 4.5 kW/lb O3 3,758

Total 4606.1

Reagent Use & Other Operating Costs

Ozone Needed 1.8 lb O3/lb NOx lb/hr O3 835.2

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 ratio 10.0 * L/G = Gal/1,000 acf

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 925,808 248,729 $/mgal, 2,088 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 Neutralization 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 25.309984 $/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 93.7 Mscf/hr 692,427 998,480 Mscf, 94 Mscf/hr, 7946 hr/yr, 93% utilization

SCR Catalyst 500 $/ft3 0 ft3 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

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 B - Indurator Waste Gas Mar 2007 Revision

NOx LoTOx 3/13/2007 Page 21 of 21
Attachment C 

DRI Package Boiler 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost AnalysisTable C-1: Cost Summary - DRI Package Boiler

NOx Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

LoTOx 70% 9.4 22.0 $724,544 $619,859 $28,142 NA LoTOx is inferior control None 

Selective Catalytic Reduction (SCR) 70% 9.4 22.0 $1,676,449 $449,601 $20,412 $90,207 NH3 SliULNB / LNB-FGR 56% 13.8 17.7 $429,399 $59,310 $3,351 NA None Selective Non-Catalytic Reduction (SNCR) 25% 23.6 7.9 $861,742 $217,176 $27,608 NA SNCR is inferior control NH3 Sli

Base Case NA 31.5

CO Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

Thermal OxidizerRecuperative 90% 3.2 29.2 $622,596 $851,566 $29,194 NA None Thermal OxidizerRegenerative 90% 3.2 29.2 $801,987 $595,648 $20,420 NA None Catalytic Oxidizer 90% 3.2 29.2 $764,279 $479,750 $16,447 NA None 

Uncontrolled 0% 32.4

VOC Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

Thermal OxidizerRecuperative 90% 0.21 1.9 $622,596 $851,566 $446,128 NA None Thermal OxidizerRegenerative 90% 0.21 1.9 $801,987 $595,648 $312,055 NA None Catalytic Oxidizer 90% 0.21 1.9 $764,279 $479,750 $251,337 NA None 

Uncontrolled 0% 2.1

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 C - DRCost Summary 3/6/2007 
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 Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 140 $/ft3 Cormetech, Inc., 1/2006 bid

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual 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

Pollutant 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 (SO2) 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 unit 61 Base Case ppm NOx dry

Enter data for this study (applies to all units) 31.5 T/yr NOx Base Case

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 C - DRI Package Boiler Mar 2007 Revision

Utility Chem$ Data 3/6/2007 Page 2 of 27
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 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) 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

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 - NA

Nitrous Oxides (NOx) 7.9 31.5 56% 13.8 17.7 3,351 

Sulfur Dioxide (SO2) 0.2 0.1 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 - NA

Notes & Assumptions

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

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 C - DRI Package Boiler Mar 2007 Revision

 NOx ULNB 3/6/2007 Page 3 of 27
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 Expenses 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 Cost 429,399

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

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 Management

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 - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 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 Costs 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 assumptions

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 C - DRI Package Boiler Mar 2007 Revision

 NOx ULNB 3/6/2007 Page 4 of 27
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: Catalyst

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 650 $/ft3

Amount Required 39 ft3

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

Annualized 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 - 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 0.01 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

Maintenance

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 Neutralization 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 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 Catalyst 650 $/ft3 0 ft3 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

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 C - DRI Package Boiler Mar 2007 Revision

 NOx ULNB 3/6/2007 Page 5 of 27
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 EU 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 35% 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

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 - NA

Nitrous Oxides (NOx) 7.9 31.5 70% 9.4 22.0 28,142 

Sulfur Dioxide (SO2) 0.2 0.1 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 - 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 MN Steel Industries September 2006 Water Balance 

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 C - DRI Package Boiler Mar 2007 Revision

NOx LoTOx 3/6/2007 Page 6 of 27
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 Expenses 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 NA 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 Cost 724,544

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 Management

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 - 

NA NA - 

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 Costs 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 Costs 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 assumptions

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 C - DRI Package Boiler Mar 2007 Revision

NOx LoTOx 3/6/2007 Page 7 of 27
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 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 $/ft3

Amount Required 0 ft3

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 36.8358272 $ 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

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency 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 O3 64

Total 133.3

Reagent Use & Other Operating Costs

Ozone Needed 1.8 lb O3/lb NOx lb/hr O3 14.3

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 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 0.051 $/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 Neutralization 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 Catalyst 140 $/ft3 0 ft3 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

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 C - DRI Package Boiler Mar 2007 Revision

NOx LoTOx 3/6/2007 Page 8 of 27
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 EU 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) NA

 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 1,676,449

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

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 - NA

Nitrous Oxides (NOx) 7.9 31.5 70% 9.4 22.0 20,412 

Sulfur Dioxide (SO2) 0.2 0.1 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 - NA

Notes & Assumptions

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.

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 C - DRI Package Boiler Mar 2007 Revision

NOx SCR PwrPlt 3/6/2007 Page 9 of 27
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) 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 1,676,449

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,633,094

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 Management

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 - 

CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 100% utilization 16,521

NA NA - 

Total Annual Direct Operating Costs 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 Costs 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 assumptions

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 C - DRI Package Boiler Mar 2007 Revision

NOx SCR PwrPlt 3/6/2007 Page 10 of 27
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: Catalyst 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 $/ft3 Flow #2 37,543 acfm

Amount Required 522.5 ft3 Vol #2 522.5 ft3

Catalyst Cost 37,700 Cost adjusted for freight & sales tax

Installation Labor 5,655 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 43,355 Zero out if no replacement parts needed

Annualized 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

Annualized 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 Catalytic (catalytic or thermal) 168.4

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 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 0.051 $/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 Neutralization 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 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 Catalyst 650 $/ft3 0 ft3 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 assumptions

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 C - DRI Package Boiler Mar 2007 Revision

NOx SCR PwrPlt 3/6/2007 Page 11 of 27
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

Annual 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.

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 C - DRI Package Boiler Mar 2007 Revision

NOx SCR PwrPlt 3/6/2007 Page 12 of 27
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 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 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

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 - NA

Nitrous Oxides (NOx) 7.9 31.5 25% 23.6 7.9 27,608 

Sulfur Dioxide (SO2) 0.2 0.1 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 - NA

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 1.19 

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

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 C - DRI Package Boiler Mar 2007 Revision

NOx SNCR 3/6/2007 Page 13 of 27
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) NA

MN Sales Taxes 6.5% of control device cost (A) NA

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

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 861,742

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 861,742

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 15.00 % of Total Capital Investment 129,261

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

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 - 

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 5,115

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 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 Costs Sum indirect oper costs + capital recovery cost 81,342

Total Annual Cost (Annualized Capital Cost + Operating Cost) 217,176

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 C - DRI Package Boiler Mar 2007 Revision

NOx SNCR 3/6/2007 Page 14 of 27
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 Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 140 $/ft3

Amount Required 12 ft3

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 Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 37 $/ft3

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 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/ft3 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

Ash Generation 0.2 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 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 Neutralization 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 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 Catalyst 140 $/ft3 0 ft3 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 assumptions

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 C - DRI Package Boiler Mar 2007 Revision

NOx SNCR 3/6/2007 Page 15 of 27
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 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 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

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 - NA

Nitrous Oxides (NOx) 7.9 31.5 31.5 - NA

Sulfur Dioxide (SO2) 0.2 0.1 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 - NA

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 

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 C - DRI Package Boiler Mar 2007 Revision

CO-VOC Therm Ox 3/6/2007 Page 16 of 27
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 Cost 622,596

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 Management

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 - 

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 Costs 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 Costs 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 assumptions

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 C - DRI Package Boiler Mar 2007 Revision

CO-VOC Therm Ox 3/6/2007 Page 17 of 27
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: Catalyst

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 650 $/ft3

Amount Required 39 ft3

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

Annualized 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 - 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 0.051 $/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 Neutralization 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 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 Catalyst 650 $/ft3 0 ft3 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

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 C - DRI Package Boiler Mar 2007 Revision

CO-VOC Therm Ox 3/6/2007 Page 18 of 27
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 

Twi 356 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 947 Deg F - Temperature of waste gas out of heat recovery

Tfo 609 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 24,282 scfm - Flow of waste gas 

Qaf 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 Incinerators

 (EPA 453/B-96-001)

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 C - DRI Package Boiler Mar 2007 Revision

CO-VOC Therm Ox 3/6/2007 Page 19 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost Analysis

Table C-8: CO/VOC Control - Catalytic Oxidizer

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 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) 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 - NA

Nitrous Oxides (NOx) 7.9 31.5 31.5 - NA

Sulfur Dioxide (SO2) 0.2 0.1 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 - 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 inflation

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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 C - DRI Package Boiler Mar 2007 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 20 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost Analysis

Table C-8: CO/VOC Control - Catalytic Oxidizer

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 expenses 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 Cost 670,874

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 Management

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 - 

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 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 123,933

Total Annual Cost (Annualized Capital Cost + Operating Cost) 479,750

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 2007)\Attachments\Attach C - DRI Package Boiler Mar 2007 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 21 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost Analysis

Table C-8: 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 $/ft3

Amount Required 24 ft3

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 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 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 catalytic (catalytic or thermal) 168.4

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 0.051 $/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 Neutralization 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 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 Catalyst 650 $/ft3 0 ft3 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 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 2007)\Attachments\Attach C - DRI Package Boiler Mar 2007 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 22 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost Analysis

Table C-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 

Twi 356 Deg F - Temperature of waste gas into heat recovery

Tfi 600 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 527 Deg F - Temperature of waste gas out of heat recovery

Tfo 429 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 24,282 scfm - Flow of waste gas 

Qaf 66 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 24,348 scfm Flue Gas Cost in 1989 $'s $266,593

Current Cost Using CHE Plant Cost Index $317,861

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)

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 C - DRI Package Boiler Mar 2007 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 23 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost Analysis

Table C-9 CO/VOC Control - Regenerative Thermal Oxidizer

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 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)

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 + IC 801,987

Operating Costs

 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 Cost 595,648

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 2.9 0.7 2.9 - NA

Nitrous Oxides (NOx) 7.9 31.5 31.5 - NA

Sulfur Dioxide (SO2) 0.2 0.1 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 & Assumptions

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

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 C - DRI Package Boiler Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 24 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost Analysis

Table C-9 CO/VOC Control - Regenerative Thermal Oxidizer

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 Total 149,439

Total Direct Capital Cost, DC 647,567

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 49,813

Construction & field expenses 5% of purchased equip cost (B) 24,906

Contractor fees 10% of purchased equip cost (B) 49,813

Start-up 2% of purchased equip cost (B) 9,963

Performance test 1% of purchased equip cost (B) 4,981

Model Studies 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 + IC 801,987

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cos 801,987

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 Management

Electricity 0.05 $/kwh, 168 kW-hr, 7946 hr/yr, 100% utilization 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 Costs 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 Costs Sum indirect oper costs + capital recovery cos 137,817

Total Annual Cost (Annualized Capital Cost + Operating Cost 595,648

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 2007)\Attachments\Attach C - DRI Package Boiler Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 25 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost Analysis

Table C-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 $/ft3

Amount Required 0 ft3

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 Labor 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 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 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 Type catalytic (catalytic or thermal) 168.4

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 0.051 $/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% utilization

Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization

WW Treat Neutralization 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 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 Catalyst 650 $/ft3 0 ft3 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 facto

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 2007)\Attachments\Attach C - DRI Package Boiler Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 26 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment C - Emission Control Cost Analysis

Table C-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 

Twi 356 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 1,116 Deg F - Temperature of waste gas out of heat recovery

Tfo 440 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 24,282 scfm - Flow of waste gas 

Qaf 104 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 24,282 scfm Flue Gas

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerator

 (EPA 453/B-96-001)

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 C - DRI Package Boiler Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 27 of 27
Attachment D 

DRI Process Heater 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost AnalysisTable D-1: Cost Summary - DRI Process Heaters

PM/PM10 Control Cost Summary *

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic'

AQRV's

Wet Scrubber 0.01 

gr/dscf 17.4 17.4 $1,551,775 $777,333 $44,695 $44,695 None 

Baghouse 0.01 gr/dscf 17.4 17.4 $6,913,747 $1,393,567 $80,128 $80,128 None Uncontrolled 0.02 

gr/dscf 34.8

* Based on highest emission rate if PM not equal to PM10

NOx Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic'

AQRV's

LoTOx 70% 57.8 134.8 $3,946,254 $1,807,751 $13,415 NA None 

Selective Catalytic Reduction (SCR) 70% 57.8 134.8 $9,445,459 $1,946,130 $14,442 $45,385 NH3 SliUltra-Low NOx Burners 50% 96.3 96.3 $883,202 $198,792 $2,065 NA None 

Selective Non-Catalytic Reduction (SNCR) 25% 144.4 48.1 $1,854,845 $493,536 $10,255 NA Inferior Control NH3 Sli

Base Case NA 192.5

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 - HYCost Summary 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost AnalysisTable D-1: Cost Summary - DRI Process Heaters

CO Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic'

AQRV's

Thermal OxidizerRecuperative 90% 19.8 178.5 $945,280 $3,892,175 $21,811 NA None Thermal OxidizerRegenerative 90% 19.8 178.5 $2,184,749 $2,555,426 $14,320 NA None Catalytic Oxidizer 90% 19.8 178.5 $1,701,213 $1,917,871 $10,747 NA None 

Uncontrolled 0% 198.3

VOC Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic'

AQRV's

Thermal OxidizerRecuperative 90% 1.30 11.7 $945,280 $3,892,175 $333,309 NA None Thermal OxidizerRegenerative 90% 1.30 11.7 $2,184,749 $2,555,426 $218,835 NA None Catalytic Oxidizer 90% 1.30 11.7 $1,701,213 $1,917,871 $164,238 NA None 

Uncontrolled 0% 13.0

Fluoride Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic'

AQRV's

Wet Scrubber 95% 8.7E-05 1.7E-03 $1,551,775 $777,333 $470,077,600 NA None 

Baghouse 95% 8.7E-05 1.7E-03 $6,913,747 $1,393,567 $842,733,202 NA None 

Uncontrolled 0% 1.7E-03

Lead Control Cost Summary 

Control Technology

Control 

Eff %

Uncontrolled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic'

AQRV's

Wet Scrubber 95% 6.2E-05 1.2E-03 $1,551,775 $777,333 $655,036,285 NA None 

Baghouse 95% 6.2E-05 1.2E-03 $6,913,747 $1,393,567 $1,174,318,507 NA None 

Uncontrolled 0% 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 - HYCost Summary 
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 Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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 & 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 140 $/ft3 Cormetech, Inc., 1/2006 bid

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual 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 

Pollutant Lb/Hr prior to eductor 

PM10 8.76 0.010 gr/dscf

Total Particulates 8.76 0.010 gr/dscf NOx Control Efficiency Calculations

Nitrous Oxides (NOx) 48.5 52 ppmw 24.23 lb/hr NOx at 0.040 lb NOx/MMBtu

Sulfur Dioxide (SO2) 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 unit 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

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 Revision

Utility Chem$ Data 3/6/2007 Page 3 of 34
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%

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) 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

Pollutant Lb/Hr 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 (SO2) 3.0 0.8 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 & Assumptions

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 = 444, 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 actual control efficiencies.

5 Scrubber/WESP evaporative water loss per adiabatic energy balance; H2O heat of vaporization = sensible heat loss in stack gas.

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 Revision

PM-PB Wet Scrubber 3/6/2007 Page 4 of 34
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 Costs

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 Expenses 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 NA 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, 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, 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 Costs 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 Costs 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 assumptions

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 Revision

PM-PB Wet Scrubber 3/6/2007 Page 5 of 34
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 $/ft3

Amount Required 0 ft3

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 37.940902 $ 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

Annualized 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 Costs

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 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 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 Neutralization 1.69 $/mgal 37.3 gpm 17,767 29,995 $/mgal, 37 gpm, 7946 hr/yr, 100% utilization

WW Treat Biotreatemen 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 Catalyst 140 $/ft3 0 ft3 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

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 Revision

PM-PB Wet Scrubber 3/6/2007 Page 6 of 34
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/Hr 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 (SO2) 3.0 0.8 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 Chapter 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 per 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 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 

Revision

PM-PB Baghouse 3/6/2007 Page 7 of 34
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 5,493,114

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 Management

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

NA NA - 

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

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 

Revision

PM-PB Baghouse 3/6/2007 Page 8 of 34
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 $/ft3

Amount Required 0 ft3

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 Labor 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 Cost 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 ft2 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 ft2

Cages 10 ft long 5 in dia 13.42 area/cage ft2 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 Neutralization 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization

WW Treat Biotreatemen 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 ft3 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

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 

Revision

PM-PB Baghouse 3/6/2007 Page 9 of 34
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost Analysis

Table D-5: NOx Control - Ultra Low NOx Burner

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) 451,500

 Purchased Equipment Total (B) 22% of control device cost (A) 548,573

 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 - NA

Nitrous Oxides (NOx) 48.5 192.5 50% 96.3 96.3 2,065 

Sulfur Dioxide (SO2) 3.0 0.8 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 per John Zink burner company email dated 08/03/2006

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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 Revision

NOx- ULNB 3/6/2007 Page 10 of 34
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost Analysis

Table D-5: NOx Control - Ultra Low NOx Burner

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% 548,573

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 713,144

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 54,857

Construction & field expenses 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 Cost 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 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 Management

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 - 

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

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 Revision

NOx- ULNB 3/6/2007 Page 11 of 34
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost Analysis

Table D-5: NOx Control - Ultra Low NOx Burner

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 $/ft3

Amount Required 39 ft3

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 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 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 - 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 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 Neutralization 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization

WW Treat Biotreatemen 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 ft3 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

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 Revision

NOx- ULNB 3/6/2007 Page 12 of 34
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 3,946,254

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/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 - NA

Nitrous Oxides (NOx) 48.5 192.5 70% 57.8 134.8 13,415 

Sulfur Dioxide (SO2) 3.0 0.8 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.

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 

Revision

NOx LoTOx 3/6/2007 Page 13 of 34
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 2,702,384

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 3,946,254

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 3,946,254

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 Management

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

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 

Revision

NOx LoTOx 3/6/2007 Page 14 of 34
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 LoTOx6

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 $/ft3

Amount Required 0 ft3

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 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, 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 O3 392

Total 662.2

Reagent Use & Other Operating Costs

Ozone Needed 1.8 lb O3/lb NOx lb/hr O3 87.2

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 Neutralization 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 ft3 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

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 

Revision

NOx LoTOx 3/6/2007 Page 15 of 34
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) NA

 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/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 - NA

Nitrous Oxides (NOx) 4 192.5 48.5 70% 57.8 134.8 14,442 

Sulfur Dioxide (SO2) 3.0 0.8 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 Mauer

6 SCR catalyst cost $/ft3 per 1/16/2006 Cormetech proposal

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 

Revision

NOx SCR PwrPlt 3/6/2007 Page 16 of 34
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 Management

Electricity 0.05 $/kwh, 154 kW-hr, 7946 hr/yr, 100% utilization 63,759

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 - 

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

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 

Revision

NOx SCR PwrPlt 3/6/2007 Page 17 of 34
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 $/ft3 Flow #2 NA acfm

Amount Required 1367.0 ft3 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/ft3 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 Neutralization 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization

WW Treat Biotreatemen 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 ft3 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

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 

Revision

NOx SCR PwrPlt 3/6/2007 Page 18 of 34
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.

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 

Revision

NOx SCR PwrPlt 3/6/2007 Page 19 of 34
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/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 - NA

Nitrous Oxides (NOx) 10 192.5 48.5 25% 144.4 48.1 10,255 

Sulfur Dioxide (SO2) 3.0 0.8 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

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 

Revision

NOx SNCR 3/6/2007 Page 20 of 34
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 Management

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

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 

Revision

NOx SNCR 3/6/2007 Page 21 of 34
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 $/ft3

Amount Required 12 ft3

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 Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 38 $/ft3

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/ft3 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 Neutralization 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization

WW Treat Biotreatemen 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 ft3 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

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 

Revision

NOx SNCR 3/6/2007 Page 22 of 34
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost Analysis

Table D-9: CO/VOC Control - 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) 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) 3,892,175

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 - NA

Nitrous Oxides (NOx) 48.5 192.5 192.5 - NA

Sulfur Dioxide (SO2) 3.0 0.8 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 - NA

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 

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 Revision

CO-VOC Therm Ox 3/6/2007 Page 23 of 34
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost Analysis

Table D-9: CO/VOC Control - Thermal Oxidizer

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 expenses 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 Cost 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 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 Management

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 - 

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 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 157,075

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,892,175

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 2007)\Attachments\Attach D - HYL DRI Heater Sept 2006 Revision

CO-VOC Therm Ox 3/6/2007 Page 24 of 34
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost Analysis

Table D-9: 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 $/ft3

Amount Required 39 ft3

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 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 thermal (catalytic or thermal) 731.0

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 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 Neutralization 1.69 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 100% utilization

WW Treat Biotreatemen 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 ft3 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

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 Revision

CO-VOC Therm Ox 3/6/2007 Page 25 of 34
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment D - Emission Control Cost Analysis

Table D-9: 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 

Twi 347 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 944 Deg F - Temperature of waste gas out of heat recovery

Tfo 603 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 129,023 scfm - Flow of waste gas 

Qaf 1,036 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 130,059 scfm Flue Gas Cost in 1989 $'s $405,294

Current Cost Using CHE Plant Cost Index $483,235

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)

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 Revision

CO-VOC Therm Ox 3/6/2007 Page 26 of 34
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 + IC 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

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 - NA

Nitrous Oxides (NOx) 48.5 192.5 192.5 - NA

Sulfur Dioxide (SO2) 3.0 0.8 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 inflation

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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 

Revision

CO-VOC Catalytic Ox 3/6/2007 Page 27 of 34
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 Total 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 + IC 1,701,213

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 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 Management

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 Costs 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 Costs 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

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 

Revision

CO-VOC Catalytic Ox 3/6/2007 Page 28 of 34
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 $/ft3

Amount Required 129 ft3

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* 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 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 Biotreatement 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 ft3 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

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 

Revision

CO-VOC Catalytic Ox 3/6/2007 Page 29 of 34
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 

Twi 347 Deg F - Temperature of waste gas into heat recovery

Tfi 600 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 524 Deg F - Temperature of waste gas out of heat recovery

Tfo 423 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 129,023 scfm - Flow of waste gas 

Qaf 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)

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 

Revision

CO-VOC Catalytic Ox 3/6/2007 Page 30 of 34
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 + IC 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

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 - NA

Nitrous Oxides (NOx) 48.5 192.5 192.5 - NA

Sulfur Dioxide (SO2) 3.0 0.8 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

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 

Revision

Regen. Thermal Ox 3/6/2007 Page 31 of 34
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 Total 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 + IC 2,184,749

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 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 Management

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 Costs 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 Costs 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

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 

Revision

Regen. Thermal Ox 3/6/2007 Page 32 of 34
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 $/ft3

Amount Required 0 ft3

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* 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 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 Biotreatement 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 ft3 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

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 

Revision

Regen. Thermal Ox 3/6/2007 Page 33 of 34
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 

Twi 347 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 1,115 Deg F - Temperature of waste gas out of heat recovery

Tfo 432 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 129,023 scfm - Flow of waste gas 

Qaf 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)

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 

Revision

Regen. Thermal Ox 3/6/2007 Page 34 of 34
Attachment E 

DRI Tail Gas Purification System 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment E - Emission Control Cost AnalysisTable E-1: Cost Summary - DRI Top Gas Purification

H2S Control Cost Summary DRI Top Gas Purification

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic'

AQRV's

LoCAT 92.3% 2.5 30.1 $7,373,349 $1,355,047 $45,010 NA None 

Zinc Oxide 92.3% 2.5 30.1 $7,920,532 $2,096,023 $69,622 NA None 

Regenerative Thermal Oxidizer + Absorber - Caustic 92.3% 2.5 30.1 $3,011,277 $1,137,575 $37,786 NA

Collater

NOx 

emissio

Regenerative Thermal Oxidizer 92.3% 2.5 30.1 $1,956,150 $883,916 $29,360 NA

Collateral 

and NO

emissio

Recuperantive Thermal Oxidizer 92.3% 2.5 30.1 $1,467,113 $1,441,107 $47,868 NA

Collateral 

and NO

emissio

Uncontrolled 0% 32.6

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 E - RevisionCost Summary 
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

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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 & 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 140 $/ft3 Cormetech, Inc., 1/2006 bid

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual 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 

Pollutant Lb/Hr prior to eductor 

PM10 0.000 gr/dscf

Total Particulates 0.000 gr/dscf Control Device Outlet Concentration

Nitrous Oxides (NOx) 0 ppmw 0 PPM NOx @ 70% control

Sulfur Dioxide (SO2) 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 unit

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 2007)\Attachments\Attach E - HYL Top Gas Purification Mar 2007 

Revision

Utility Chem$ Data 3/6/2007 Page 2 of 19
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 Rate 100% Temperature 120 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 26,834 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 22,875 scfm @ 68o F

Dry Std Flow Rate 20,473 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,800,000

 Purchased Equipment Total (B) 22% of control device cost (A) 4,617,000

 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) 1,615,950

Total Capital Investment (TCI) = DC + IC 7,373,349

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) 1,355,047

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 - - - NA

Total Particulates - - - NA

Nitrous Oxides (NOx) - - - NA

Sulfur Dioxide (SO2) - - - NA

Sulfuric Acid Mist - - - NA

Fluorides - - - NA

Volatile Organic Compounds (VOC) - - - NA

Carbon Monoxide (CO) - - - NA

Lead (Pb) - - - NA

Hydrogen Sulfide (H2S) 32.6 8.2 92.3% 2.5 30.1 45,010 

Notes & Assumptions

1 Aug 3, 2006 Cost Estimate Gas Technology Products

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 hours or less per day.

6

7

8

9

Notes to User

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 E - HYL Top Gas Purification Mar 2007 Revision

H2S LoCAT 3/6/2007 Page 3 of 19
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) 380,000

MN Sales Taxes 6.5% of control device cost (A) 247,000

Freight 5% of control device cost (A) 190,000

Purchased Equipment Total (B) 22% 4,617,000

Installation

Foundations & supports NA of purchased equip cost (B) NA

Handling & erection NA of purchased equip cost (B) NA

Electrical NA of purchased equip cost (B) NA

Piping NA of purchased equip cost (B) NA

Insulation NA of purchased equip cost (B) NA

Painting NA of purchased equip cost (B) NA

Installation Subtotal Standard Expenses (3) 25% 1,140,399

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 1,140,399

Total Direct Capital Cost, DC 5,757,399

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 461,700

Construction & field expenses 10% of purchased equip cost (B) 461,700

Contractor fees 10% of purchased equip cost (B) 461,700

Start-up 1% of purchased equip cost (B) 46,170

Performance test 1% of purchased equip cost (B) 46,170

Model Studies NA 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 7,373,349

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,373,349

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 Management

Electricity (4) 0.05 $/kwh, 50 kW-hr, 7946 hr/yr, 100% utilization 20,709

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

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 Costs 243,978

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 Costs Sum indirect oper costs + capital recovery cost 1,111,069

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,355,047

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 2007)\Attachments\Attach E - HYL Top Gas Purification Mar 2007 Revision

H2S LoCAT 3/6/2007 Page 4 of 19
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 0.0944

Replacement Catalyst:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 140 $/ft3

Amount Required 0 ft3

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 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

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% 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 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 $/day 331.1 days 331.1 22,183 $/day, 331 days, 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 ft3 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

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 E - HYL Top Gas Purification Mar 2007 Revision

H2S LoCAT 3/6/2007 Page 5 of 19
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 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 Rate 22,875 scfm @ 68o F

Dry Std Flow Rate 20,473 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) 4,919,585

 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 7,920,532

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) 2,096,023

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 - - - NA

Total Particulates - - - NA

Nitrous Oxides (NOx) - - - NA

Sulfur Dioxide (SO2) - - - NA

Sulfuric Acid Mist - - - NA

Fluorides - - - NA

Volatile Organic Compounds (VOC) - - - NA

Carbon Monoxide (CO) - - - NA

Lead (Pb) - - - NA

Hydrogen Sulfide (H2S) 32.6 8.2 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 Catalysts.

4 Capital cost estimated as four times the operating cost of the zinc oxide

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 E - HYL Top Gas Purification Mar 2007 Revision

H2S Zinc Oxide 3/6/2007 Page 6 of 19
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) 404,904

MN Sales Taxes 6.5% of control device cost (A) 263,188

Freight 5% of control device cost (A) 202,452

Purchased Equipment Total (B) 22% 4,919,585

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) 196,783

Piping 2% of purchased equip cost (B) 98,392

Insulation 1% of purchased equip cost (B) 49,196

Painting 1% of purchased equip cost (B) 49,196

Installation Subtotal Standard Expenses 30% 1,475,876

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 1,475,876

Total Direct Capital Cost, DC 6,395,461

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 491,959

Construction & field expenses 5% of purchased equip cost (B) 245,979

Contractor fees 10% of purchased equip cost (B) 491,959

Start-up 2% of purchased equip cost (B) 98,392

Performance test 1% of purchased equip cost (B) 49,196

Model Studies 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 7,920,532

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,920,532

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 Management

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

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 Costs 1,025,552

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 Costs Sum indirect oper costs + capital recovery cost 1,070,471

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,096,023

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 2007)\Attachments\Attach E - HYL Top Gas Purification Mar 2007 Revision

H2S Zinc Oxide 3/6/2007 Page 7 of 19
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 0.0944

Replacement Catalyst: Catalyst

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 650 $/ft3

Amount Required 0 ft3

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

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% 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 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 360.00 $/ft3 0.4 $/ft3 2,812 1,012,260 $/ft3, 0 $/ft3, 7946 hr/yr, 100% utilization

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 Catalyst 650 $/ft3 0 ft3 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

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 E - HYL Top Gas Purification Mar 2007 Revision

H2S Zinc Oxide 3/6/2007 Page 8 of 19
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 Rate 100% Temperature 120 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 25,136 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 22,875 scfm @ 68o F

Dry Std Flow Rate 20,481 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 394,735

 Purchased Equipment Total (B) 22% of control device cost (A) 479,603

 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 1,055,127

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) 253,659

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 - - - NA

Total Particulates - - - NA

Nitrous Oxides (NOx) - - - NA

Sulfur Dioxide (SO2) - - - - NA

Sulfuric Acid Mist - - - NA

Fluorides - - - NA

Volatile Organic Compounds (VOC) - - - NA

Carbon Monoxide (CO) - - - NA

Lead (Pb) - - - NA

Hydrogen Sulfide (H2S) 32.6 8.2 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 control efficiencies.

7 Scrubber/WESP evaporative water loss per Turbosonic proposal 

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 E - HYL Top Gas Purification Mar 2007 Revision

SO2 Caustic Absorber 3/6/2007 Page 9 of 19
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) 39,474

MN Sales Taxes 6.5% of control device cost (A) 25,658

Freight 5% of control device cost (A) 19,737

Purchased Equipment Total (B) 22% 479,603

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) 4,796

Piping 30% of purchased equip cost (B) 143,881

Insulation 1% of purchased equip cost (B) 4,796

Painting 1% of purchased equip cost (B) 4,796

Installation Subtotal Standard Expenses 85% 407,663

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 407,663

Total Direct Capital Cost, DC 887,266

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,960

Construction & field expenses 10% of purchased equip cost (B) 47,960

Contractor fees 10% of purchased equip cost (B) 47,960

Start-up 1% of purchased equip cost (B) 4,796

Performance test 1% of purchased equip cost (B) 4,796

Model Studies NA 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 1,055,127

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,055,127

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 Management

Electricity 0.05 $/kwh, 40 kW-hr, 7946 hr/yr, 100% utilization 16,603

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% utilization 5,056

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 81,822

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 Costs Sum indirect oper costs + capital recovery cost 171,838

Total Annual Cost (Annualized Capital Cost + Operating Cost) 253,659

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 2007)\Attachments\Attach E - HYL Top Gas Purification Mar 2007 Revision

SO2 Caustic Absorber 3/6/2007 Page 10 of 19
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 0.0944

Replacement Catalyst:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 140 $/ft3

Amount Required 0 ft3

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 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, Scrubber 25,136 8.55 0.7 - 35.9 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 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% utilization

Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 100% utilization

WW Treat Neutralization 1.69 $/mgal 6.3 gpm 2,995 5,056 $/mgal, 6 gpm, 7946 hr/yr, 100% utilization

WW Treat Biotreatemen 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 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 ft3 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

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 E - HYL Top Gas Purification Mar 2007 Revision

SO2 Caustic Absorber 3/6/2007 Page 11 of 19
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 Rate 22,875 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) 282,488

Total Capital Investment (TCI) = DC + IC 1,467,113

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) 1,441,107

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 0.2 0.6 0.6 - NA

Total Particulates 8.7 2.2 8.7 - NA

Nitrous Oxides (NOx) 2.5 10.1 10.1 - NA

Sulfur Dioxide (SO2) - - - - NA

Sulfuric Acid Mist - - - - NA

Fluorides - - - - NA

Volatile Organic Compounds (VOC) - - - - NA

Carbon Monoxide (CO) - - - - NA

Lead (Pb) - - - - NA

Hydrogen Sulfide (H2S) 32.6 8.2 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.

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 E - HYL Top Gas Purification Mar 2007 Revision

Recup Therm Ox 3/6/2007 Page 12 of 19
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% 911,250

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 273,375

Total Direct Capital Cost, DC 1,184,625

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 91,125

Construction & field expenses 5% of purchased equip cost (B) 45,563

Contractor fees 10% of purchased equip cost (B) 91,125

Start-up 2% of purchased equip cost (B) 18,225

Performance test 1% of purchased equip cost (B) 9,113

Model Studies 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 1,467,113

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,467,113

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 Management

Electricity 0.05 $/kwh, 93 kW-hr, 7946 hr/yr, 100% utilization 38,586

Natural Gas 6.85 $/mscf, 345 scfm, 7946 hr/yr, 100% utilization 1,125,256

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 Costs 1,213,902

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 Costs Sum indirect oper costs + capital recovery cost 227,205

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,441,107

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 2007)\Attachments\Attach E - HYL Top Gas Purification Mar 2007 Revision

Recup Therm Ox 3/6/2007 Page 13 of 19
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 $/ft3

Amount Required 39 ft3

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 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 25,136 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 Type 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% 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 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 ft3 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

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 E - HYL Top Gas Purification Mar 2007 Revision

Recup Therm Ox 3/6/2007 Page 14 of 19
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 

Twi 120 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 876 Deg F - Temperature of waste gas out of heat recovery

Tfo 444 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 34,391 scfm - Flow of waste gas 

Qaf 345 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 34,735 scfm Flue Gas Cost in 1989 $'s $291,358

Current Cost Using CHE Plant Cost Index $347,389

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

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 0.0276

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)

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 E - HYL Top Gas Purification Mar 2007 Revision

Recup Therm Ox 3/6/2007 Page 15 of 19
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 Rate 22,875 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) 376,650

Total Capital Investment (TCI) = DC + IC 1,956,150

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) 883,916

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 0.1 0.3 0.3 - NA

Total Particulates 0.3 0.1 0.3 - NA

Nitrous Oxides (NOx) 1.1 4.4 4.4 - NA

Sulfur Dioxide (SO2) - - - - NA

Sulfuric Acid Mist - - - - NA

Fluorides - - - - NA

Volatile Organic Compounds (VOC) - - - - NA

Carbon Monoxide (CO) - - - - NA

Lead (Pb) - - - - NA

Hydrogen Sulfide (H2S) 32.6 8.2 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

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 E - HYL Top Gas Purification Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 16 of 19
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% 1,215,000

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 364,500

Total Direct Capital Cost, DC 1,579,500

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 121,500

Construction & field expenses 5% of purchased equip cost (B) 60,750

Contractor fees 10% of purchased equip cost (B) 121,500

Start-up 2% of purchased equip cost (B) 24,300

Performance test 1% of purchased equip cost (B) 12,150

Model Studies 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 1,956,150

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,956,150

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 Management

Electricity 0.05 $/kwh, 120 kW-hr, 7946 hr/yr, 100% utilization 49,866

Natural Gas 6.85 $/mscf, 150 scfm, 7946 hr/yr, 100% utilization 491,062

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 Costs 590,987

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 Costs Sum indirect oper costs + capital recovery cost 292,929

Total Annual Cost (Annualized Capital Cost + Operating Cost) 883,916

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 2007)\Attachments\Attach E - HYL Top Gas Purification Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 17 of 19
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 $/ft3

Amount Required 0 ft3

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 26,834 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 Type catalytic (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% 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 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 ft3 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

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 E - HYL Top Gas Purification Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 18 of 19
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 

Twi 120 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 1,092 Deg F - Temperature of waste gas out of heat recovery

Tfo 228 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 31,935 scfm - Flow of waste gas 

Qaf 150 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 31,935 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 0.021066

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)

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 E - HYL Top Gas Purification Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 19 of 19
Attachment F 

Pneumatic Transport System Gas Heater 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment F - Emission Control Cost AnalysisTable F-1: Cost Summary - Pneumatic Transport System (PTS) Gas Heater

NOx Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

LoTOx 70% 1.0 2.4 $73,206 $137,201 $57,562 $255,713 None 

Selective Catalytic Reduction (SCR) 70% 1.0 2.4 $179,922 $160,163 $67,195 $304,757 NH3 SliULNB / LNB - FGR 56% 1.5 1.9 $118,124 $17,477 $9,125 NA None 

Selective Non-Catalytic Reduction (SNCR) 25% 2.6 0.9 $346,842 $85,477 $100,412 NA SNCR is inferior control NH3 Sli

Base Case NA 3.4

CO Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

Thermal OxidizerRecuperative 90% 0.4 3.2 $348,272 $183,888 $58,257 NA None Thermal OxidizerRegenerative 90% 0.4 3.2 $199,027 $142,871 $45,263 NA None Catalytic Oxidizer 90% 0.4 3.2 $361,783 $150,410 $47,651 NA None 

Uncontrolled 0% 3.5

VOC Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

Thermal OxidizerRecuperative 90% 0.02 0.2 $348,272 $183,888 $890,254 NA None Thermal OxidizerRegenerative 90% 0.02 0.2 $199,027 $142,871 $691,680 NA None Catalytic Oxidizer 90% 0.02 0.2 $361,783 $150,410 $728,179 NA None 

Uncontrolled 0% 0.2

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 F - Pn2006 RevisionCost Summary 3/6/2007 
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 Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 140 $/ft3 Cormetech, Inc., 1/2006 bid

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual 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

Pollutant Lb/Hr Uncontrolled Conc from Heater

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 (SO2) 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 unit 66 Base Case ppm NOx dry

Enter data for this study (applies to all units) 3.4 T/yr NOx Base Case

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 F - Pneumatic Gas Transport Heater Sept 2006 

Revision

Utility Chem$ Data 3/6/2007 Page 2 of 27
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 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) 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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 0.9 3.4 56% 1.5 1.9 9,125 

Sulfur Dioxide (SO2) 0.1 0.0 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 - NA

Notes & Assumptions

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

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx ULNB 3/6/2007 Page 3 of 27
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 Expenses 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 Cost 118,124

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

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 Management

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 - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 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 Costs 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx ULNB 3/6/2007 Page 4 of 27
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 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 $/ft3

Amount Required 39 ft3

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

Annualized 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 - NA

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 0.01 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

Maintenance

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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx ULNB 3/6/2007 Page 5 of 27
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 EU 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 35% 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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 0.9 3.4 70% 1.0 2.4 57,562 

Sulfur Dioxide (SO2) 0.1 0.0 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 - 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 MN Steel Industries September 2006 Water Balance 

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx LoTOx 3/6/2007 Page 6 of 27
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 Expenses 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 NA 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 Cost 73,206

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 Management

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 - 

NA NA - 

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 Costs 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 Costs 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx LoTOx 3/6/2007 Page 7 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment F - Emission Control Cost Analysis

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 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 $/ft3

Amount Required 0 ft3

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 36.8358272 $ 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

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency 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 O3 7

Total 15.4

Reagent Use & Other Operating Costs

Ozone Needed 1.8 lb O3/lb NOx lb/hr O3 1.7

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 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 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 Neutralization 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 Catalyst 140 $/ft3 0 ft3 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

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx LoTOx 3/6/2007 Page 8 of 27
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 EU 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) NA

 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 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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 0.9 3.4 70% 1.0 2.4 67,195 

Sulfur Dioxide (SO2) 0.1 0.0 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 - NA

Notes & Assumptions

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.

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx SCR PwrPlt 3/6/2007 Page 9 of 27
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) 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 179,922

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 174,949

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 Management

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 - 

CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 93% utilization 1,895

NA NA - 

Total Annual Direct Operating Costs 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 Costs 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx SCR PwrPlt 3/6/2007 Page 10 of 27
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 Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst 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 $/ft3 Flow #2 4,306 acfm

Amount Required 59.9 ft3 Vol #2 59.9 ft3

Catalyst Cost 4,324 Cost adjusted for freight & sales tax

Installation Labor 649 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 4,973 Zero out if no replacement parts needed

Annualized 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

Annualized 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 - NA

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 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 0.051 $/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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx SCR PwrPlt 3/6/2007 Page 11 of 27
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

Annual 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.

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx SCR PwrPlt 3/6/2007 Page 12 of 27
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 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 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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 0.9 3.4 25% 2.6 0.9 100,412 

Sulfur Dioxide (SO2) 0.1 0.0 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 - NA

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 1.19 

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

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx SNCR 3/6/2007 Page 13 of 27
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) NA

MN Sales Taxes 6.5% of control device cost (A) NA

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

Inventory Capital 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 Cost 346,842

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 15.00 % of Total Capital Investment 52,026

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

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 - 

NA NA - 

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 Costs 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 Costs Sum indirect oper costs + capital recovery cost 32,739

Total Annual Cost (Annualized Capital Cost + Operating Cost) 85,477

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx SNCR 3/6/2007 Page 14 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment F - Emission Control Cost Analysis

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 Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 140 $/ft3

Amount Required 12 ft3

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 Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 37 $/ft3

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 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/ft3 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

Ash Generation 0.0 lb/hr

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 0.0 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 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 Catalyst 140 $/ft3 0 ft3 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

NOx SNCR 3/6/2007 Page 15 of 27
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 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) 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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 0.9 3.4 3.4 - NA

Sulfur Dioxide (SO2) 0.1 0.0 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 - NA

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 

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

CO-VOC Therm Ox 3/6/2007 Page 16 of 27
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 Cost 348,272

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 Management

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 - 

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 Costs 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 Costs 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

CO-VOC Therm Ox 3/6/2007 Page 17 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment F - Emission Control Cost Analysis

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: Catalyst

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 650 $/ft3

Amount Required 39 ft3

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

Annualized 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 - NA

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 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

CO-VOC Therm Ox 3/6/2007 Page 18 of 27
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 

Twi 495 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 989 Deg F - Temperature of waste gas out of heat recovery

Tfo 707 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 2,380 scfm - Flow of waste gas 

Qaf 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 Incinerators

 (EPA 453/B-96-001)

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

CO-VOC Therm Ox 3/6/2007 Page 19 of 27
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 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) 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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 0.9 3.4 3.4 - NA

Sulfur Dioxide (SO2) 0.1 0.0 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 - 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 inflation

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 20 of 27
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 Cost 352,629

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 Management

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 - 

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, 93% utilization 2,233

NA NA - 

Total Annual Direct Operating Costs 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 Costs 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 21 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment F - Emission Control Cost Analysis

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: Catalyst

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 3000 $/ft3

Amount Required 2 ft3

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

Annualized 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 - NA

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 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 22 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment F - Emission Control Cost Analysis

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 

Twi 495 Deg F - Temperature of waste gas into heat recovery

Tfi 600 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 569 Deg F - Temperature of waste gas out of heat recovery

Tfo 527 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 2,380 scfm - Flow of waste gas 

Qaf 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 Incinerators

 (EPA 453/B-96-001)

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 23 of 27
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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 0.9 3.4 3.4 - NA

Sulfur Dioxide (SO2) 0.1 0.0 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 - 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

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

Regen. Thermal Ox 3/6/2007 Page 24 of 27
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 Cost 199,027

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 Management

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 - 

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 Costs 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 Costs 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 assumptions

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

Regen. Thermal Ox 3/6/2007 Page 25 of 27
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 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 $/ft3

Amount Required 0 ft3

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

Annualized 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 - NA

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 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 93% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

Regen. Thermal Ox 3/6/2007 Page 26 of 27
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 

Twi 495 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 1,130 Deg F - Temperature of waste gas out of heat recovery

Tfo 566 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 2,380 scfm - Flow of waste gas 

Qaf 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 Incinerators

 (EPA 453/B-96-001)

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 F - Pneumatic Gas Transport Heater Sept 

2006 Revision

Regen. Thermal Ox 3/6/2007 Page 27 of 27
Attachment G 

Degasser Boiler 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment G - Emission Control Cost AnalysisTable G-1: Cost Summary - Degasser Boiler

NOx Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

LoTOx 70% 2.6 6.2 $673,564 $302,396 $49,032 $216,675 None 

Selective Catalytic Reduction (SCR) 70% 2.6 6.2 $1,683,175 $356,433 $57,793 $261,280 NH3 SliULNB / LNB-FGR 56% 3.9 5.0 $285,011 $39,905 $8,052 NA None 

Selective Non-Catalytic Reduction (SNCR) 25% 6.6 2.2 $861,742 $212,444 $96,450 NA SNCR is inferior control NH3 Sli

Base Case NA 8.8

CO Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

Thermal OxidizerRecuperative 90% 0.9 8.2 $608,902 $322,239 $39,455 NA None Thermal OxidizerRegenerative 90% 0.9 8.2 $760,713 $283,680 $34,733 NA None Catalytic Oxidizer 90% 0.9 8.2 $738,592 $249,321 $30,526 NA None 

Uncontrolled 0% 9.1

VOC Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic

AQRV's

Thermal OxidizerRecuperative 90% 0.06 0.5 $608,902 $322,239 $602,923 NA None Thermal OxidizerRegenerative 90% 0.06 0.5 $760,713 $283,680 $530,777 NA None Catalytic Oxidizer 90% 0.06 0.5 $738,592 $249,321 $466,489 NA None 

Uncontrolled 0% 0.6

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 G - DeCost Summary 3/6/2007 
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 Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 140 $/ft3 Cormetech, Inc., 1/2006 bid

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual 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 

Pollutant 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 (SO2) 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 unit 61 Base Case ppm NOx dry

Enter data for this study (applies to all units) 8.8 T/yr NOx Base Case

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 G - Degasser Boiler Mar 2007 Revision

Utility Chem$ Data 3/6/2007 Page 2 of 27
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 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) 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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 7.9 8.8 56% 3.9 5.0 8,052 

Sulfur Dioxide (SO2) 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) - - - - NA

Notes & Assumptions

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

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 G - Degasser Boiler Mar 2007 Revision

NOx ULNB 3/6/2007 Page 3 of 27
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 Expenses 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 Cost 285,011

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

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 Management

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 - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 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 Costs 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

NOx ULNB 3/6/2007 Page 4 of 27
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: Catalyst

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 650 $/ft3

Amount Required 39 ft3

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

Annualized 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 - 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 0.01 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

Maintenance

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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

NOx ULNB 3/6/2007 Page 5 of 27
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 35% 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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 7.9 8.8 70% 2.6 6.2 49,032 

Sulfur Dioxide (SO2) 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) - - - - 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 MN Steel Industries September 2006 Water Balance 

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 G - Degasser Boiler Mar 2007 Revision

NOx LoTOx 3/6/2007 Page 6 of 27
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 Expenses 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 NA 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 Cost 673,564

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 Management

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 - 

NA NA - 

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 Costs 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 Costs 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

NOx LoTOx 3/6/2007 Page 7 of 27
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 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 $/ft3

Amount Required 0 ft3

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 36.8358272 $ 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

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency 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 O3 64

Total 138.2

Reagent Use & Other Operating Costs

Ozone Needed 1.8 lb O3/lb NOx lb/hr O3 14.3

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 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 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 Neutralization 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 Catalyst 140 $/ft3 0 ft3 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

NOx LoTOx 3/6/2007 Page 8 of 27
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) NA

 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 1,683,175

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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 7.9 8.8 70% 2.6 6.2 57,793 

Sulfur Dioxide (SO2) 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) - - - - NA

Notes & Assumptions

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.

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 G - Degasser Boiler Mar 2007 Revision

NOx SCR PwrPlt 3/6/2007 Page 9 of 27
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) 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 1,683,175

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,636,709

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 Management

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 - 

CO Catalyst 650.00 $/ft3, 0 ft3, 7946 hr/yr, 28% utilization 17,706

NA NA - 

Total Annual Direct Operating Costs 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 Costs 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

NOx SCR PwrPlt 3/6/2007 Page 10 of 27
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: Catalyst 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 $/ft3 Flow #2 40,237 acfm

Amount Required 560.0 ft3 Vol #2 560.0 ft3

Catalyst Cost 40,405 Cost adjusted for freight & sales tax

Installation Labor 6,061 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 46,466 Zero out if no replacement parts needed

Annualized 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

Annualized 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 - 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 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 0.051 $/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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

NOx SCR PwrPlt 3/6/2007 Page 11 of 27
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

Annual 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.

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 G - Degasser Boiler Mar 2007 Revision

NOx SCR PwrPlt 3/6/2007 Page 12 of 27
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 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 Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year

 Direct Capital Costs EPRI Correlation, 1998 $'s 25% 0.08 1998 513,33 99 5

 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. 131,102

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 81,342

Total Annual Cost (Annualized Capital Cost + Operating Cost) 212,444

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 0.8 0.8 - NA

Total Particulates 0.8 0.7 0.8 - NA

Nitrous Oxides (NOx) 7.9 8.8 25% 6.6 2.2 96,45 0

Sulfur Dioxide (SO2) 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) - - - - NA

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 1.19

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 1.2

9 No coal ash disposal cost; fuel is natural gas

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 G - Degasser Boiler Mar 2007 Revision

NOx SNCR 3/6/2007 Page 13 of 27
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) NA

MN Sales Taxes 6.5% of control device cost (A) NA

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

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 861,742

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 861,742

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 15.00 % of Total Capital Investment 129,261

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 0 kW-hr, 7946 hr/yr, 28% utilization 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 - 

NA NA - 

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 Costs 131,102

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 Costs Sum indirect oper costs + capital recovery cost 81,342

Total Annual Cost (Annualized Capital Cost + Operating Cost) 212,444

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 G - Degasser Boiler Mar 2007 Revision

NOx SNCR 3/6/2007 Page 14 of 27
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment G - Emission Control Cost Analysis

Table G-6: 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 $/ft3

Amount Required 12 ft3

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 Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 37 $/ft3

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 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/ft3 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

Ash Generation 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% utilization

Comp Air 0.31 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 7946 hr/yr, 28% utilization

WW Treat Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization

WW Treat Biotreatemen 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

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 Catalyst 140 $/ft3 0 ft3 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

** 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

NOx SNCR 3/6/2007 Page 15 of 27
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 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) 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) 117,242

Total Capital Investment (TCI) = DC + IC 608,902

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) 322,239

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 0.8 0.8 - NA

Total Particulates 0.8 0.7 0.8 - NA

Nitrous Oxides (NOx) 7.9 8.8 8.8 - NA

Sulfur Dioxide (SO2) 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) - - - - NA

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

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 G - Degasser Boiler Mar 2007 Revision

CO-VOC Therm Ox 3/6/2007 Page 16 of 27
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% 378,200

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 113,460

Total Direct Capital Cost, DC 491,660

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 37,820

Construction & field expenses 5% of purchased equip cost (B) 18,910

Contractor fees 10% of purchased equip cost (B) 37,820

Start-up 2% of purchased equip cost (B) 7,564

Performance test 1% of purchased equip cost (B) 3,782

Model Studies 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 608,902

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 608,902

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 Management

Electricity 0.05 $/kwh, 149 kW-hr, 7946 hr/yr, 28% utilization 16,791

Natural Gas 6.85 $/mscf, 157 scfm, 7946 hr/yr, 28% utilization 143,520

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 Costs 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 Costs Sum indirect oper costs + capital recovery cost 111,868

Total Annual Cost (Annualized Capital Cost + Operating Cost) 322,239

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 2007)\Attachments\Attach G - Degasser Boiler Mar 2007 Revision

CO-VOC Therm Ox 3/6/2007 Page 17 of 27
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 $/ft3

Amount Required 39 ft3

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 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 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 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% utilization

Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 28% utilization

WW Treat Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

CO-VOC Therm Ox 3/6/2007 Page 18 of 27
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 

Twi 495 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 989 Deg F - Temperature of waste gas out of heat recovery

Tfo 707 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 22,235 scfm - Flow of waste gas 

Qaf 157 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 22,392 scfm Flue Gas Cost in 1989 $'s $261,070

Current Cost Using CHE Plant Cost Index $311,276

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 Incinerators

 (EPA 453/B-96-001)

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 G - Degasser Boiler Mar 2007 Revision

CO-VOC Therm Ox 3/6/2007 Page 19 of 27
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

Pollutant Lb/Hr 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 - NA

Nitrous Oxides (NOx) 7.9 8.8 8.8 - NA

Sulfur Dioxide (SO2) 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) - - - - 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 inflation

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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 G - Degasser Boiler Mar 2007 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 20 of 27
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 Cost 653,060

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 Management

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 - 

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, 28% utilization 20,860

NA NA - 

Total Annual Direct Operating Costs 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 Costs 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 21 of 27
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: Catalyst

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 3000 $/ft3

Amount Required 22 ft3

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

Annualized 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 - 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 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 22 of 27
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 

Twi 495 Deg F - Temperature of waste gas into heat recovery

Tfi 600 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 569 Deg F - Temperature of waste gas out of heat recovery

Tfo 527 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 22,235 scfm - Flow of waste gas 

Qaf 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 Incinerators

 (EPA 453/B-96-001)

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 G - Degasser Boiler Mar 2007 Revision

CO-VOC Catalytic Ox 3/6/2007 Page 23 of 27
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 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) 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) 146,473

Total Capital Investment (TCI) = DC + IC 760,713

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) 283,680

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 0.8 0.8 - NA

Total Particulates 0.8 0.7 0.8 - NA

Nitrous Oxides (NOx) 7.9 8.8 8.8 - NA

Sulfur Dioxide (SO2) 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) - - - - 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

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 G - Degasser Boiler Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 24 of 27
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% 472,493

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 141,748

Total Direct Capital Cost, DC 614,240

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,249

Construction & field expenses 5% of purchased equip cost (B) 23,625

Contractor fees 10% of purchased equip cost (B) 47,249

Start-up 2% of purchased equip cost (B) 9,450

Performance test 1% of purchased equip cost (B) 4,725

Model Studies 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 760,713

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 760,713

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 Management

Electricity 0.05 $/kwh, 180 kW-hr, 7946 hr/yr, 28% utilization 20,326

Natural Gas 6.85 $/mscf, 89 scfm, 7946 hr/yr, 28% utilization 81,024

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 Costs 151,410

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 Costs Sum indirect oper costs + capital recovery cost 132,270

Total Annual Cost (Annualized Capital Cost + Operating Cost) 283,680

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 2007)\Attachments\Attach G - Degasser Boiler Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 25 of 27
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 $/ft3

Amount Required 0 ft3

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 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 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 - 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% utilization

Comp Air 0.31 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7946 hr/yr, 28% utilization

WW Treat Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 28% utilization

WW Treat Biotreatemen 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 Catalyst 650 $/ft3 0 ft3 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 assumptions

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 G - Degasser Boiler Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 26 of 27
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 

Twi 495 Deg F - Temperature of waste gas into heat recovery

Tfi 1200 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 1,130 Deg F - Temperature of waste gas out of heat recovery

Tfo 566 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp 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

Qwg 22,235 scfm - Flow of waste gas 

Qaf 89 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 22,235 scfm Flue Gas

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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 G - Degasser Boiler Mar 2007 Revision

Regen. Thermal Ox 3/6/2007 Page 27 of 27
Attachment H 

Material Handling, Pellet Plant 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment H - Emission Control Cost AnalysisTable H-1: Cost Summary - Material Handling, Pelletizer - Hearth Layer Bin

PM/PM10 Control Cost Summary *

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air T

AQ

Baghouse 0.0025 

gr/dscf 2 680 $6,113,901 $1,115,524 $1,640 NA N

Wet Scrubber 0.005 

gr/dscf 3 679 $974,410 $388,257 $572 NA N

Dry ElectroStatic Precipitator (ESP)

0.005 

gr/dscf 3 679 $2,625,818 $466,071 $687 NA N

Wet Wall ElectroStatic Precipitator (WWESP)

0.005 

gr/dscf 3 679 $6,475,115 $1,034,437 $1,524 NA N

Uncontrolled 0% 682* Based on highest emission rate if PM not equal to PM10

Fluoride Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air T

AQ

Wet Scrubber 99% 1.7E-04 1.7E-02 $974,410 $388,257 $22,998,559 N

A N

Dry ElectroStatic Precipitator (ESP) 99% 1.7E-04 1.7E-02 $2,625,818 $466,071 $27,607,908 NA N

Baghouse 99% 1.7E-04 1.7E-02 $6,113,901 $1,115,524 $66,078,547 N

A N

Wet Wall ElectroStatic Precipitator (WWESP) 99% 1.7E-04 1.7E-02 $6,475,115 $1,034,437 $61,275,355 NA NUncontrolled 0% 1.7E-02

Lead Control Cost Summary 

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air T

AQ

Wet Scrubber 99% 6.8E-06 6.8E-04 $974,410 $388,257 $575,041,859 N

A N

Dry ElectroStatic Precipitator (ESP) 99% 6.8E-06 6.8E-04 $2,625,818 $466,071 $690,291,177 NA N

Baghouse 99% 6.8E-06 6.8E-04 $6,113,901 $1,115,524 $1,652,187,436 N

A N

Wet Wall ElectroStatic Precipitator (WWESP) 99% 6.8E-06 6.8E-04 $6,475,115 $1,034,437 $1,532,091,371 NA NUncontrolled 0% 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 Summary 3/6/2007 
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 Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 500 $/ft3 Cormetech, Inc.

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual 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

Pollutant Lb/Hr Uncontrolled Conc 

PM10 738.3 1.00 gr/dscf

Total Particulates 738.3 1.00 gr/dscf

Nitrous Oxides (NOx) - - ppm

Sulfur Dioxide (SO2) - - 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 unit

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 2007)\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 + IC 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 (SO2) - - 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 water 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 ft2 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 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 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% utilization 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% utilization 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 2007)\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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft2 1.94E-03 kW/ft2 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 Disch 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* 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 19,895 ft2 grid area 0.984 $/ft2 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 Neutralization 1.64 $/mgal 90.8 gpm 10,070 16,505 $/mgal, 91 gpm, 7946 hr/yr, 23.2505344980828% utilization

WW Treat Biotreatemen 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 ft3 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 2007)\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 + IC 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 (SO2) - - 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 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 ft2 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 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 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% utilization 10,499

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, 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 2007)\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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft2 1.94E-03 kW/ft2 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 Disch 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* 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 19,895 ft2 grid area 0.984 $/ft2 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization

WW Treat Biotreatemen 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 ft3 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 2007)\Attachments\Attach H - Material Handling Mar 2007 Revision

PM-Pb Dry ESP 3/6/2007 Page 8 of 14
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 (SO2) - - 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 = 444, 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 control efficiencies.

3.691585714

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 Revision

PM-PB Wet Scrubber 3/6/2007 Page 9 of 14
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% utilization 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% utilization 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

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 Revision

PM-PB Wet Scrubber 3/6/2007 Page 10 of 14
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 $/ft3

Amount Required 0 ft3

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 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, 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* 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 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 Neutralization 1.64 $/mgal 45.4 gpm 5,035 8,253 $/mgal, 45 gpm, 7946 hr/yr, 23.2505344980828% utilization

WW Treat Biotreatemen 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 ft3 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 2007)\Attachments\Attach H - Material Handling Mar 2007 Revision

PM-PB Wet Scrubber 3/6/2007 Page 11 of 14
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 + IC 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 (SO2) - - 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 Chapter 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 per 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 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 Revision

PM-PB Baghouse 3/6/2007 Page 12 of 14
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% utilization 15,378

NA NA - 

NA NA - 

NA NA - 

Comp Air 0.31 $/mscf, 2 scfm/kacfm, 7946 hr/yr, 23.2505344980828% utiliza 6,192

NA NA - 

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

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 Revision

PM-PB Baghouse 3/6/2007 Page 13 of 14
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 $/ft3

Amount Required 0 ft3

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 Labor 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 Cost 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 ft2 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 ft2

Cages 16 ft long 5 in dia 13.42 area/cage ft2 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* 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 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 23.2505344980828% utilization

WW Treat Biotreatemen 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 ft3 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

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 Revision

PM-PB Baghouse 3/6/2007 Page 14 of 14
Attachment I 

DRI, Material Handling 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment I - Emission Control Cost AnalysisTable I-1: Cost Summary - DRI Material Handling Depressurization Vent

PM/PM10 Control Cost Summary *

Control Technology

Control 

Eff %

Controlled Emissions 

T/y

Emission 

Reduction T/yr

Installed 

Capital Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Dry ElectroStatic Precipitator (ESP)

0.005 

gr/dscf 3.2 61.7 $831,104 $211,610 $3,430 NA None Low 

Wet Scrubber 0.005 gr/dscf 3.2 61.7 $674,360 $353,525 $5,731 NA None High Baghouse 0.0025 gr/dscf 1.6 63.3 $1,019,106 $387,266 $6,117 NA None Low Uncontrolled 0% 64.9

* Based on highest emission rate if PM not equal to PM10

Fluoride Control Cost Summary 

Control Technology

Control 

Eff %

Controlled Emissions 

T/y

Emission 

Reduction T/yr

Installed 

Capital Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Dry ElectroStatic Precipitator (ESP) 99% 1.6E-04 1.6E-02 $831,104 $211,610 $13,167,234 NA None Low Wet Scrubber 99% 1.6E-04 1.6E-02 $674,360 $353,525 $21,997,770 NA None High 

Baghouse 99% 1.6E-04 1.6E-02 $1,019,106 $387,266 $24,097,245 NA None Low Uncontrolled 0% 1.6E-02

Lead Control Cost Summary 

Control Technology

Control 

Eff %

Controlled Emissions 

T/y

Emission 

Reduction T/yr

Installed 

Capital Cost $

Annualized 

Operating Cost 

$/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Dry ElectroStatic Precipitator (ESP) 99% 6.5E-06 6.4E-04 $831,104 $211,610 $329,180,860 NA None Low Wet Scrubber 99% 6.5E-06 6.4E-04 $674,360 $353,525 $549,944,248 NA None High 

Baghouse 99% 6.5E-06 6.4E-04 $1,019,106 $387,266 $602,431,118 NA None Low Uncontrolled 0% 6.5E-04

The 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 Summary 3/6/2007 
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 Ven 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

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 500 $/ft3 Cormetech, Inc.

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual Op. Hrs 7946 Hours Engineering Estimate

Utilization Rate 100% 2004 Kaar Consulting MSI Cost Model

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 (SO2) - - 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)

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 Revision

Utility Chem$ Data 3/6/2007 Page 2 of 11
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 - NA

Sulfur Dioxide (SO2) - - 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 ft2 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 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 Revision

PM-Pb Dry ESP 3/6/2007 Page 3 of 11
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 - 

NA NA - 

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

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 Revision

PM-Pb Dry ESP 3/6/2007 Page 4 of 11
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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft21.94E-03 kW/ft29.4 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 Disch 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 $/ft2 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 Neutralization 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 ft3 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

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 Revision

PM-Pb Dry ESP 3/6/2007 Page 5 of 11
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

Annual Interest Rate 7.0% Actual 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 (SO2) - - 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 control efficiencies.

5 Scrubber/WESP evaporative water loss per MN Steel Industries September 2006 Water Balance 

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 Revision

PM-PB Wet Scrubber 3/6/2007 Page 6 of 11
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 NA 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

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 Revision

PM-PB Wet Scrubber 3/6/2007 Page 7 of 11
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 $/ft3

Amount Required 0 ft3

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 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, 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 Neutralization 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 ft3 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

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 Revision

PM-PB Wet Scrubber 3/6/2007 Page 8 of 11
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 (SO2) - - 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 Chapter 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 per 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 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 Revision

PM-PB Baghouse 3/6/2007 Page 9 of 11
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

NA NA - 

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

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 Revision

PM-PB Baghouse 3/6/2007 Page 10 of 11
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 $/ft3

Amount Required 0 ft3

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 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.

Annualized 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 ft2 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 ft2

Cages 12 ft long 5 in dia 13.42 area/cage ft2 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 Neutralization 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 ft3 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

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 Revision

PM-PB Baghouse 3/6/2007 Page 11 of 11
Attachment J 

Steel Mill, Handling Material 

BACT Cost Tables 
Minnesota Steel Industries Air Quality Permit Application BACT Report -Attachment J - Emission Control Cost Analysis Material Handling, Table J-1: Cost Summary - Material Handling, Steel Mill Quicklime 

PM/PM10 Control Cost Summary *

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution 

Control Cost 

$/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts

Wet Scrubber 0.005 gr/dscf 0.05 18.7 $28,454 $32,180 $1,719 NA None High 

Baghouse 0.0025 gr/dscf 0.02 18.7 $63,096 $36,469 $1,945 NA None Low Dry ElectroStatic Precipitator (ESP)

0.005 

gr/dscf 0.05 18.7 $110,499 $42,254 $2,257 NA None Low 

Wet Wall ElectroStatic Precipitator (WWESP)

0.005 

gr/dscf 0.05 18.7 $223,627 $122,155 $6,524 NA None Low 

Uncontrolled 0% 18.8* Based on highest emission rate if PM not equal to PM10

Fluoride Control Cost Summary *

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution 

Control Cost 

$/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts

Wet Scrubber 99% 0.02 2.20 $28,454 $32,180 $14,657 NA None High 

Baghouse 99% 0.02 2.20 $63,096 $36,469 $16,611 NA None Low Dry ElectroStatic Precipitator (ESP) 99% 0.02 2.20 $110,499 $42,254 $19,246 NA None Low 

Wet Wall ElectroStatic Precipitator (WWESP) 99% 0.02 2.20 $223,627 $122,155 $55,639 NA None Low Uncontrolled 0% 2.22The control efficiency fluorides are for example calculations and do not represent actual control efficiencies. Fluorospar bin is only source of F- emissions in this source group

Lead Control Cost Summary *

Control Technology

Control 

Eff %

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution 

Control Cost 

$/ton

Incremental 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts

Wet Scrubber 99% 0.0002 0.02 $28,454 $32,180 $1,731,615 NA None High 

Baghouse 99% 0.0002 0.02 $63,096 $36,469 $1,962,434 NA None Low Dry ElectroStatic Precipitator (ESP) 99% 0.0002 0.02 $110,499 $42,254 $2,273,702 NA None Low 

Wet Wall ElectroStatic Precipitator (WWESP) 99% 0.0002 0.02 $223,627 $122,155 $6,573,210 NA None Low Uncontrolled 0% 0.02

The 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 

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls Cost Summary 
3/6/2007

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

Average union labor rate for MN mining 

industry

Maintenance Labor 32 $/hr

Average 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

Average 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

Ammonia 0.101 $/lb

Reagent #8 $/ton

Catalyst & Replacement Parts 

SCR Catalyst 500 $/ft3 Cormetech, Inc.

CO Catalyst 650 $/ft3 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 $/ft3

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 Information

Annual Op. Hrs 7946 Hours Engineering Estimate

Utilization Rate 26.2% 2004 Kaar Consulting MSI Cost Model

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 (SO2) - - 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)

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls Utility Chem$ Data 3/6/2007 Page 2 of 14
3/6/2007

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 (SO2) - - 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 ft2 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.

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-Pb Dry ESP 3/6/2007 Page 3 of 14
3/6/2007

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

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-Pb Dry ESP 3/6/2007 Page 4 of 14
3/6/2007

Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment J - Emission Control Cost Analysis

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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft2

1.94E-03 kW/ft20.5 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 ft2

 grid area 0.954 $/ft2 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 Neutralization 1.64 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7946 hr/yr, 26.2487065469698% utilization

WW Treat Biotreatement 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 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

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-Pb Dry ESP 3/6/2007 Page 5 of 14
3/6/2007

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

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) 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 (SO2) - - 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.

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-PB Wet Scrubber 3/6/2007 Page 6 of 14
3/6/2007

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 NA 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

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-PB Wet Scrubber 3/6/2007 Page 7 of 14
3/6/2007

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 $/ft3

Amount Required 0 ft3

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 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, 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 Neutralization 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 ft3 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

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-PB Wet Scrubber 3/6/2007 Page 8 of 14
3/6/2007

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 + IC 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/yr T/yr $/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 (SO2) - - 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 Chapter 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 per 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 efficiencies

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.

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-PB Baghouse 3/6/2007 Page 9 of 14
3/6/2007

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 + IC 63,096

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 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 Management

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% utiliza 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 Costs 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 Costs 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

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-PB Baghouse 3/6/2007 Page 10 of 14
3/6/2007

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 $/ft3

Amount Required 0 ft3

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 Labor 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 Cost 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 ft2 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 ft2

Cages 10 ft long 5 in dia 13.42 area/cage ft2 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 Neutralization 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 ft3 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

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-PB Baghouse 3/6/2007 Page 11 of 14
3/6/2007

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 - NA

Sulfur Dioxide (SO2) - - 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 water 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.

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-Pb-SO2-SA-F- Wet ESP 3/6/2007 Page 12 of 14
3/6/2007

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

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-Pb-SO2-SA-F- Wet ESP 3/6/2007 Page 13 of 14
3/6/2007

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 $/ft3

Amount Required 0 ft3

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 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 Baghouse & ESP 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 ft2

1.94E-03 kW/ft268.2 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 Disch 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 $/ft2 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 Neutralization 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 ft3 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

P:\\23\62\833\Task 3\Cost Sheets\Attach J - Material Handling Mar 2007 Revision.xls PM-Pb-SO2-SA-F- Wet ESP 3/6/2007 Page 14 of 14
Attachment K 

Diesel Powered Stationary Engines 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment K - Emission Control Cost AnalysisTable K-1: Cost Summary - Emergency Generators and Pumps

PM/PM10 Control Cost Summary 

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

GCP Varies by Design NA NA NA Site Specific

Oxidation 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 hrs

SO2 Control Cost Summary

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

Attach K - Emergency Generator Sept 2006 Revision 
Minnesota Steel Industries Air Quality Permit Application 

BACT Report -Attachment K - Emission Control Cost AnalysisTable K-1: Cost Summary - Emergency Generators and Pumps

NOx Control Cost Summary

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% 859 NA NA Site Specific

SCR 90% 45 $11,685,869 $1,290,046 $28,645

* based on 8760 hrs.

CO/VOC Control Cost Summary

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% 11.14 $5,031,939 $552,480 $49,583

VOC: 90% 1.57 $5,031,939 $552,480 $352,797

* based on 8760 hrs.

Attach K - Emergency Generator Sept 2006 Revision 
BACT Report -Attachment K - Emission Control Cost Analysis

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 15 years Equipment Life Estimate (1)

CRF 0.1098

Capital Cost

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

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 15 years Equipment Life Estimate (1)

CRF 0.1098

Catalyst Replacement Cost

Equipment Life 15 years

CRF 0.1098

Catalyst cost per unit 53000 $/ft

3 Vendor Estimate (2)

Amount Required 6.55 ft

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

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 15 years Equipment Life Estimate (1)

CRF 0.1098

Capital Cost

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 Summary 
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME THROUGHP

UT 

UNITS POLLUTANT CONTROL

CODE 

CONTROL EQUIPMENT EMISSION 

LIMIT 1

UNITS CASE-BYCASE 

BASIS 

MN-0064 NORTHSHORE MINING 

COMPANY

3/22/2006 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 

MN-0064 NORTHSHORE MINING 

COMPANY

3/22/2006 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-PSD

MN-0064 NORTHSHORE MINING 

COMPANY

3/22/2006 FURNACE 5 HOOD EXHAUST 

(WASTE GAS (#501, #502, #503)

160 LT/H pellets Nitrogen Oxides 

(NOx)

N 40 PPM @ 15% 

O2

BACT-PSD 

MN-0064 NORTHSHORE MINING 

COMPANY

3/22/2006 FURNACE 5 HOOD EXHAUST 

(WASTE GAS (#501, #502, #503)

160 LT/H pellets Sulfur Dioxide 

(SO2)

A WET ESP, HE 0.13 LB/MMBTU 

MN-0036 ISPAT INLAND MINING 

CO.

1/14/2000 METAL ORE MINING, TACONITE, 

INDURATING FURNACE

370 MMBTU/H Nitrogen Dioxide 

(NO2)

P FUEL USE IS LIMITED TO 270 

MMBTU/HR FOR ALL EU26 BURNERS COMBINED (4 STACKS) IN ADDITION TO THE USE OF EXISTING LOW NOX BURNERS. 11 CONTROL OPTIONS EXAMINED.

1088 LB/H BACT-PSD

BACT-PSD Emission Limits

Pollutant BACT Limit Units

PM 0.01 GR/DSCF

PM10 0.005 GR/DSCF

SO2 0.13 LB/MMBTUNOx 40

PPM @ 15% O2

No Performance Li

Taconite RBLC BACT Limits Summary

Other (non-BACT)-case-by-c

Emission Limits

page 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 2
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type Fuel

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

L

LA-0107

LOUISIANA IRON WORKS (TONDU) - DRI PLANT 5/5/1996 REFORMER FURNACE DRI

NATURAL GAS 1160.6 MMBTU/H PM10

SCRUBBING SPENT GAS FROM THE DRI FURNACE 0.001 GR/SCF BACT-PSD 

LA-0101

AMERICAN IRON REDUCTION - GULF COAST DRI FACILITY 3/18/1996 REFORMER FURNACES, 2 UNITS DRI

NATURAL GAS 1090 MMBTU/H PM10

SCRUBBING SPENT GAS FROM THE DRI FURNACES 0.003 GR/SCF BACT-PSD 

MO-0011

PEA RIDGE IRON ORE CO. 8/9/1995

ADDITION OF DIRECT REDUCTION FURNACE&COALHANDLING DRI

#6 RESIDUAL FUEL OIL 0.01 GRAIN\DRYPM10

USES A #6 RESIDUAL FUEL OIL. SPRAY DRYER \ FABRIC FILTER Barr Engineering Note: Facility shut down in 2001. New equipment probably not installed. RBLC has note that in 1997 startup was delayed due to lack of funds. 0.01 GR/DSCF BACT-PSD 

LA-0101

AMERICAN IRON REDUCTION - GULF COAST DRI FACILITY 3/18/1996 REFORMER FURNACES, 2 UNITS DRI

NATURAL GAS 1090 MMBTU/H NOX LOW NOX BURNERS 0.132 LB/MMBTU BACT-PSD 

AL-0086

TUSCALOOSA STEEL CORP. - MOBILE DRI PLANT 10/10/1995

DIRECT REDUCED IRON MATERIAL HANDLING SYSTEM DRI 150 T/H PM CYCLONE AND VENTURI SCRUBBER 0.63 LB/H BACT-PSD 

AL-0086

TUSCALOOSA STEEL CORP. - MOBILE DRI PLANT 10/10/1995

REFORMER AND DIRECT REDUCED IRON SHAFT FURNACE DRI 150 T/H PM VENTURI SCRUBBER 1.5 LB/H BACT-PSD 

MO-0011

PEA RIDGE IRON ORE CO. 8/9/1995

ADDITION OF DIRECT REDUCTION FURNACE&COALHANDLING DRI

#6 RESIDUAL FUEL OIL 0.01 GRAIN\DRYNOX

#6 RESIDUAL FUEL OIL, SNCR Barr Engineering Note: Facility shut down in 2001. New equipment probably not installed. RBLC has note that in 1997 startup was delayed due to lack of funds. 52 LB/HR BACT-PSD 

MO-0011

PEA RIDGE IRON ORE CO. 8/9/1995

ADDITION OF DIRECT REDUCTION FURNACE&COALHANDLING DRI

#6 RESIDUAL FUEL OIL 0.01 GRAIN\DRYSO2

USES A #6 RESIDUAL FUEL OIL SPRAY DRYER\ FABRIC FILTER Barr Engineering Note: Facility shut down in 2001. New equipment probably not installed. RBLC has note that in 1997 startup was delayed due to lack of funds. 104 LB/HR BACT-PSD 

AL-0086

TUSCALOOSA STEEL CORP. - MOBILE DRI PLANT 10/10/1995

REFORMER AND DIRECT REDUCED IRON SHAFT FURNACE DRI 150 T/H NOX LOW NOX BURNERS 105 LB/H BACT-PSD 

LA-0107

LOUISIANA IRON WORKS (TONDU) - DRI PLANT 5/5/1996 REFORMER FURNACE DRI

NATURAL GAS 1160.6 MMBTU/H NOX LOW NOX BURNERS 153 LB/H BACT-PSD 

BACT-PSD PM10 gr/dscf Emission Limits

MIN 0.001 GR/DSCF

MAX 0.01 GR/DSCF

MEDIAN 0.003 GR/DSCF

COUNT 3 CASES

BACT-PSD SO2 Emission Limits

SO2

BACT-PSD NOx Emission Limits

NOx 0.132 lb/MMBtuNOx 0.02 lb/t DRI

Other (non-BACT)-case-by

No Perform

No Performance Limits

DRI RBLC BACT Limits Summary

Other (non-BACT)-case-by

No Perform

Other (non-BACT)-case-by

No Perform

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-3: Electric Arc Furnace (EAF)- PM10

RBLC ID FACILITY NAME 

PERMIT 

DATE 

PROCESS 

NAME 

Proc 

Type FUEL 

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISSION LIMIT 2 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999

FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR PM10

FABRIC FILTERS (BAGHOUSE). SEE NOTES 0.0052 GR/DSCF BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998

ELECTRIC ARC FURNACE EAF 50 T/H PM10 BAGHOUSE 0.0052 GR/DSCF BACT-PSD 

PA-0214

J & L SPECIALTY STEEL, INC. 4/2/2003

ELECTRIC ARC FURNACE, (2) EAF 720000 T/YR PM10

GOOD COMBUSTION PRACTICES 1.14 LB/H BACT-PSD 5 T/Y

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998

FURNACE, ELECTRIC ARC #5 EAF 100 T/H OF STEEL PM10 CONTROLLED BY BAGHOUSE 7.5 LB/H BACT-PSD 32.8 T/Y

OH-0276 CHARTER STEEL 4/14/2003

ELECTRIC ARC FURNACE EAF 110 T/H MELT PM10 BAGHOUSE 12.43 LB/H BACT-PSD 40.15 T/Y

NJ-0040 CO-STEEL RARITAN 12/19/1996

ELECTRIC ARC FURNACE EAF 1160320 T/YR PM10

PSE AND CANOPY HOOD DRAW EXHAUST GASES TO BAGHOUSES WITH CAPACITY OF 1,000,000 ACFM. 20 LB/H BACT-PSD 6.7 MG

TX-0398 NUCOR JEWETT PLANT 5/5/2000

ELECTRIC ARC FURNACE EAF 600000 T/YR PM10 FF 30 LB/H BACT-PSD 243.26 T/Y

TX-0398 NUCOR JEWETT PLANT 5/5/2000 EAF BAGHOUSE EAF PM10 30.9 LB/H BACT-PSD

AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 EAF EAF 425 t/h PM10 FABRIC FILTER 37 LB/H BACT-PSD 162.1 T/Y

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (FUGITIVE EMISSIONS) EAF 70 T/H PM10

USE OF SEGMENTED CANOPY HOOD, SCAVENGER DUCTING, CROSS-DRAFT PARTITIONING AND CLOSED ROOF MONITORS. 81.2 T/YR BACT-PSD

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H PM10

FABRIC FILTER, STACK TEST WAS NOT DONE FOR PM10 43.17 LB/H N/A 50.6 T/Y

OH-0245

TECHNOLOGIES INTERNATIONAL 1/27/1999

FURNACE (EAF) NO. 7, P905 EAF 85 T/H PM10

FABRIC FILTER, STACK TEST WAS NOT DONE ON PM10 43.17 LB/H N/A 189.24 T/Y

PA-0178

ELLWOOD QUALITY STEELS CO. 4/30/2001

ELECTRIC ARC FURNACE EAF 53 T/BATCH PM10

DIRECT EVACUATION SYSTEM,BAGHOUSE 0.15 LB/T Other Case-by-Case 31 T/Y

WA-0319 NUCOR STEEL 9/8/2004

EAF, HIGH TEMPERATURE BAGHOUSE EAF 795000 t/yr PM10 BAGHOUSE 7.14 LB/H Other Case-by-Case 

WA-0319 NUCOR STEEL 9/8/2004

EAF, LOW TEMPERATURE BAGHOUSE EAF 795000 t/yr PM10

LOW TEMPERATURE BAGHOUSE 7.93 LB/H Other Case-by-Case 

UT-0061

NUCOR STEEL CORPORATION 8/29/1997

ELECTRIC ARC FURNACES (#1 & #2) EAF 65 T (EACH) PM10 FABRIC FILTER 15.43 LB/H Other Case-by-Case 

NE-0025

NUCOR STEEL DIVISION 6/22/2004

ELECTRIC ARC FURNACE EAF 56 MMBTU/H PM10

DIRECT EVACUATION CONTROL (DEC) 28.78 LB/H Other Case-by-Case

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005

ELECTRIC ARC FURNACE EAF 350 t/h PM10 BAGHOUSE 15.57 LB/H 59.96 T/Y

BACT-PSD PM10 gr/dscf Emission Limits

MIN 0.0018 GR/DSCF MIN 0.0017 GR

MAX 0.0052 GR/DSCF MAX 0.0052 GR

MEDIAN 0.0030 GR/DSCF MEDIAN 0.0026 GR

COUNT 7 CASES COUNT 5 CA

Other (non-BACT)-case-by-case PM10 

Emission Limits

EAF RBLC PM10 BACT Limits Summary

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-4: Electric Arc Furnace (EAF)- PM

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY- CASE BASIS EMIS

LIM

AR-0021

QUANEX CORPORATION - MACSTEEL DIVISION 2/18/1998 ELECTRIC ARC FURNACES, 2 EAF 86 T/H PM

POSITIVE PRESSURE MULTICOMPARTMENT BAGHOUSE 0.0018 GR/DSCF BACT-PSD 

AL-0197

NUCOR STEEL DECATUR, LLC 7/11/2002 ELECTRIC ARC FURNACE, (2) EAF 440 T/H PM BAGHOUSE 0.0032 GR/DSCF BACT-PSD 

IN-0073

QUALITECH STEEL CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H PM

DIRECT SHELL EVAC; BAGHOUSE. THE FURNACE IS IN ENCLOSED BUILDING. MATERIAL DELIVERED THROUGH HOLE IN FLOOR. BAGHOUSE COLLECTOR FOR FURNACE AND ROOM. 0.0032 GR/DSCF BACT-PSD 

AL-0124 SIMCALA INC 9/18/1998

FURNACE, ELECTRIC ARC SILICON EAF 20 MW PM

POSITIVE PRESSURE BAGHOUSE AND MULTICLONES 0.0032 GR/DSCF BACT-PSD 

AL-0129 IPSCO STEEL INC 10/16/1998 FURNACE, ELECTRIC ARC EAF 200 T/H PM BAGHOUSE WITH STACK 0.0033 GR/DSCF BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998 FURNACE, ELECTRIC ARC #5 EAF 100 T/H OF STEEL PM CONTROLLED BY BAGHOUSE 0.0034 GR/DSCF BACT-PSD 

CO-0054

CF & I STEEL L.P. DBA ROCKY MOUNTAIN STEEL MILLS 6/21/2004 ELECTRIC ARC FURNACE (EAF) EAF 156 T/H PM FF(FABRIC FILTER) 0.0052 GR/DSCF BACT-PSD 

MI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF 560000 T/YR PM

SIDE DRAFT/CANOPY HOOD AND BAGHOUSE 0.0052 GR/DSCF BACT-PSD 

TX-0417 NUCOR CORP. 1/15/2003 ELECTRIC ARC FURNACE EAF PM BAGHOUSE FILTRATION SYSTEM 0.0052 GR/DSCF BACT-PSD 

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 FURNACE, ELECTIC ARC EAF 50 T/H PM BAGHOUSE. 0.0052 GR/DSCF BACT-PSD 

KY-0094

NORTH AMERICAN STAINLESS 12/1/2003 EAF EAF 154 t/batch PM BAGHOUSE 13.94 LB/H BACT-PSD 

NJ-0040 CO-STEEL RARITAN 12/19/1996 ELECTRIC ARC FURNACE EAF 1160320 T/YR PM

PSE AND CANOPY HOOD DRAW EXHAUST GASES TO BAGHOUSES WITH CAPACITY OF 1,000,000 ACFM 20 LB/H BACT-PSD 

AL-0202 CORUS TUSCALOOSA 6/3/2003 ELECTRIC ARC FURNACE EAF 160 T/H PM

DIRECT EVACUATION CANOPY, ELEPHANT HOUSE, AND MELTSHOP BAGHOUSE 32.5 LB/H BACT-PSD 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 7, P905 EAF 85 T/H PM

FABRIC FILTER, DIRECT EVACUATION CONTROL (DEC) AND BUILDING EVACUATION SYSTEM 56.8 LB/H N/A 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H PM

FABRIC FILTER, DIRECT EVACUATION CONTROL (DEC) AND BUILDING EVACUATION SYSTEM 56.8 LB/H N/A 

IA-0031 IPSCO STEEL INC 3/14/1996

ELECTRIC ARC FURNACE/STEEL FOUNDRY EAF 230 T/H PM

BAGHOUSE-POLYBAGS 32 MODULES/260 BAGS PER MODULE 0.0033 GR/DSCF Other Case-by-Case 

TN-0122

HOEGANAES CORPORATION 2/11/2000 ELECTRIC ARC FURNACE (EAF) EAF 45 MVA/70.4 MMBTU/H PM FABRIC FILTER 18.07 LB/H Other Case-by-Case 

NE-0025 NUCOR STEEL DIVISION 6/22/2004 ELECTRIC ARC FURNACE EAF 56 MMBTU/H PM

DIRECT EVACUATION CONTROL (DEC) 37.89 LB/H Other Case-by-Case

IN-0070 NUCOR STEEL 6/20/1996 ELECTRIC ARC FURNACE (EAF) EAF 502 T/H PM BAGHOUSE 101.2 T/YR Other Case-by-Case 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 ELECTRIC ARC FURNACE EAF 350 t/h PM BAGHOUSE 0.0032 GR/DSCF 

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (FUGITIVE EMISSIONS) EAF 70 T/H PM

USE OF SEGMENTED CANOPY HOOD, SCAVENGER DUCTING, CROSSDRAFT PARTITIONING AND CLOSED ROOF MONITORS. 140 T/YR

BACT-PSD PM gr/dscf Emission Limits

MIN 0.0018 GR/DSCF MIN 

MAX 0.0052 GR/DSCF MAX 

MEDIAN 0.0033 GR/DSCF MEDIAN 

COUNT 13 CASES COUNT 

Other (non-BACT)-case-by-

Lim

EAF RBLC PM BACT Limits Summary

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

L

TN-0155

NUCOR STEEL CORPORATION 11/6/2000 ELECTRIC ARC FURNACE EAF 150 T/H SO2

LIMIT HIGH-SULFUR STEEL PRODUCTION TO 125,000 TON/YR; MAINTENANCE OF A LOG OF IRON PYRITE USAGE DURING HIGH-SULFUR STEEL PRODUCTION, PROPERLY DESIGNED EAF; SCRAP MANAGEMENT PLAN 0.16 LB/T BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 ELECTRIC ARC FURNACE (EAF) EAF 350 t/h SO2

LOW SULFUR COKE AND SCRAP MANAGEMENT 0.2 LB/T BACT-PSD

TX-0417 NUCOR CORP. 1/15/2003 ELECTRIC ARC FURNACE EAF SO2 LOW SULFUR FUEL 0.35 LB/T BACT-PSDSC-0072

SMI STEEL - SOUTH CAROLINA 11/26/2001 EAF EAF 850000 T/YR SO2 SCRAP MANAGEMENT PLAN 0.35 LB/T BACT-PSD

AL-0129 IPSCO STEEL INC 10/16/1998 FURNACE, ELECTRIC ARC EAF 200 T/H SO2 0.7 LB/T BACT-PSD AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 ELECTRIC ARC FURNACE EAF 50 T/H SO2

DES WITH NO ADD-IN CONTROLS (EXISTING) 0.7 LB/T BACT-PSD 

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (FUGITIVE EMISSIONS) EAF 70 T/H SO2 0.7 T/YR BACT-PSD

MI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF 560000 T/YR SO2 1

LB/T STEEL PRODUCED BACT-PSD 

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, ELECTRIC ARC EAF 225 T/H SO2

LOW SULFUR COKE/SCRAP MANAGEMENT. 1.5 LB/T BACT-PSD

NJ-0040 CO-STEEL RARITAN 12/19/1996 ELECTRIC ARC FURNACE EAF 1160320 T/YR SOX BAGHOUSE 2 LB/H BACT-PSDVA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998 FURNACE, ELECTRIC ARC #5 EAF 100 T/H OF STEESO2 16.8 LB/H BACT-PSD 

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (STACK EMISSIONS) EAF 70 T/H SO2 17.5 LB/H BACT-PSD 

NY-0094 NUCOR AUBURN STEEL 6/22/2004 EAF EAF 110 t/h SO2 25.3 LB/H BACT-PSD 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR SO2

SULFUR CONTENT OF DIRECT REDUCED IRON, CHARGE CARBON, AND INJECTION CARBON 50 LB/H BACT-PSD 

*AR-0086

NUCOR-YAMATO STEEL COMPANY, BLYTHEVILLE MILL 6/11/2004 EAF #1 BAGHOUSE, SN-01 EAF 450 T/H STEEL SO2 LOW SULFUR COKE USAGE 90 LB/H BACT-PSD 

AR-0021

QUANEX CORPORATION - MACSTEEL DIVISION 2/18/1998 ELECTRIC ARC FURNACES, 2 EAF 86 T/H SO2 USE OF HIGH QUALITY SCRAP 90.3 LB/H BACT-PSD 

AL-0202 CORUS TUSCALOOSA 6/3/2003 ELECTRIC ARC FURNACE EAF 160 T/H SO2 99.2 LB/H BACT-PSD IN-0073

QUALITECH STEEL CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H SO2

LIMIT OPERATIONS; THREE BAR WITH DIFFERENT SULFUR CONTENT: LOW SULFUR .003 LBS/TON, 1100 SERIES .52 LBS/TON AND 1200 SERIES 1.4 LBS/TON 149 T/YR BACT-PSD 

AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 EAF EAF 425 t/h SO2 SCRAP MANAGEMENT 155 LB/H BACT-PSD 

AL-0197

NUCOR STEEL DECATUR, LLC 7/11/2002 ELECTRIC ARC FURNACE, (2) EAF 440 T/H SO2 220 LB/H BACT-PSD 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) 

NO. 7, P905 EAF 85 T/H SO2

LOOKED AT CHARGE SUBSTITUTION (NOT FEASIBLE) AND SO2 CONTROLS (NOT FEASIBLE) 5.95 LB/H N/A 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H SO2

LOOKED AT CHARGE SUBSTITUTION (NOT FEASIBLE) AND SO2 CONTROLS (NOT FEASIBLE) 11.55 LB/H N/A 

PA-0214

J & L SPECIALTY STEEL,INC. 4/2/2003 ELECTRIC ARC FURNACE, (2) EAF 720000 T/YR SOX 0.09 LB/H Other Case-by-Case

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 EAF EAF 200 T/H SO2 0.15 LB/T Other Case-by-Case 

CO-0054

CF & I STEEL L.P. DBA ROCKY MOUNTAIN STEEL MILLS 6/21/2004 ELECTRIC ARC FURNACE (EAF) EAF 156 T/H SO2

ALTERNATIVE RAW MATERIALS + PROCESS CONTROLS 0.25

LB/T (STEEL PRD). Other Case-by-Case

PA-0178

ELLWOOD QUALITY STEELS CO. 4/30/2001 ELECTRIC ARC FURNACE EAF 53 T/BATCH SO2 DIRECT EVACUATION SYSTEM 0.45 LB/T Other Case-by-Case 

TN-0122

HOEGANAES CORPORATION 2/11/2000 ELECTRIC ARC FURNACE (EAF) EAF 45 MVA/70.4 MMSO2

SULFUR CONTENT OF NO. 2 FUEL OIL LIMITED TO 0.25% BY WEIGHT 3.86 LB/H Other Case-by-Case 

IA-0031 IPSCO STEEL INC 3/14/1996

ELECTRIC ARC FURNACE/STEEL FOUNDRY EAF 230 T/H SO2 BASELINE NO CONTROL 14 LB/H Other Case-by-Case 

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

L

UT-0061

NUCOR STEEL CORPORATION 8/29/1997

ELECTRIC ARC FURNACES (#1 & #2) EAF 65 T (EACH) SO2 19.95 LB/H Other Case-by-Case

OH-0276 CHARTER STEEL 4/14/2003 ELECTRIC ARC FURNACE EAF 110 T/H MELT SO2 PRODUCTION LIMITS. SEE NOTE 22 LB/H 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 ELECTRIC ARC FURNACE EAF 350 t/h SO2 105 LB/H 

BACT-PSD SO2 and SOx lb/t steel Emission Limits

MIN 0.16 lb/t steel MIN 

MAX 1.50 lb/t steel MAX 

MEDIAN 0.35 lb/t steel MEDIAN 

COUNT 14 CASES COUNT 

EAF RBLC SO2 and SOx BACT Limits Summary

Other (non-BACT)-case-b

steel Emiss

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type FUEL 

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISSION LIMIT 2 

TX-0417 NUCOR CORP. 1/15/2003 ELECTRIC ARC FURNACE EAF NOX

OXY-FUEL BURNERS AND GOOD ENGINEERING PRACTICES 0.3 LB/T BACT-PSD

AR-0077 BLUEWATER PROJECT 7/22/2004 ELECTRIC ARC FURNACE (EAF) EAF NATURAL GAS 350 t/h NOX LOW NOX BURNERS 0.35 LB/T BACT-PSD

OH-0245 [b]

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H NOX

LOOKED AT SCR, SNCR, AND FGR ALL INFEASIBLE 0.35 LB/T BACT-PSD 33 L

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, ELECTRIC ARC EAF 225 T/H NOX LOW NOX BURNER. 0.38 LB/T BACT-PSD

IN-0073

QUALITECH STEEL CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H NOX 0.5 LB/T BACT-PSD 0 

SC-0072

SMI STEEL - SOUTH CAROLINA 11/26/2001 EAF EAF NATURAL GAS 850000 T/YR NOX

LOW NOX OXY-FUEL" BURNERS MOUNTED IN EAF" 0.51 LB/T BACT-PSD

MI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF COAL/COKE 560000 T/YR NOX 0.53

LB/T STEEL PRODUCED BACT-PSD 148.4 T

TN-0155

NUCOR STEEL CORPORATION 11/6/2000 ELECTRIC ARC FURNACE EAF NATURAL GAS 150 T/H NOX

THE PROPER OPERATION OF THE EAF AND DEC SYSTEMS, OXY-FUEL NATURAL GAS BURNERS IN THE SHAFT,ELBOW BOX AND SIDEWALLS 0.7 LB/T BACT-PSD 21 P

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 ELECTRIC ARC FURNACE EAF ELECTRICITY 50 T/H NOX

DES WITH NO ADD-ON CONTROL (EXISTING) 1 LB/T BACT-PSD 50 L

OH-0245 [b]

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 7, P905 EAF 85 T/H NOX

LOOKED AT SCR, SNCR, AND FGR ALL INFEASIBLE. 8.5 LB/H BACT-PSD 37.2 T

TN-0122

HOEGANAES CORPORATION 2/11/2000 ELECTRIC ARC FURNACE (EAF) EAF NATURAL GAS 45 MVA/70.4 MMBTU/H NOX LOW NOX BURNERS 11.04 LB/H BACT-PSD 0.2 L

NJ-0040 CO-STEEL RARITAN 12/19/1996 ELECTRIC ARC FURNACE EAF NATURAL GAS 1160320 T/YR NOX 24 LB/H BACT-PSD

NY-0094 NUCOR AUBURN STEEL 6/22/2004 EAF EAF NATURAL GAS 110 t/h NOX 27.32 LB/H BACT-PSD 0.27 L

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (STACK

EMISSIONS) EAF ELECTRICITY 70 T/H NOX 27.72 LB/H BACT-PSD 110.88 T

OH-0276 CHARTER STEEL 4/14/2003 ELECTRIC ARC FURNACE EAF ELECTRIC 110 T/H MELT NOX

DIRECT EVACUATION CONTROL AND LOW NOX OXY-FUEL BURNERS 36.29 LB/H BACT-PSD 117.25 T

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998 FURNACE, ELECTRIC ARC #5 EAF 100 T/H OF STEEL NOX 37.8 LB/H BACT-PSD 165.6 T

AL-0202 CORUS TUSCALOOSA 6/3/2003 ELECTRIC ARC FURNACE EAF 160 T/H NOX 56 LB/H BACT-PSD 0.35 L

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF ELECTRICITY 200 T/YR NOX

LOW NOX/OXYFUEL BURNERS AND COMBUSTION CONTROLS. 70 LB/H BACT-PSD 0.35 L

AL-0197

NUCOR STEEL DECATUR, LLC 7/11/2002 ELECTRIC ARC FURNACE, (2) EAF 440 T/H NOX 176 LB/H BACT-PSD 0.4 L

PA-0178

ELLWOOD QUALITY STEELS CO. 4/30/2001 ELECTRIC ARC FURNACE EAF NATURAL GAS 53 T/BATCH NOX

DIRECT EVACUATION SYSTEM, OXYFUEL 0.1 LB/T Other Case-by-Case 20.7 T

CO-0054 [a]

CF & I STEEL L.P. DBA ROCKY MOUNTAIN STEEL MILLS 6/21/2004 ELECTRIC ARC FURNACE (EAF) EAF ELECTRIC POWE 156 T/H NOX GOOD COMBUSTION PRACTICES. 0.15 LB/T Other Case-by-Case

PA-0214

J & L SPECIALTY STEEL, INC. 4/2/2003 ELECTRIC ARC FURNACE, (2) EAF NATURAL GAS 720000 T/YR NOX LOW NOX BURNERS 16.62 LB/H Other Case-by-Case 72.8 T

UT-0061

NUCOR STEEL CORPORATION 8/29/1997

ELECTRIC ARC FURNACES (#1 & #2) EAF NATURAL GAS 65 T (EACH) NOX EXISTING LOW NOX BURNERS 47.25 LB/H Other Case-by-Case

IA-0031 IPSCO STEEL INC 3/14/1996

ELECTRIC ARC FURNACE/STEEL FOUNDRY EAF ELECTRICITY 230 T/H NOX

OXYFUEL/LOW NOX BURNER SCRAP PREHEATING BURNERS ONLY CONSIDERED BASELINE 63 LB/H Other Case-by-Case 276 T

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (FUGITIVE EMISSIONS) EAF ELECTRICITY 70 T/H NOX 1.11 T/YR

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 ELECTRIC ARC FURNACE EAF ELECTRICITY 350 t/h NOX 189 LB/H 675 T

BACT-PSD NOx lb/t Steel Emission Limits

MIN 0.200 lb/t steel MIN 0.100 l

MAX 1.000 lb/t steel MAX 0.100 l

MEDIAN 0.380 lb/t steel MEDIAN 0.100 l

COUNT 13 CASES COUNT 1 C

EAF RBLC NOx BACT Limits Summary

Other (non-BACT)-case-by-case NO

Emission 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 renegotiations were 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 analysis

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISS

LIMIT 

AR-0030 [a]

ARKANSAS STEEL ASSOCIATES 9/24/1998 ELECTRIC ARC FURNACE EAF 50 T/H CO

DES WITH AIR GAP FOR CO COMBUSTION (EXISTING) 0.6 LB/T BACT-PSD 

KY-0094

NORTH AMERICAN STAINLESS 12/1/2003 EAF EAF 154 t/batch CO 2 LB/T BACT-PSD 

AL-0129 IPSCO STEEL INC 10/16/1998 FURNACE, ELECTRIC ARC EAF 200 T/H CO DEC WITH POST-COMBUSTION 2 LB/T BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 ELECTRIC ARC FURNACE (EAF) EAF 350 t/h CO AIR GAP 2 LB/T BACT-PSD

TX-0417 NUCOR CORP. 1/15/2003 ELECTRIC ARC FURNACE EAF CO GOOD COMBUSTION PRACTICE 2 LB/T BACT-PSD

SC-0072

SMI STEEL - SOUTH CAROLINA 11/26/2001 EAF EAF 850000 T/YR CO

DESTRUCTION OF CO IN THE DUCT ELBOW AND WATER COOLED DUCTWORK 2 LB/T BACT-PSD

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, ELECTRIC ARC EAF 225 T/H CO OXIDATION WITH SIDE DRAFT AIR GAP 2 LB/T BACT-PSD

TN-0155

NUCOR STEEL CORPORATION 11/6/2000 ELECTRIC ARC FURNACE EAF 150 T/H CO

PROPER OPERATION OF EAF AND DIRECT EVACUATION CONTROL SYSTEM, USE OF OXY-FUEL FOR POSTCOMBUSTION CONTROL; USE OF OXYGEN LANCING. 4 LB/T BACT-PSD 

IN-0073

QUALITECH STEEL CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H CO

POST COMBUSTION UNDER HOOD BY OXYGEN INJECTION AND OXY FUEL BURNERS & FOURTH HOLE WITH ADJUSTABLE GAP TO ALLOW AIR INTO WATER COOLED DUCTWORK FOR COMBUS 4.7 LB/T BACT-PSD 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 EAF EAF 200 T/H CO 4TH HOLE 4.8 LB/T BACT-PSD 

PA-0178

ELLWOOD QUALITY STEELS CO. 4/30/2001 ELECTRIC ARC FURNACE EAF 53 T/BATCH CO DIRECT EVACUATION SYSTEM 5 LB/T BACT-PSD 

MI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF 560000 T/YR CO 5

LB/T STEEL PRODUCED BACT-PSD 

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 FURNACE, ELECTIC ARC EAF 50 T/H CO

DIRECT SHELL EVACUATION CONTROL (DEC) SYSTEM WITH AIR GAP FOR CO COMBUSTION. 6 LB/T BACT-PSD 

NC-0065 AMERISTEEL CORP. 4/29/1999

STEEL PRODUCTION, ELECTRIC ARC FURNACE EAF 569400 T/YR CO

CONTROL: SEE PROCESS DESCRIPTION. EMISSION LIMIT IN LB/TON STEEL PRODUCED 6 LB/T BACT-PSD

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (FUGITIVE EMISSIONS) EAF 70 T/H CO 11.37 T/YR BACT-PSD

WV-0018 ALLOY 12/16/2002 ELECTRIC ARC FURNACE EAF 18000 T/YR CO

DIRECT EVACUATION CANOPY USED TO INTRODUCE AMBIENT AIR MIX WITH EXHAUST TO PROMOTE CO COMBUSTION. 54 LB/H BACT-PSD 

TN-0122

HOEGANAES CORPORATION 2/11/2000 ELECTRIC ARC FURNACE (EAF) EAF 45 MVA/70.4 MMBTU/H CO

COMBUSTION AIR GAP BETWEEN THE WATER-COOLED DUCT AND THE ELBOW OFF 152.9 LB/H BACT-PSD 

NY-0094 NUCOR AUBURN STEEL 6/22/2004 EAF EAF 110 t/h CO

DIRECT SHELL EVACUATION (DSE) CONTROLS TO LIMIT CO EMISSIONS. 202.4 LB/H BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998 FURNACE, ELECTRIC ARC #5 EAF 100 T/H OF STEEL CO CONTROLLED BY DEC WITH AIRGAP 240 LB/H BACT-PSD 

NJ-0040 CO-STEEL RARITAN 12/19/1996 ELECTRIC ARC FURNACE EAF 1160320 T/YR CO GOOD COMBUSTION PRACTICES 275 LB/H BACT-PSD

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (STACK EMISSIONS) EAF 70 T/H CO 284.2 LB/H BACT-PSD 

AL-0202 CORUS TUSCALOOSA 6/3/2003 ELECTRIC ARC FURNACE EAF 160 T/H CO DIRECT EVACUATION CANOPY 320 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 ELECTRIC ARC FURNACE EAF 110 T/H MELT CO DIRECT EVACUATION CONTROL 356.4 LB/H BACT-PSD 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR CO

DEC AIR GAP AND POST COMBUSTION CHAMBER 400 LB/H BACT-PSD 

AR-0021

QUANEX CORPORATION - MACSTEEL DIVISION 2/18/1998 ELECTRIC ARC FURNACES, 2 EAF 86 T/H CO

EXISTING SIDE DRAFT CONTROL SYSTEM. 421.4 LB/H BACT-PSD 

AL-0197

NUCOR STEEL DECATUR, LLC 7/11/2002 ELECTRIC ARC FURNACE, (2) EAF 440 T/H CO 880 LB/H BACT-PSD 

AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 EAF EAF 425 t/h CO DIRECT SHELL EVACUATION 961.5 LB/H BACT-PSD 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 EAF BAGHOUSE EAF CO 972 LB/H BACT-PSD

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 7, P905 EAF 85 T/H CO

DEC SYSTEM COMBUSTS 90% OF THE CO. LOOKED AT SCRAP PREHEATING (NOT FEASIBLE). USED A DEC GAP TO HELP COMBUST THE CO. 340 LB/H N/A 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H CO

DEC COMBUSTS 90% OF THE CO. USED A DEC GAP TO HELP COMBUST THE CO. LOOKED AT SCRAP PREHEATING (NOT FEASIBLE) 660 LB/H N/A 

CO-0054

CF & I STEEL L.P. DBA ROCKY MOUNTAIN STEEL MILLS 6/21/2004 ELECTRIC ARC FURNACE (EAF) EAF 156 T/H CO

PROCESS CONTROLS, INCLUDING PATTERN OF CHARGING, RAW MATERIALS ADDITION, ETC. 2 LB/T Other Case-by-Case

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISS

LIMIT 

IA-0031 IPSCO STEEL INC 3/14/1996

ELECTRIC ARC FURNACE/STEEL FOUNDRY EAF 230 T/H CO

SLOT AND POST COMBUSTION CHAMBER DEC\ELBOW SLOT\POST COMBUSTION\WATER COOLED DUCT 210 LB/H Other Case-by-Case 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 ELECTRIC ARC FURNACE EAF 600000 T/YR CO 648 LB/H Other Case-by-Case 

UT-0061

NUCOR STEEL CORPORATION 8/29/1997

ELECTRIC ARC FURNACES (#1 & #2) EAF 65 T (EACH) CO 973.2 LB/H Other Case-by-Case 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 ELECTRIC ARC FURNACE EAF 350 t/h CO 1400 LB/H 

BACT-PSD CO lb/t steel Emission Limits

MIN 0.60 lb/t steel MIN 

MAX 25.22 lb/t steel MAX 

MEDIAN 2.00 lb/t steel MEDIAN 

COUNT 20 CASES COUNT 

EAF RBLC CO BACT Limits Summary

Other (non-BACT)-case-by-case 

[a] Billy Ferguson of Arkansas Steel Associates, said on 6/8/06 that they were having no problems meeting the limit of 0.6 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type FUEL 

THROUGH

PUT UNITS

POLLUTANT Control Equipment EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS 

MI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF COAL/COKE 560000 T/YR VOC 0.03 LB/T STEEL PRODUCBACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 ELECTRIC ARC FURNACE (EAF) EAF NATURAL GAS 350 t/h VOC SCRAP MANAGEMENT 0.13 LB/T BACT-PSD

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, ELECTRIC ARC EAF 225 T/H VOC SCRAP MANAGEMENT. 0.13 LB/T BACT-PSD

KY-0094

NORTH AMERICAN STAINLESS 12/1/2003 EAF EAF 154 t/batch VOC 0.15 LB/T BACT-PSD 

IN-0073

QUALITECH STEEL

CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H VOC

SCRAP MANAGEMENT - NOHEAVY OILED SCRAP 0.15 LB/T STEEL PROD. BACT-PSD 

TN-0155

NUCOR STEEL CORPORATION 11/6/2000 ELECTRIC ARC FURNACE EAF NATURAL GAS 150 T/H VOC

SCRAP MANAGEMENT PLAN; 

PROPER OPERATION OF EAF AND DEC SYSTEMS, USE OF OXY-FUEL FOR 0.26 LB/T BACT-PSD

AL-0129 IPSCO STEEL INC 10/16/1998 FURNACE, ELECTRIC ARC EAF 200 T/H VOC

DEC WITH POST COMBUSTION CHAMBER 0.35 LB/T BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 ELECTRIC ARC FURNACE EAF ELECTRICITY 50 T/H VOC

DIRECT EVACUATION SYSTEM (DES) WITH AIR GAP FOR LONG RESIDENCE TIME (EXISTING) 0.35 LB/T BACT-PSD 

TX-0417 NUCOR CORP. 1/15/2003 ELECTRIC ARC FURNACE EAF VOC

COMBUSTION IN DSE SYSTEM 0.427 LB/T BACT-PSD

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (FUGITIVE EMISSIONS) EAF ELECTRICITY 70 T/H VOC 0.8 T/YR BACT-PSD

NJ-0040 CO-STEEL RARITAN 12/19/1996 ELECTRIC ARC FURNACE EAF NATURAL GAS 1160320 T/YR VOC

GOOD COMBUSTION PRACTICES 6 LB/H BACT-PSD

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF ELECTRICITY 200 T/YR VOC

SCRAP MANAGEMENT PLAN. THERMAL OXIDIZER AND MAINTAINING A NEGATIVE PRESSURE AT THE DEC AIR GAP 18 LB/H BACT-PSD

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (STACK EMISSIONS) EAF ELECTRICITY 70 T/H VOC 20.02 LB/H BACT-PSD 

AL-0202 CORUS TUSCALOOSA 6/3/2003 ELECTRIC ARC FURNACE EAF 160 T/H VOC

DEC AND GOOD SCRAP QUALITY 20.8 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 ELECTRIC ARC FURNACE EAF ELECTRIC 110 T/H MELT VOC

DIRECT EVACUATION CONTROL AND OPERATIONAL PRACTICES 22 LB/H BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998 FURNACE, ELECTRIC ARC #5 EAF 100 T/H OF STEEVOC

SCRAP MANAGEMENT PLAN EXISTS 30 LB/H BACT-PSD 

IA-0031 IPSCO STEEL INC 3/14/1996

ELECTRIC ARC FURNACE/STEEL FOUNDRY EAF ELECTRICITY 230 T/H VOC

DEC/ELBOW SLOT/POST COMBUSTION/WATER COOLED DUCT 31 LB/H BACT-PSD 

AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 EAF EAF 425 t/h VOC SCRAP MANAGEMENT 44.1 LB/H BACT-PSD 

AL-0197

NUCOR STEEL DECATUR, LLC 7/11/2002 ELECTRIC ARC FURNACE, (2) EAF 440 T/H VOC 88 LB/H BACT-PSD 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 ELECTRIC ARC FURNACE EAF ELECTRICITY 350 t/h VOC 122.5 LB/H BACT-PSD 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 7, P905 EAF 85 T/H VOC

DEC GAP HELPS TO BURN VOC. LOOKED AT THERMAL INC. IT WOULD COST $254,000 PER TON (INFEASIBLE) 29.75 LB/H N/A 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H VOC

DEC GAP HELPS TO BURN

UP VOC. LOOKED AT THERMAL INCINERATOR, IT WOULD COST $254,000 PER 57.75 LB/H N/A 

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type FUEL 

THROUGH

PUT UNITS

POLLUTANT Control Equipment EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 EAF EAF NATURAL GAS 200 T/H VOC 0.1 LB/T Other Case-by-Case 

TN-0122

HOEGANAES CORPORATION 2/11/2000 ELECTRIC ARC FURNACE (EAF) EAF NATURAL GAS 45 MVA/70.4 MMVOC 0.11 LB/H Other Case-by-Case 

CO-0054

CF & I STEEL L.P. DBA

ROCKY MOUNTAIN STEEL MILLS 6/21/2004 ELECTRIC ARC FURNACE (EAF) EAF ELECTRIC PO 156 T/H VOC

PROCESS AND RAW MATERIAL CONTROLS. 0.13 LB/T Other Case-by-Case

PA-0178

ELLWOOD QUALITY STEELS CO. 4/30/2001 ELECTRIC ARC FURNACE EAF NATURAL GAS 53 T/BATCH VOC

DIRECT EVACUATION SYSTEM 0.3 LB/T Other Case-by-Case 

PA-0214

J & L SPECIALTY STEEL,INC. 4/2/2003 ELECTRIC ARC FURNACE, (2) EAF NATURAL GAS 720000 T/YR VOC 0.82 LB/H Other Case-by-Case 

BACT-PSD VOC lb/t steel Emission Limits

MIN 0.030 lb/t steel MIN 

MAX 0.427 lb/t steel MAX 

MEDIAN 0.150 lb/t steel MEDIAN 

COUNT 11 CASES COUNT 

EAF RBLC VOC BACT Limits Summary

Other (non-BACT)

Em

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISSION LIMIT 2 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998 FURNACE, ELECTRIC ARC #5 EAF 100 T/H OF STEEL FL

CONTROLLED BY BAGHOUSE 0.54 LB/H BACT-PSD 2.

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR FL

PROCESS OPERATIONS 0.68 LB/H BACT-PSD

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 EAF EAF 200 T/H FL 1.4 LB/H Other Case-by-Case

BACT-PSD FL lb/t steel Emission Limits

EAF RBLC FL BACT Limits Summary

Other (non-BACT)-case-by-case FL lb/t 

Limits

No Performance Limits No Performance Limit

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISSI

LIMIT 

AR-0077 BLUEWATER PROJECT 7/22/2004 ELECTRIC ARC FURNACE (EAF) EAF 350 t/h PB FABRIC FILTER 0.0009 LB/T BACT-PSD

KY-0094

NORTH AMERICAN STAINLESS 12/1/2003 EAF EAF 154 t/batch PB BAGHOUSE 0.001 LB/T BACT-PSD 

IN-0073

QUALITECH STEEL CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H PB BAGHOUSE 0.07 LB/H BACT-PSD 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR PB BAGHOUSE. SEE NOTES 0.114 LB/H BACT-PSDMI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF 560000 T/YR PB BAGHOUSE 0.13 MG/M3 BACT-PSD 

NJ-0040 CO-STEEL RARITAN 12/19/1996 ELECTRIC ARC FURNACE EAF 1160320 T/YR PB BAGHOUSE 0.22 LB/H BACT-PSD*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (STACK EMISSIONS) EAF 70 T/H PB

BAGHOUSE AND DUST HANDLING SYSTEM. USE OF DIRECT-SHELL EVACUATION CONTROL SYSTEM. USE OF SEGMENTED CANOPY HOOD, SCAVENGER DUCTING, CROSS-DRAFT PARTITIONING AND CLOSED ROOF MONITORS. 0.25 LB/H BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998 FURNACE, ELECTRIC ARC #5 EAF 100 T/H OF STEEL PB CONTROLLED BY BAGHOUSE 0.3 LB/H BACT-PSD 

AR-0021

QUANEX CORPORATION - MACSTEEL DIVISION 2/18/1998 ELECTRIC ARC FURNACES, 2 EAF 86 T/H PB

POSITIVE PRESSURE, MULTICOMPARTMENT, FABRIC FILTERBAGHOUSE 0.3 LB/H BACT-PSD 

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 FURNACE, ELECTIC ARC EAF 50 T/H PB BAGHOUSE - 3% OF BAGHOUSE DUST 0.4 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 ELECTRIC ARC FURNACE EAF 110 T/H MELT PB BAGHOUSE 0.55 LB/H BACT-PSD 

FL-0192

AMERISTEEL CORPORATION 9/28/1999 ELECTRIC ARC FURNACE EAF 720000 T/YR PB BAGHOUSES 0.7 LB/H BACT-PSD 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 ELECTRIC ARC FURNACE EAF 350 t/h PB BAGHOUSE 0.819 LB/H BACT-PSD 

TN-0155

NUCOR STEEL CORPORATION 11/6/2000 ELECTRIC ARC FURNACE EAF 150 T/H PB

LEAD MANAGEMENT AND ABATEMENT PROGRAM, EAF BAGHOUSE BACT-PSD

OH-0245 [a]

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 7, P905 EAF 85 T/H PB

FABRIC FILTER, DIRECT EVACUATION CONTROL (DEC) AND BUILDING EVACUATION SYSTEM 0.036 LB/H N/A 

OH-0245 [a]

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H PB

FABRIC FILTER, DIRECT EVACUATION CONTROL (DEC) AND BUILDING EVACUATION SYSTEM 0.036 LB/H N/A 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 EAF EAF 200 T/H PB FABRIC FILTER 0.26 LB/H N/A

IA-0031 IPSCO STEEL INC 3/14/1996

ELECTRIC ARC FURNACE/STEEL FOUNDRY EAF 230 T/H PB

BAGHOUSE-POLYBAGS 32 MODULES / 260 BAGS PER MODULE 0.13 LB/H Other Case-by-Case 

CO-0054

CF & I STEEL L.P. DBA ROCKY MOUNTAIN 

STEEL MILLS 6/21/2004 ELECTRIC ARC FURNACE (EAF) EAF 156 T/H LEAD OXIDE

SELECT RAW MATERIAL TO MINIMIZE LEAD INPUT AND CONTROL OPERATING TEMPERATURE TO FIX VAPOR LEAD TO THE PM TO BE REMOVED WITH HIGHEFFICIENCY FF. 0.00057 LB/T Other Case-by-Case

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (FUGITIVE EMISSIONS) EAF 70 T/H PB

USE OF SEGMENTED CANOPY HOOD, SCAVENGER DUCTING, CROSS-DRAFT PARTITIONING AND CLOSED ROOF MONITORS. 0.01 T/YR

BACT-PSD Pb lb/t steel Emission Limits

MIN 0.00090 lb/t steel MIN 0.0

MAX 0.00100 lb/t steel MAX 0.0

MEDIAN 0.00095 lb/t steel MEDIAN 0.0

COUNT 2 CASES COUNT 

Other (non-BACT)-case-by-case P

EAF 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 a stack 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS E

AR-0077 BLUEWATER PROJECT 7/22/2004 LADLE METALLURGY FURNACE LMF 350 T/H PM10 FABRIC FILTER 0.0018 GR/DSCF BACT-PSD IN-0073

QUALITECH STEEL CORP. 10/31/1996

LADLE METALLURGY STATION (LMS) LMF 135 T/H PM10

ADDITIVES ADDED UNDER HOOD ONLY, ARTIFICIAL SLAG ADDED BY CHUTE, COVERING LADLE IF TRANSFER DELAYEDAND ARGON STIRRING UNDER A HOOD. 0.0032 GR/DSCF BACT-PSD 

IN-0108 NUCOR STEEL 11/21/2003

LADLE METALLURGY FURNACES (2) LMF 502 T/H PM10

BAGHOUSE. CONTROL METHOD: STACK TESTING AND VISIBLE EMISSION NOTATIONS 0.0052 GR/DSCF BACT-PSD 

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, LADLE METALLURGY LMF 225 T/H PM10 FABRIC FILTER. 0.0052 GR/DSCF BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 LADLE METALLURGY FURNACE LMF 110 T/H PM10 BAGHOUSE 2.2 LB/H BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998

METALLURGICAL STATION, LADLE, #5 LMF 100 T/H OF STEEL PM10 CONTROLLED BY BAGHOUSE 2.8 LB/H BACT-PSD 

*AR-0086

NUCOR-YAMATO STEEL COMPANY, BLYTHEVILLE MILL 6/11/2004 LMF #1 BAGHOUSE, SN-35 LMF 250 T/YR STEEL PM10 FABRIC FILTER 7 LB/H BACT-PSD 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

LADLE METALLURGY FACILITY (LMF), P123 LMF PM10

FABRIC FILTER. NO STACK TEST FOR PM10. 2.44 LB/H N/A 

OH-0246

THE TIMKEN 

COMPANY/FAIRCREST PLANT 2/20/2003 LADLE REFINER LMF PM10 0.52 LB/H Other Case-by-Case

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 LADLE METALLURGY FURNACE LMF 350 t/h PM10 2.4 LB/H 

BACT-PSD PM10 gr/dscf steel Emission Limits

MIN 0.0018 GR/DSCF MIN 

MAX 0.0052 GR/DSCF MAX 

MEDIAN 0.0042 GR/DSCF MEDIAN 

COUNT 6 CASES COUNT 

LMF RBLC PM10 BACT Limits Summary

Other (non-BACT)-case

Emissio

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS E

IN-0108 NUCOR STEEL 11/21/2003

LADLE METALLURGY FURNACES (2) LMF 502 T/H PM FILTERAB

BAGHOUSE. COMPLIANCE METHOD: STACK TESTING AND VISIBLE EMISSION NOTATIONS. 0.0018 GR/DSCF BACT-PSD 

AR-0021

QUANEX CORPORATION - MACSTEEL DIVISION 2/18/1998 FURNACE, LADLE METALLURGY LMF 0 PM

ROUTED TO EAF BAGHOUSES. MULTICOMPARTMENT POSITIVE PRESSURE BAGHOUSES. 0.0018 GR/DSCF BACT-PSD 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 LADLE METALLURGY FURNACE LMF 350 t/h PM BAGHOUSE 0.0032 GR/DSCF BACT-PSD 

IN-0073

QUALITECH STEEL CORP. 10/31/1996

LADLE METALLURGY STATION (LMS) LMF 135 T/H PM

ADDITIVES ADDED UNDER HOOD ONLY, ARTIFICIAL SLAG ADDED BY CHUTE, COVERING LADLE IF TRANSFER DELAYEDAND ARGON STIRRING UNDER A HOOD. 0.0032 GR/DSCF BACT-PSD 

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 LADLE METALLURGY STATION LMF 50 T/H PM BAGHOUSE. 0.0052 GR/DSCF BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998

METALLURGICAL STATION, LADLE, #5 LMF 100 T/H OF STEEL PM CONTROLLED BY BAGHOUSE 0.0052 GR/DSCF BACT-PSD 

TX-0417 NUCOR CORP. 1/15/2003

LADLE METALLURGY FURNACE STATIONS (2) LMF PM

CLOSE-CAPTURE HOOD AND ROOF CANOPY HOOD OVER THE CASTING DECK, RESULTING IN 98.8% CAPTURE, THEN ROUTED TO LMF/CASTER BAGHOUSE. 0.0052 GR/DSCF BACT-PSD

TX-0399 NUCOR JEWETT PLANT 1/5/2003 WEST LMF/CASTER BUILDING LMF PM 11.63 LB/H BACT-PSD 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

LADLE METALLURGY FACILITY (LMF), P123 LMF PM FABRIC FILTER 3.12 LB/H N/A 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 LADLE REFINER LMF PM 0.68 LB/H Other Case-by-Case

TN-0122

HOEGANAES CORPORATION 2/11/2000

LADLE METALLURGY FACILITY (LMF) LMF 110650 LB MOLTEN STEEL/H PM BAGHOUSE 1.53 LB/H Other Case-by-Case 

BACT-PSD PM GR/DSCF Emission Limits

MIN 0.0018 GR/DSCF MIN 

MAX 0.0052 GR/DSCF MAX 

MEDIAN 0.0032 GR/DSCF MEDIAN 

COUNT 7 CASES COUNT 

LMF RBLC PM BACT Limits Summary

Other (non-BACT)-case-b

Li

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME

PERMIT 

DATE 

PROCESS 

NAME Proc Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS 

TX-0399

NUCOR JEWETT PLANT 1/5/2003

WEST LMF/CASTER BUILDING LMF SO2 0.04 LB/H BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998

METALLURGICAL STATION, LADLE, #5 LMF 100 T/H OF STEEL SO2 6 LB/H BACT-PSD 

*AR-0086

NUCOR-YAMATO STEEL COMPANY, BLYTHEVILLE MILL 6/11/2004

LMF #1 BAGHOUSE, SN35 LMF 250 T/YR STEEL SO2 LOW SULFUR COKE USAGE 90 LB/H BACT-PSD 

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001

FURNACE, LADLE METALLURGY LMF 225 T/H SO2 LOW SULFUR COKE USE. 0.076 LB/T BACT-PSD

AR-0077

BLUEWATER PROJECT 7/22/2004

LADLE METALLURGY FURNACE LMF 350 T/H SO2 0.08 LB/T BACT-PSD

IN-0108 NUCOR STEEL 11/21/2003

LADLE METALLURGY FURNACES (2) LMF 502 T/H SO2 0.185 LB/T BACT-PSD 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

LADLE METALLURGY FACILITY (LMF), P123 LMF SO2

LOOKED AT CHARGE SUBSTITUTION (NOT FEASIBLE) & FLUE GAS DESULFURIZATION. LOOKED AT ADDON CONTROLS (WET SCRUBBER, SPRAY DRYER ABORPTION AND DRY SORBENT INJECTION) 525

LB/3 H PERIOD N/A 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 LADLE REFINER LMF SO2 0.94 LB/H Other Case-by-Case

TN-0122

HOEGANAES CORPORATION 2/11/2000

LADLE METALLURGY FACILITY (LMF) LMF 110650 LB MOLTEN STEEL/H SO2 2.32 LB/H Other Case-by-Case 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005

LADLE METALLURGY FURNACE LMF 350 t/h SO2 14 LB/H 

OH-0276 CHARTER STEEL 4/14/2003

LADLE METALLURGY FURNACE LMF 110 T/H SO2 220 LB/H 

BACT-PSD SO2 lb/t steel Emission Limits

MIN 0.0760 lb/t steel MIN 

MAX 0.3600 lb/t steel MAX 

MEDIAN 0.1325 lb/t steel MEDIAN 

COUNT 4 CASES COUNT 

LMF RBLC SO2 BACT Limits Summary

Other (non-BACT)

Em

page 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 MA
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID 

FACILITY 

NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS

CASE-BYCASE 

BASIS 

EM

L

IN-0108 NUCOR STEEL 11/21/2003

LADLE METALLURGY FURNACES (2) LMF 502 T/H NOX 0.0176 LB/T BACT-PSD 

AR-0077

BLUEWATER PROJECT 7/22/2004

LADLE METALLURGY FURNACE LMF 350 T/H NOX 0.02 LB/T BACT-PSD

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001

FURNACE, LADLE METALLURGY LMF 225 T/H NOX 0.02 LB/T BACT-PSD

OH-0276 CHARTER STEEL 4/14/2003

LADLE METALLURGY FURNACE LMF 110 T/H NOX 1.65 LB/H BACT-PSD 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 LADLE REFINER LMF NOX LOW NOX BURNERS 1.67 LB/H BACT-PSD

TN-0122

HOEGANAES CORPORATION 2/11/2000

LADLE METALLURGY FACILITY (LMF) LMF 110650 LB MOLTEN STEEL/H NOX

PROPER COMBUSTION CONTROL 2.23 T/MO BACT-PSD

VA-0241

ELECTRIC STEEL CORPORATION 11/6/1998

METALLURGICAL STATION, LADLE, #5 LMF 100 T/H OF STEEL NOX 6 LB/H BACT-PSD 

TX-0399

NUCOR JEWETT PLANT 1/5/2003

WEST LMF/CASTER BUILDING LMF NOX 6.36 LB/H BACT-PSD 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005

LADLE METALLURGY FURNACE LMF 350 t/h NOX 18.9 LB/H 

TN-0157

HOEGANAES CORP. 12/31/2003

LADLE METALLURGY FACILITY LMF NOX GOOD COMBUSTION PRACTICE. 26.7 TONS/YEAR

BACT-PSD NOx lb/t steel Emission Limits

MIN 0.0176 lb/t steel MIN NA 

MAX 0.0200 lb/t steel MAX NA 

MEDIAN 0.0200 lb/t steel MEDIAN NA 

COUNT 3 CASES COUNT NA 

LMF RBLC NOx BACT Limits Summary

Other (non-BACT)-

steel Emi

page 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 RBL
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

LI

AR-0077 BLUEWATER PROJECT 7/22/2004 LADLE METALLURGY FURNACE LMF 350 T/H CO SIDE DRAFT AIR GAP 0.05 LB/T BACT-PSD

IN-0108 NUCOR STEEL 11/21/2003

LADLE METALLURGY FURNACES (2) LMF 502 T/H CO 0.0713 LB/T BACT-PSD 

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, LADLE METALLURGY LMF 225 T/H CO OXIDATION WITH SIDE DRAFT AIR GAP 0.28 LB/T BACT-PSD

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 LADLE METALLURGY STATION LMF 50 T/H CO

DIRECT SHEEL EVACUATION CONTROL (DEC) SYSTEM WITH AIR GAP. 0.6 LB/T BACT-PSD 

TX-0399 NUCOR JEWETT PLANT 1/5/2003 WEST LMF/CASTER BUILDING LMF CO 5.34 LB/H BACT-PSD 

TN-0122

HOEGANAES CORPORATION 2/11/2000

LADLE METALLURGY FACILITY (LMF) LMF 110650 LB MOLTEN STEEL/H CO PROPER COMBUSTION CONTROL 7.36 T/MO BACT-PSD

AL-0202 CORUS TUSCALOOSA 6/3/2003 LADLE METALLURGY STATION LMF 160 T/H CO 32 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 LADLE METALLURGY FURNACE LMF 110 T/H CO 33 LB/H BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998

METALLURGICAL STATION, LADLE, #5 LMF 100 T/H OF STEEL CO 48 LB/H BACT-PSD 

*AR-0086

NUCOR-YAMATO STEEL COMPANY, BLYTHEVILLE MILL 6/11/2004 LMF #1 BAGHOUSE, SN-35 LMF 250 T/YR STEEL CO OXIDATION WITH SIDE DRAFT AIR GAPS 70 LB/H BACT-PSD 

TN-0157 HOEGANAES CORP. 12/31/2003 LADLE METALLURGY FACILITY LMF CO GOOD COMBUSTION PRACTICE. 88.3 TONS/YEAR BACT-PSD

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 LADLE REFINER LMF CO 0.91 LB/H Other Case-by-Case

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 LADLE METALLURGY FURNACE LMF 350 t/h CO 140 LB/H 

BACT-PSD CO lb/t steel Emission Limits

MIN 0.005 lb/t steel MIN NA 

MAX 0.600 lb/t steel MAX NA 

MEDIAN 0.136 lb/t steel MEDIAN NA 

COUNT 6 CASES COUNT NA 

LMF RBLC CO BACT Limits Summary

Other (non-BACT)-case-by-c

Lim

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGHP

UT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS 

AR-0077 BLUEWATER PROJECT 7/22/2004 LADLE METALLURGY FURNACE LMF 350 T/H VOC 0.005 LB/T 

IN-0108 NUCOR STEEL 11/21/2003

LADLE METALLURGY FURNACES (2) LMF 502 T/H VOC 0.0086 LB/T 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998

METALLURGICAL STATION, LADLE, #5 LMF 100 T/H OF STEEL VOC 0.2 LB/H 

OH-0276 CHARTER STEEL 4/14/2003 LADLE METALLURGY FURNACE LMF 110 T/H VOC 0.22 LB/H 

TX-0399 NUCOR JEWETT PLANT 1/5/2003 WEST LMF/CASTER BUILDING LMF VOC 0.35 LB/H 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 LADLE METALLURGY FURNACE LMF 350 t/h VOC 12.25 LB/H 

TN-0122

HOEGANAES CORPORATION 2/11/2000

LADLE METALLURGY FACILITY (LMF) LMF 110650 LB MOLTEN STEEL/H VOC 0.04 T/MO 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 LADLE REFINER LMF VOC 0.07 LB/H 

BACT-PSD VOC lb/t steel Emission Limits

MIN 0.0050 lb/t steel 

MAX 0.0086 lb/t steel 

MEDIAN 0.0068 lb/t steel 

COUNT 2 CASES 

LMF RBLC VOC BACT Lim

page 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 
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT Control Equipment EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998

METALLURGICAL STATION, LADLE, #5 LMF 100 T/H OF STEEL FL CONTROLLED BY BAGHOUSE 0.16 LB/H BACT-PSD 

BACT-PSD FL lb/t steel Emission Limits

LMF RBLC FL BACT Limits Summary

Other (non-BACT

Em

No Performance Limits No Per

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT Control Equipment EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS 

OH-0276 CHARTER STEEL 4/14/2003 LADLE METALLURGY FURNACE LMF 110 T/H PB BAGHOUSE 0.02 LB/H BACT-PSD 

TX-0399 NUCOR JEWETT PLANT 1/5/2003 WEST LMF/CASTER BUILDING LMF LEAD OXIDE 0.05 LB/H BACT-PSD 

VA-0241

ROANOKE ELECTRIC STEEL CORPORATION 11/6/1998

METALLURGICAL STATION, LADLE, #5 LMF 100 T/H OF STEEL PB CONTROLLED BY BAGHOUSE 0.09 LB/H BACT-PSD 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 LADLE METALLURGY FURNACE LMF 350 t/h PB BAGHOUSE 0.126 LB/H BACT-PSD 

BACT-PSD Pb gr/dscf Emission Limits

MIN 0.0001 GR/DSCF MIN N

MAX 0.0001 GR/DSCF MAX N

MEDIAN 0.0001 GR/DSCF MEDIAN N

COUNT 1 CASES COUNT N

LMF RBLC Pb BACT Limits Summary

Other (non-BACT

Em

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

LI

WI-0206 SAUKVILLE PLANT 12/19/2003 MELT SHOP, P01, S01 MS 137.5 T/D PM10

REVERSE AIR BAGHOUSE (EXISTING) 0.0014 GR/DSCF BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H PM10

FURNACE SHAFT EVACUATION; POSITIVE P BAGHOUSE WITH A DESIGN FLOW OF 1,100,000 ACFM ($550/TON REMOVED) 0.0018 GR/DSCF BACT-PSD 

IL-0068

KEYSTONE STEEL & WIRE COMPANY 6/1/2000 FURNACE, EAF & LMF MS 1200000 T/Y PM10

BAGHOUSE; INCLUDES

EMISSIONS OF PM, PM10 AND PB. PM EMISSION FACTOR IS 0.27 LB/TON STEEL PRODUCED. PB EMISSION FACTOR IS 0.006 LB/TON STEEL PRODUCED. 0.0018 GR/DSCF BACT-PSD 

FL-0192

AMERISTEEL CORPORATION 9/28/1999

ELECTRIC ARC FURNACE AND MELT SHOP MS 720000 T/YR PM10

TWO BAGHOUSES, ONE FOR EAF AND ONE FOR THE MELT SHOP. EMISSION LIMIT OF .0042 GR/DSCF IN THE FIRST YEAR. 0.0034 GR/DSCF BACT-PSD 

OK-0087

EJIW ARDMORE FOUNDRY INC. 9/9/2003 MELT AREA MS 560 T/D PM10 BAGHOUSE 0.0045 GR/DSCF BACT-PSD 

IN-0109 BETA STEEL CORP. 5/30/2003 STEEL FURNACE MELTSHOP MS 1100000 T/YR PM10

BAGHOUSE, ROOF CANOPIES 0.0052 GR/DSCF BACT-PSD 

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H PM10

BAGHOUSES. COMPLIANCE METHOD: STACK TESTING AND BAG LEAK DETECTION SYSTEM 0.0052 GR/DSCF BACT-PSD 

WI-0094

CHARTER STEEL DIVISION 2/26/1997

ELECTRIC ARC FURNACE, MELT SHOP, P01, S01 MS 450000 T/YR PM10 BAGHOUSE 3.03 LB/H BACT-PSD 

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR PM10 BAGHOUSE 5.56 LB/H BACT-PSD 

TX-0399 NUCOR JEWETT PLANT 1/5/2003 EAF, LMF, CASTER MELTSHOP MS 240 T/H PM10 FF 34.21 LB/H BACT-PSD 

*OH-0285

NORTH STAR BHP STEEL, LTD 8/5/2003

ELECTRIC ARC FURNACE WITH TWO LADLE MELT FURNACES MS 315 T STEEL/H PM10 TWO BAGHOUSES 167.2

T/ROLLING 12-MONTHS BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998 MELTSHOP, MISC. OPERATIONS MS 53 MMBTU/H PM10 12 LB/MMCF Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS A MS PM10 BAGHOUSE 17.9 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS B MS PM10 BAGHOUSE 26 LB/H Other Case-by-Case 

OK-0048 GRIFFIN WHEEL CO 10/18/1999

ELECTRIC ARC FURNACE/LADLE METALLURGY FURNACE MS PM10

4TH HOLE EVACUATION W/ A STORAGE TYPE CANOPY 83.2 T/YR Other Case-by-Case

BACT-PSD PM10 GR/DSCF Emission Limits

MIN 0.0014 GR/DSCF MIN 

MAX 0.0052 GR/DSCF MAX 

MEDIAN 0.0018 GR/DSCF MEDIAN 

COUNT 10 CASES COUNT 

MS RBLC PM10 BACT Limits Summary

Other (non-BACT)-case-b

Emission L

page 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 2
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID 

FACILITY 

NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUG

HPUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

L

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR PM BAGHOUSE 6.05 LB/H BACT-PSD 

WI-0094

CHARTER STEEL DIVISION 2/26/1997

ELECTRIC ARC FURNACE, MELT SHOP, P01, S01 MS 450000 T/YR PM BAGHOUSE 6.05 LB/H BACT-PSD 

AR-0033

NUCOR YAMATO STEEL COMPANY 3/28/2000

2 ELECTRIC ARC FURNACES,MELTSHOP, TUNDISH MS 450 T/H PM

MULTI-COMPARTMENT POSITIVE PRESSURE BAGHOUSE 24.7 LB/H BACT-PSD 

NC-0064 NUCOR STEEL 4/20/1999

STEEL PLANT, MELT SHOP (EAF,LMS,CSC) MS 250 T/H PM

NEGATIVE PRESSURE BAGHOUSE 0.0032 GR/DSCF BACT-PSD 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS STEEL/H PM

POSITIVE PRESSURE REVERSE AIR CLEANING BAGHOUSE- 3 MAIN FANS, 2 REVERSE AIR FANS. UNCAPTURED FUGITIVES VENTED THRU ROOF MONITORS. 0.0052 GR/DSCF BACT-PSD 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP ROOF MONITORS MS PM 4.8 LB/H BACT-PSD 

*OH-0285

NORTH STAR BHP STEEL, LTD 8/5/2003

ELECTRIC ARC FURNACE WITH TWO LADLE MELT FURNACES MS 315 T STEEL/H PM 46.9

T/ROLLING 12 MONTHS BACT-PSD

TX-0399

NUCOR JEWETT PLANT 1/5/2003 EAF, LMF, CASTER MELTSHOP MS 240 T/H PM FF 55.55 LB/H BACT-PSD 

OK-0048

GRIFFIN WHEEL CO 10/18/1999

ELECTRIC ARC FURNACE/LADLE METALLURGY FURNACE MS PM

4TH HOLE EVACUATION W/ A STORAGE TYPE CANOPY 86.1 T/YR OF PM BACT-PSD 

TN-0122

HOEGANAES CORPORATION 2/11/2000 MELT SHOP OPERATIONS MS PM FABRIC FILTER 0.005 GR/DSCF Other Case-by-Case 

MI-0275

RAVENNA CASTING CENTER, INC. 4/14/2000 IRON MELT SHOP MS 27 T/H PM FABRIC FILTER. 0.01

LB/1000 LB EXHAUST Other Case-by-Case 

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP ROOF MONITORS MS PM 4.8 LB 

BACT-PSD PM GR/DSCF Emission Limits

MIN 0.0015 GR/DSCF MIN 

MAX 0.0052 GR/DSCF MAX 

MEDIAN 0.0018 GR/DSCF MEDIAN 

COUNT 5 CASES COUNT 

MS RBLC PM BACT Limits Summary

Other (non-BACT)-cas

Emission 

page 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 2
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS POLLUTANT CONTROL EQUIPMENT

EMISSION 

LIMIT 1 UNITS

CASE-BY-CASE 

BASIS 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS PM FILTERABLE

ONE (1) BAGHOUSE, NEGATIVE PRESSURE, REVERSE AIR CLEANING, THREE FEET PER MINUTE FILTER VELOCITY, AND 1.16 MILLION DSCFM FLOW RATE 0.0018 GR/DSCF BACT-PSD 

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H PM FILTERABLE

BAGHOUSES 1 & 2. EACH BAGHOUSE CAN SUFFICIENTLY CONTROL EMISSIONS INDEPENDENTLY. COMPLIANCE METHOD: STACK TESTING AND BAG LEAK DETECTION SYSTEM. 0.0018 GR/DSCF BACT-PSD 

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS PM FILTERABLE

ONE (1) BAGHOUSE, NEGATIVE PRESSURE, REVERSE AIR CLEANING, THREE FEET PER MINUTE FILTER VELOCITY, AND 1.16 MILLION DSCFM FLOW RATE 0.0018 GR/DSCF 

BACT-PSD PM Filterable gr/dscf Emission Limits

MIN 0.0018 GR/DSCF MIN 

MAX 0.0018 GR/DSCF MAX 

MEDIAN 0.0018 GR/DSCF MEDIAN 

COUNT 3 CASES COUNT 

MS RBLC PM Filterable BACT Limits Summary

Other (non-BACT

gr/dsc

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGHP

UT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CAS

BASIS 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS STEEL/H SO2 0.2 LB/T OF STEEL BACT-PSD 

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H SO2

SCRAP MANAGEMENT PLAN. COMPLIANCE METHOD: SO2 CEM. 0.25 LB/T BACT-PSD 

IN-0109 BETA STEEL CORP. 5/30/2003 STEEL FURNACE MELTSHOP MS 1100000 T/YR SO2 0.33 LB/T BACT-PSD 

NC-0064 NUCOR STEEL 4/20/1999

STEEL PLANT, MELT SHOP (EAF,LMS,CSC) MS 250 T/H SO2 SCRAP STEEL MANAGEMENT PLAN 0.35 LB/T BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H SO2 0.7 LB/T BACT-PSD 

IL-0068

KEYSTONE STEEL & WIRE COMPANY 6/1/2000 FURNACE, EAF & LMF MS 1200000 T/Y SO2

USE OF LOW SULFUR INJECTION COKE (0.65% OR LESS). WORK PRACTICES 2

LB/T STEEL PRODUCED BACT-PSD

PA-0235 KOPPEL STEEL CORP. 11/26/2003 MELT SHOP MS 598000 T/YR SOX 50 LB/H BACT-PSD

AR-0033

NUCOR YAMATO STEEL COMPANY 3/28/2000

2 ELECTRIC ARC FURNACES,MELTSHOP, TUNDISH MS 450 T/H SO2

LOW SULFUR COKE AND SCRAP MANAGEMENT 67.5 LB/H BACT-PSD 

WI-0094

CHARTER STEEL DIVISION 2/26/1997

ELECTRIC ARC FURNACE, MELT SHOP, P01, S01 MS 450000 T/YR SOX

NATURAL GAS. BASIS IS SYNTHETIC MINOR LIMIT 0.176 LB/H Other Case-by-Case

WI-0206 SAUKVILLE PLANT 12/19/2003 MELT SHOP, P01, S01 MS 137.5 T/D SO2

THE AMOUNT OF STEEL TAPPED MAY NOT EXCEED 62,500 TONS PER MONTH, AS DETERMINED BY AN AVERAGE OVER ANY 12 CONSECUTIVE MONTHS. THIS RESTRICTION IS PROPOSED BY THE PERMITTEE TO LIMIT THE POTENTIAL TO EMIT OF SULFUR DIOXIDEAND 0.176 LB/T Other Case-by-Case

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR SO2

THE SO2 LIMITS WERE SYNTHETIC MINOR LIMITS TO AVOID TRIGGERING PSD. 0.176 LB/T Other Case-by-Case

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998 MELTSHOP, MISC. OPERATIONS MS 53 MMBTU/H SO2 0.6 LB/MMCF Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS A MS SO2 NONE INDICATED 5.1 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS B MS SO2 NONE INDICATED 8.7 LB/H Other Case-by-Case 

TN-0122

HOEGANAES CORPORATION 2/11/2000 MELT SHOP OPERATIONS MS SO2 13.14 LB/H Other Case-by-Case 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS SO2 SCRAP MANAGEMENT 0.35 LB/T STEEL 

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS SO2 SCRAP MANAGEMENT 0.35 LB/T STEEL 

BACT-PSD SO2 and SOx lb/t steel Emission Limits

MIN 0.15 lb/t steel MIN 

MAX 2.00 lb/t steel MAX 

MEDIAN 0.35 lb/t steel MEDIAN 

COUNT 9 CASES COUNT 

MS RBLC SO2 and SOx BACT Limits Summary

Other (non-BACT)

stee

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISSIO

LIMIT 

WI-0094

CHARTER STEEL DIVISION 2/26/1997

ELECTRIC ARC FURNACE, MELT SHOP, P01, S01 MS 450000 T/YR NOX

CONTROL OF OPERATING PARAMETERS TO ENSURE PROPER OPERATION OF THE EMISSIONS UNITS 0.51 LB/H BACT-PSD

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS A MS NOX NONE INDICATED 6 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS B MS NOX NONE INDICATED 10.3 LB/H BACT-PSD 

TN-0122

HOEGANAES CORPORATION 2/11/2000 MELT SHOP OPERATIONS MS NOX PROPER COMBUSTION CONTROL 17.14 LB/H BACT-PSD 

AR-0033

NUCOR YAMATO STEEL COMPANY 3/28/2000

2 ELECTRIC ARC FURNACES,MELTSHOP, TUNDISH MS 450 T/H NOX LOW NOX BURNERS. 171 LB/H BACT-PSD 

*OH-0285

NORTH STAR BHP STEEL, LTD 8/5/2003

ELECTRIC ARC FURNACE WITH TWO LADLE MELT FURNACES MS 315 T STEEL/H NOX

DIRECT EVACUATION CONTROL SYSTEM WITH AIR GAP, AND COOLED POST COMBUSTION CHAMBER WITH BURNERS 179.6 LB/H BACT-PSD 

TX-0399 NUCOR JEWETT PLANT 1/5/2003 EAF, LMF, CASTER MELTSHOP MS 240 T/H NOX 215.52 LB/H BACT-PSD 5

TN-0157 HOEGANAES CORP. 12/31/2003 STEEL MELT SHOP MS 76.5 tons/hour NOX LOW NOX BURNERS. 17.87 LB/HR BACT-PSD FL-0192

AMERISTEEL CORPORATION 9/28/1999

ELECTRIC ARC FURNACE AND MELT SHOP MS 720000 T/YR NOX

COMBUSTION PRACTICES. EMISSION LIMIT UNITS: LB/T OF STEEL (PRIMARY), LB/H 24 HR AVE (ALTERNATE). ADDITIONAL EMISSION LIMIT: 118.8 T/YR 0.33 LB/T BACT-PSD 

WI-0206 SAUKVILLE PLANT 12/19/2003 MELT SHOP, P01, S01 MS 137.5 T/D NOX

DEC (DIRECT EVACUATION CONTROL) AND LOW NOX SUPPLEMENTAL BURNERS. ALSO REQUIRES CONTROL OF DEC AND EAF OPERATING PARAMETERS. 0.33 LB/T BACT-PSD

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H NOX

NATURAL GAS FIRED OXY FUEL BURNERS, COMPLIANCE METHOD: NOX CONTINUOUS EMISSIONS MONITOR. 0.35 LB/T BACT-PSD 

IN-0109 BETA STEEL CORP. 5/30/2003 STEEL FURNACE MELTSHOP MS 1100000 T/YR NOX 0.45 LB/T BACT-PSD 

NC-0064 NUCOR STEEL 4/20/1999

STEEL PLANT, MELT SHOP (EAF,LMS,CSC) MS 250 T/H NOX 0.51 LB/T BACT-PSD 

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR NOX LOW NOX BURNER 0.51 LB/T BACT-PSD

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H NO2 LOW NOX BURNERS; WORK PRACTICES 0.7 LB/T BACT-PSD 

OK-0048 GRIFFIN WHEEL CO 10/18/1999

ELECTRIC ARC FURNACE/LADLE METALLURGY FURNACE MS NOX 0.2 LB/T STEEL BACT-PSD

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS STEEL/H NOX 0.35 LB/T STEEL BACT-PSD 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS NOX 0.36 LB/T STEEL BACT-PSD 

IL-0068

KEYSTONE STEEL & WIRE COMPANY 6/1/2000 FURNACE, EAF & LMF MS 1200000 T/Y NOX

DEC, OXY/FUEL BURNERS. WORK PRACTICES 0.51

LB/T STEEL PRODUCED BACT-PSD

PA-0237

J & L SPECIALTY STEEL, INC. 4/2/2003 MELT SHOP MS 720000 T/YR NOX

LAER DETERMINED TO BE PROPER OPERATION OF DIRECT EVACUATION CONTROL 504 T/YR LAER

MI-0275

RAVENNA CASTING CENTER, INC. 4/14/2000 IRON MELT SHOP MS 27 T/H NO2 3.1 LB/H Other Case-by-Case 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998 MELTSHOP, MISC. OPERATIONS MS 53 MMBTU/H NOX 100 LB/MMCF Other Case-by-Case 

PA-0235 KOPPEL STEEL CORP. 11/26/2003 MELT SHOP MS 598000 T/YR NOX 165 T/YR Other Case-by-Case

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP ROOF MONITORS MS NOX 9.6 LB 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP ROOF MONITORS MS NOX 9.6 LB/H 

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS NOX 0.36 LB/T STEEL 

BACT-PSD NOx lb/t steel Emission Limits

MIN 0.20 lb/t steel MIN NA 

MAX 0.70 lb/t steel MAX NA 

MEDIAN 0.36 lb/t steel MEDIAN NA 

COUNT 12 CASES COUNT NA 

MS RBLC NOx BACT Limits Summary

Other (non-BACT)-case-by-ca

Emission Lim

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS E

IL-0068

KEYSTONE STEEL & WIRE COMPANY 6/1/2000 FURNACE, EAF & LMF MS 1200000 T/Y CO

DEC, OXY/FUEL BURNERS, COMBUSTION CHAMBER. WORK PRACTICES 1.34

LB/T STEEL PRODUCED BACT-PSD 

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H CO

DIRECT SHELL EVACUATION (DSE). COMPLIANCE METHOD: CO CEM 2 LB/T BACT-PSD 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS STEEL/H CO 2.76 LB/T OF STEEL BACT-PSD 

FL-0192

AMERISTEEL CORPORATION 9/28/1999

ELECTRIC ARC FURNACE AND MELT SHOP MS 720000 T/YR CO

DIRECT EVACUATION CONTROL/ AIR GAP OXIDATION. EMISSION LIMIT UNITS: LB/T OF STEEL (PRIMARY), LB/H 24 HR AVE (ALTERNATE)ADDITIONAL EMISSION LIMIT: 1080 T/YR 3 LB/T BACT-PSD 

WI-0206 SAUKVILLE PLANT 12/19/2003 MELT SHOP, P01, S01 MS 137.5 T/D CO

DEC (DIRECT EVACUATION CONTROL) WITH A SECOND HOLE" TO INTRODUCE AIR FOR SECONDARY COMBUSTION AND THE CONTROL OF OPERATING PARAMETERS AND CARBON SOURCE TO ENSURE PROPER OPERATION OF THE EMISSIONS UNITS" 3.5 LB/T BACT-PSD

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR CO

DIRECT EVACUATION CONTROL (DEC) SYSTEM 3.5 LB/T BACT-PSD

WI-0094

CHARTER STEEL DIVISION 2/26/1997

ELECTRIC ARC FURNACE, MELT SHOP, P01, S01 MS 450000 T/YR CO

USE OF A DIRECT EVACUATION CONTROL (DEC) SYSTEM AND THE CONTROL OF OPERATING PARAMETERS TO ENSURE PROPER OPERATION OF THE EMISSIONS UNITS. 3.83 LB/H BACT-PSD

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H CO

DUCTING/EXTERNAL COMBUSTION CHAMBER AT 12 MMBTU/HR; WORK PRACTICES 4 LB/T BACT-PSD 

NC-0064 NUCOR STEEL 4/20/1999

STEEL PLANT, MELT SHOP 

(EAF,LMS,CSC) MS 250 T/H CO

DIRECT SHELL EVACUATION (DSE) PLUS COMBUSTION CHAMBER FOLLOWING CONSTEEL CONVEYOR PREHEATING SECTION. 4 LB/T BACT-PSD 

MI-0275

RAVENNA CASTING CENTER, INC. 4/14/2000 IRON MELT SHOP MS 27 T/H CO

24 TON/HR POURING MAXIMUM PASSES THROUGH FABRIC FILTER/STACK 15.1 LB/H BACT-PSD 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP ROOF MONITORS MS CO 25.7 LB/H BACT-PSD OK-0048 GRIFFIN WHEEL CO 10/18/1999

ELECTRIC ARC FURNACE/LADLE METALLURGY FURNACE MS CO

4TH HOLE FUME CONTROL W/COMBUSTOIN AIR 83.2 T/YR BACT-PSD 

TN-0122

HOEGANAES CORPORATION 2/11/2000 MELT SHOP OPERATIONS MS CO 158.82 LB/H BACT-PSD 

TN-0157 HOEGANAES CORP. 12/31/2003 STEEL MELT SHOP MS 76.5 tons/hour CO

DIRECT EVACUATION CONTROL (DEC) FOR ELECTRIC ARC FURNACE. COMPLIANCE TO BE VERIFIED BY STACK TESTING WITHIN 180 DAYS OF STARTUP OF THE MODIFIED SOURCE. GOOD COMBUSTION CONTROL FROM OTHER EMISSION SOURCES IN THE MELT SHOP. 383 LB/H BACT-PSD 

TX-0399 NUCOR JEWETT PLANT 1/5/2003 EAF, LMF, CASTER MELTSHOP MS 240 T/H CO 537.89 LB/H BACT-PSD IN-0109 BETA STEEL CORP. 5/30/2003 STEEL FURNACE MELTSHOP MS 1100000 T/YR CO DIRECT SHELL EVACUATION (DSE) 817 LB/H BACT-PSD 

AR-0033

NUCOR YAMATO STEEL COMPANY 3/28/2000

2 ELECTRIC ARC FURNACES,MELTSHOP, TUNDISH MS 450 T/H CO AIR GAP 900 LB/H BACT-PSD 

PA-0235 KOPPEL STEEL CORP. 11/26/2003 MELT SHOP MS 598000 T/YR CO 1346 T/YR BACT-PSD *OH-0285

NORTH STAR BHP 

STEEL, LTD 8/5/2003

ELECTRIC ARC FURNACE WITH TWO LADLE MELT FURNACES MS 315 T STEEL/H CO

DIRECT EVACUATION CONTROL SYSTEM WITH AIR GAP, AND COOLED POST COMBUSTION CHAMBER WITH BURNERS 2362.5 LB/H BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998 MELTSHOP, MISC. OPERATIONS MS 53 MMBTU/H CO 21 LB/MMCF Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS A MS CO NONE INDICATED 81.9 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS B MS CO NONE INDICATED 140.8 LB/H Other Case-by-Case 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS CO

DIRECT SHELL EVACUATION (DSE) VIA THE CONSTEEL PROCESS PLUS COMBUSTION CHAMBER (AIR GAP) 2.3 LB/T STEEL 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS E

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS CO

DIRECT SHELL EVACUATION (DSE) VIA THE CONSTEEL PROCESS PLUS COMBUSTION CHAMBER (AIR GAP) 2.3 LB/T STEEL 

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP ROOF MONITORS MS CO 25.7 LB 

BACT-PSD CO lb/t steel Emission Limits

MIN 1.34 lb/t steel MIN NA 

MAX 7.50 lb/t steel MAX NA 

MEDIAN 3.25 lb/t steel MEDIAN NA 

COUNT 14 CASES COUNT NA 

MS RBLC CO BACT Limits Summary

Other (non-BACT)-ca

Emiss

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMIS

LIM

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR VOC

DIRECT EVACUATION CONTROL (DEC)ON ELECTRIC ARC FURNACE 0.06 LB/T BACT-PSD

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H VOC

SCRAP MANAGEMENT PLAN. COMPLIANCE METHOD: STACK TESTING AND TOTAL HYDROCARBON CEM. 0.09 LB/T BACT-PSD 

IN-0109 BETA STEEL CORP. 5/30/2003 STEEL FURNACE MELTSHOP MS 1100000 T/YR VOC

SCRAP MANAGEMENT PROGRAM TO ELIMINATE STEEL SCRAP WITH HIGH RESIDUAL OIL CONTENT. 0.15 LB/T BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H VOC

SCRAP HANDLING PLAN; WORK PRACTICES 0.35 LB/T BACT-PSD 

NC-0064 NUCOR STEEL 4/20/1999

STEEL PLANT, MELT SHOP (EAF,LMS,CSC) MS 250 T/H VOC SCRAP STEEL, MANAGEMENT PLAN 0.35 LB/T BACT-PSD 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS STEEL/H VOC 0.35 LB/T STEEL BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS A MS VOC NONE INDICATED 31.2 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS B MS VOC NONE INDICATED 53.7 LB/H BACT-PSD 

TX-0399 NUCOR JEWETT PLANT 1/5/2003 EAF, LMF, CASTER MELTSHOP MS 240 T/H VOC 103.9 LB/H BACT-PSD 

WI-0094

CHARTER STEEL DIVISION 2/26/1997

ELECTRIC ARC FURNACE, MELT SHOP, P01, S01 MS 450000 T/YR VOC

NATURAL GAS. BASIS IS SYNTHETIC MINOR LIMIT. 0.06 LB/H Other Case-by-Case

WI-0206 SAUKVILLE PLANT 12/19/2003 MELT SHOP, P01, S01 MS 137.5 T/D VOC DEC (DIRECT EVACUATION CONTROL) 0.06 LB/T Other Case-by-Case FL-0192

AMERISTEEL CORPORATION 9/28/1999

ELECTRIC ARC FURNACE AND MELT SHOP MS 720000 T/YR VOC

NEW SHREDDER HAS REDUCED VOC EMISSION POTENTIAL OF AUTOMOBILE GENERATED WASTE BY 20-30%. EMISSION LIMIT UNITS: LB/T OF STEEL (PRIMARY), LB/H 24 HR AVE (ALTERNATE)ADDITIONAL EMISSION LIMIT: 106.2 TPY 0.295 LB/T Other Case-by-Case 

TN-0122

HOEGANAES CORPORATION 2/11/2000 MELT SHOP OPERATIONS MS VOC 0.5 LB/H Other Case-by-Case 

MI-0275

RAVENNA CASTING CENTER, INC. 4/14/2000 IRON MELT SHOP MS 27 T/H VOC 4.4 LB/H Other Case-by-Case 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998 MELTSHOP, MISC. OPERATIONS MS 53 MMBTU/H VOC 5.3 LB/MMCF Other Case-by-Case 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS VOC 0.13 LB/T STEEL NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS VOC 0.13 LB/T STEEL NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP ROOF MONITORS MS VOC 1.7 LB 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP ROOF MONITORS MS VOC 1.7 LB/H 

BACT-PSD VOC lb/t steel Emission Limits

MIN 0.06 lb/t steel MIN 

MAX 0.35 lb/t steel MAX 

MEDIAN 0.14 lb/t steel MEDIAN 

COUNT 8 CASES COUNT 

MS RBLC VOC BACT Limits Summary

Other (non-BACT)-case-by-ca

Lim

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS 

*OH-0285

NORTH STAR BHP STEEL, LTD 8/5/2003

ELECTRIC ARC FURNACE WITH TWO LADLE MELT FURNACES MS 315 T STEEL/H PB TWO BAGHOUSES 0.19 LB/H BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H PB

FURNACE SHAFT EVACUATION; POSITIVE P BAGHOUSE WITH A DESIGN FLOW OF 1,100,000 ACFM ($550/TON REMOVED) 0.34 LB/H BACT-PSD 

TX-0399 NUCOR JEWETT PLANT 1/5/2003 EAF, LMF, CASTER MELTSHOP MS 240 T/H LEAD OXIDE 0.88 LB/H BACT-PSD 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS STEEL/H PB

POSITIVE PRESSURE, REVERSE AIR CLEANING BAGHOUSE WITH 3 FANS, 2 REVERSE AIR FANS, DSE, SIDE DRAFT HOOD ON LMF, ROOF MONITORS. 1.9 LB/H BACT-PSD

WI-0094

CHARTER STEEL DIVISION 2/26/1997

ELECTRIC ARC FURNACE, MELT SHOP, P01, S01 MS 450000 T/YR PB SYNTHETIC MINOR LIMIT 0.008 LB/H Other Case-by-Case

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS A MS PB BAGHOUSE 0.045 LB/H Other Case-by-Case 

MI-0275

RAVENNA CASTING CENTER, INC. 4/14/2000 IRON MELT SHOP MS 27 T/H PB FABRIC FILTER 0.07 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS B MS PB BAGHOUSE 0.077 LB/H Other Case-by-Case 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS PB 0.0016 LB/T STEEL NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS PB 0.0016 LB/T STEEL 

BACT-PSD Pb lb/t steel Emission Limits

MIN 0.0016 lb/t steel MIN 

MAX 0.0016 lb/t steel MAX 

MEDIAN 0.0016 lb/t steel MEDIAN 

COUNT 2 CASES COUNT 

MS RBLC Pb BACT Limits Summary

Other (non-BACT)-cas

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT Control Equipment EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

L

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 DRYER, LADLE LP PM10 0.0052 GR/DSCF1 BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 DRYER, LADLE LP PM10 0.0052 GR/DSCF1 BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, TUNDISH LP PM10

GOOD COMBUSTION PRACTICES AND NATURAL GAS 0.0052 GR/DSCF1 BACT-PSD 

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001

LADLE PREHEAT & DRYOUT STATIONS LP 225 T/H PM10 GOOD COMBUSTION PRACTICE 0.0075 LB/MMBTU BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003

LADLE PREHEATER AND DRYER, 6 UNITS LP 10 MMBTU/H PM10 BAGHOUSE 0.074 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 TUNDISH PREHEATER, 3 UNITS LP 20 MMBTU/H PM10 BAGHOUSE 0.15 LB/H BACT-PSD AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 PREHEATERS, LADLE, (3) LP 4 MMBTU/H PM10

NATURAL GAS COMBUSTION/GOOD COMBUSTION PRACTICES. 0.2 LB/H BACT-PSD 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 LADLE PREHEAT LP PM10 0.2 LB/H BACT-PSD 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 PREHEAT LADLE LP PM10 0.23 LB/H BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 LADLE PREHEATERS LP 15 MMBTU/HR EACH PM10

PERMIT LIMITATION IS USE OF NATURAL GAS OR PROPANE BACT-PSD

IN-0090 NUCOR STEEL 1/19/2001 TUNDISH PREHEATERS (2) LP 6 MMBTU/H PM10

PERMIT LIMITATION IS USE OF NATURAL GAS. BACT-PSD

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

B-SIDE LADLE HEATERS SIDEWALL VENT, 10C LP PM10 NONE INDICATED 0.15 LB/H N/A 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ECCENTRIC BOTTOM TAPPING LADLE PREHEATER FURNACE LP 14 MMBTU/H PM10 0.196 LB/H N/A 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

A-SIDE LADLE HEATERS SIDEWALL VENT LP PM10 NONE INDICATED 0.04 LB/H Other Case-by-Case 

BACT-PSD PM10 lb/MMBTU Emission Limits

MIN 0.0075 lb/MMBTU MIN 

MAX 0.0075 lb/MMBTU MAX 

MEDIAN 0.0075 lb/MMBTU MEDIAN 

COUNT 1 CASES COUNT 

LP RBLC PM10 BACT Limits Summary

Other (non-BACT)-case-b

Emission 

* BACT limits on a gr/dscf are equal to typical melt shop limits. It is logical to assume thdemonstration for the gr/dscf limits at these sources is at the melt shop exhaust. Preheaburners. Since the preheater flue gas cannot be routed through a stack; preheater exhato 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CAS

BASIS 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 LADLE PREHEAT LP SO2 0.01 LB/H BACT-PSD 

TN-0071

WAUPACA FOUNDRY, INC. 4/28/2000

MISC. NATURAL GAS USAGE FOR PREHEATING LADLES LP 0.02 MMCF/H SO2

USING NATURAL GAS AS FUEL AND TAKING AN EMISSION LIMITATION. 0.01 LB/H BACT-PSD

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 DRYER, LADLE LP SO2 0.1 LB/H BACT-PSD

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, TUNDISH LP SO2 0.1 LB/H BACT-PSD

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, LADLE LP SO2

GOOD COMBUSTION PRACTICES (NATURAL GAS) 0.1 LB/H BACT-PSD

IN-0090 NUCOR STEEL 1/19/2001 LADLE PREHEATERS LP 15 MMBTU/HR EACH SO2

PERMIT LIMITATION IS NATURAL GAS OR PROPANE USAGE BACT-PSD

IN-0090 NUCOR STEEL 1/19/2001 TUNDISH PREHEATERS (2) LP 6 MMBTU/H SOX

PERMIT LIMITATION IS USE OF NATURAL GAS. BACT-PSD

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

A-SIDE LADLE HEATERS SIDEWALL VENT LP SO2 NONE INDICATED 0.08 LB/H Other Case-by-Cas

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

B-SIDE LADLE HEATERS SIDEWALL VENT, 10C LP SO2 NONE INDICATED 0.27 LB/H Other Case-by-Cas

NE-0025

NUCOR STEEL DIVISION 6/22/2004 LADLE PREHEATERS (TOTAL) LP 48 MMBTU/H SO2 346.59 LB/T Other Case-by-Cas

NE-0026

NUCOR STEEL DIVISION 6/22/2004 LADLE PREHEATER LP 48 MMBTU/H SO2 346.59 LB/T Other Case-by-Cas

OH-0276 CHARTER STEEL 4/14/2003

LADLE PREHEATER AND DRYER, 6 UNITS LP 10 MMBTU/H SO2 0.006 LB/H 

OH-0276 CHARTER STEEL 4/14/2003 TUNDISH PREHEATER, 3 UNITS LP 20 MMBTU/H SO2 0.01 LB/H 

BACT-PSD SO2 and SOx lb/t steel Emission Limits

MIN NA lb/t steel MIN 

MAX NA lb/t steel MAX 

MEDIAN NA lb/t steel MEDIAN 

COUNT NA CASES COUNT 

LP RBLC SO2 and SOx BACT Limits Summary

Other (non-BACT

ste

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGHP

UT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, TUNDISH LP NOX 0.1 LB/H BACT-PSD

KY-0094

NORTH AMERICAN STAINLESS 12/1/2003

DRYERS, NATURAL GAS, (2) EMISSION POINT 83 LP 3.1 mmbtu/h NOX LOW NOX BURNERS 0.304 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

A-SIDE LADLE HEATERS SIDEWALL VENT LP NOX

THE NATURAL-GAS FIRED SIDEWALL SUPPLEMENTAL BURNERS FOR THE (2) ELECTRIC ARC FURNACES ARE DESIGNED TO MINIMIZE NOX EMISSIONS BY UTILIZING BOTH OXYGEN AND AIR FOR OXIDATION. 0.59 LB/H BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 DRYER, LADLE LP NOX 0.7 LB/H BACT-PSD

OH-0276 CHARTER STEEL 4/14/2003

LADLE PREHEATER AND DRYER, 6 UNITS LP 10 MMBTU/H NOX 0.98 LB/H BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, LADLE LP NOX

GOOD COMBUSTION PRACTICES (NATURAL GAS) 1.2 LB/H BACT-PSD

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ECCENTRIC BOTTOM TAPPING LADLE PREHEATER FURNACE LP 14 MMBTU/H NOX LOW NOX BURNER 1.25 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

B-SIDE LADLE HEATERS SIDEWALL VENT, 10C LP NOX

THE NATURAL-GAS FIRED SIDEWALL SUPPLEMENTAL BURNERS FOR THE (2) ELECTRIC ARC FURNACES ARE DESIGNED TO MINIMIZE NOX EMISSIONS BY UTILIZING BOTH OXYGEN AND AIR FOR OXIDATION. 1.91 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 TUNDISH PREHEATER, 3 UNITS LP 20 MMBTU/H NOX 1.96 LB/H BACT-PSD 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 LADLE PREHEAT LP NOX 2.04 LB/H BACT-PSD 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 PREHEAT LADLE LP NOX 2.3 LB/H BACT-PSD 

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001

LADLE PREHEAT & DRYOUT STATIONS LP 225 T/H NOX LOW NOX BURNERS 0.098 LB/MMBTU BACT-PSD 

IN-0073

QUALITECH STEEL CORP. 10/31/1996

LADLE PREHEAT/DRYER STATIONS LP 8 MMBTU/H NOX LOW NOX BURNERS 0.1 LB/MMBTU BACT-PSD 

IN-0073

QUALITECH STEEL CORP. 10/31/1996 TUNDISH DRYER LP 5 MMBTU/H NOX LOW NOX BURNERS 0.1 LB/MMBTU BACT-PSD 

IN-0073

QUALITECH STEEL CORP. 10/31/1996 TUNDISH PREHEATERS (2) LP 5 MMBTU/H NOX LOW NOX BURNERS 0.1 LB/MMBTU BACT-PSD 

TX-0417 NUCOR CORP. 1/15/2003

PROCESS HEATERS, LADLE & TUNDISH LP NOX LOW NOX BURNERS AND CLEAN FUEL. 0.1 LB/MMBTU BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 LADLE PREHEATERS LP 15 MMBTU/HR EACH NOX LOW NOX BURNERS 0.1 LB/MMBTU BACT-PSD

IN-0079 STEEL DYNAMICS, INC. 7/7/1999

DRYERS, NATURAL GAS FIRED; (PREHEATERS) LP 10 MMBTU/H NOX LOW NOX BURNERS 0.1 LB/MMBTU BACT-PSD 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999

PREHEATERS, NATURAL GAS FIRED LP 10 MMBTU/H NOX LOW NOX BURNERS 0.1 LB/MMBTU BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 TUNDISH PREHEATERS (2) LP 6 MMBTU/H NOX LOW NOX BURNERS, BTU LIMIT 0.15 LB/MMBTU BACT-PSD

NE-0025 NUCOR STEEL DIVISION 6/22/2004 LADLE PREHEATERS (TOTAL) LP 48 MMBTU/H NOX 82.92 LB/T Other Case-by-Case

NE-0026 NUCOR STEEL DIVISION 6/22/2004 LADLE PREHEATER LP 48 MMBTU/H NOX ULTRA-LOW NOX BURNERS 82.92 LB/T Other Case-by-Case

BACT-PSD NOx lb/MMBTU Emission Limits

MIN 0.089 lb/MMBTU MIN N

MAX 2.040 lb/MMBTU MAX N

MEDIAN 1.090 lb/MMBTU MEDIAN N

COUNT 10 CASES COUNT N

LP RBLC NOx BACT Limits Summary

Other (non-BACT)-cas

Emiss

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGHP

UT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMIS

LIM

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001

LADLE PREHEAT & DRYOUT STATIONS LP 225 T/H CO GOOD COMBUSTION PRACTICE 0.0824 LB/MMBTU BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, TUNDISH LP CO 0.1 LB/H BACT-PSD

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 DRYER, LADLE LP CO 0.2 LB/H BACT-PSD

KY-0094

NORTH AMERICAN STAINLESS 12/1/2003

DRYERS, NATURAL GAS, (2) EMISSION POINT 83 LP 3.1 mmbtu/h CO 0.255 LB/H BACT-PSD 

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 PREHEATERS, LADLE, (3) LP 4 MMBTU/H CO

NATURAL GAS COMBUSTION/GOOD COMBUSTION PRACTICES. 0.3 LB/H BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, LADLE LP CO

GOOD COMBUSTION PRACTICES (NATURAL GAS) 0.3 LB/H BACT-PSD

TX-0398 NUCOR JEWETT PLANT 5/5/2000 LADLE PREHEAT LP CO 0.51 LB/H BACT-PSD 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 PREHEAT LADLE LP CO 0.58 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003

LADLE PREHEATER AND DRYER, 6 UNITS LP 10 MMBTU/H CO 0.82 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

B-SIDE LADLE HEATERS SIDEWALL VENT, 10C LP CO NONE INDICATED 1.61 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 TUNDISH PREHEATER, 3 UNITS LP 20 MMBTU/H CO 1.64 LB/H BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 LADLE PREHEATERS LP 15 MMBTU/HR EACH CO

PERMIT LIMITATION IS NATURAL GAS OR PROPANE USAGE BACT-PSD

IN-0090 NUCOR STEEL 1/19/2001 TUNDISH PREHEATERS (2) LP 6 MMBTU/H CO

PERMIT LIMITATION IS USE OF NATURAL GAS. BACT-PSD

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ECCENTRIC BOTTOM TAPPING LADLE PREHEATER FURNACE LP 14 MMBTU/H CO 1.2 LB/H N/A 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

A-SIDE LADLE HEATERS SIDEWALL VENT LP CO NONE INDICATED 0.49 LB/H Other Case-by-Case 

NE-0025 NUCOR STEEL DIVISION 6/22/2004 LADLE PREHEATERS (TOTAL) LP 48 MMBTU/H CO 729.89 LB/T Other Case-by-Case

NE-0026 NUCOR STEEL DIVISION 6/22/2004 LADLE PREHEATER LP 48 MMBTU/H CO 729.89 LB/T Other Case-by-Case

BACT-PSD CO lb/t steel Emission Limits

MIN 0.0823 lb/MMBTU MIN NA 

MAX 0.0824 lb/MMBTU MAX NA 

MEDIAN 0.0824 lb/MMBTU MEDIAN NA 

COUNT 2 CASES COUNT NA 

LP RBLC CO BACT Limits Summary

Other (non-BACT)-case-by-case 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMI

LI

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001

LADLE PREHEAT & DRYOUT STATIONS LP 225 T/H VOC GOOD COMBUSTION PRACTICE 0.0054 LB/MMBTU BACT-PSD 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 PREHEAT LADLE LP VOC 0.01 LB/H BACT-PSD KY-0094

NORTH AMERICAN STAINLESS 12/1/2003

DRYERS, NATURAL GAS, (2) EMISSION POINT 83 LP 3.1 mmbtu/h VOC 0.0167 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

A-SIDE LADLE HEATERS SIDEWALL VENT LP VOC NONE INDICATED 0.03 LB/H BACT-PSD 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 LADLE PREHEAT LP VOC 0.04 LB/H BACT-PSD OH-0276 CHARTER STEEL 4/14/2003

LADLE PREHEATER AND DRYER, 6 UNITS LP 10 MMBTU/H VOC 0.05 LB/H BACT-PSD 

TN-0071

WAUPACA FOUNDRY, INC. 4/28/2000

MISC. NATURAL GAS USAGE FOR PREHEATING LADLES LP 0.02 MMCF/H VOC

USING NATURAL GAS AS FUEL AND TAKING AN EMISSION LIMITATION 0.08 LB/H BACT-PSD

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 DRYER, LADLE LP VOC 0.1 LB/H BACT-PSD

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, TUNDISH LP VOC 0.1 LB/H BACT-PSD

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 PREHEATER, LADLE LP VOC

GOOD COMBUSTION PRACTICES (NATURAL GAS) 0.1 LB/H BACT-PSD

OH-0276 CHARTER STEEL 4/14/2003 TUNDISH PREHEATER, 3 UNITS LP 20 MMBTU/H VOC 0.11 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

B-SIDE LADLE HEATERS SIDEWALL VENT, 10C LP VOC NONE INDICATED 0.11 LB/H BACT-PSD 

NE-0026 NUCOR STEEL DIVISION 6/22/2004 LADLE PREHEATER LP 48 MMBTU/H VOC 25.7 LB/T Other Case-by-Case

NE-0025 NUCOR STEEL DIVISION 6/22/2004 LADLE PREHEATERS (TOTAL) LP 48 MMBTU/H VOC 25.77 LB/T Other Case-by-Case

BACT-PSD VOC lb/MMBTU Emission Limits

MIN 0.0054 lb/MMBTU MIN NA 

MAX 0.0054 lb/MMBTU MAX NA 

MEDIAN 0.0054 lb/MMBTU MEDIAN NA 

COUNT 1 CASES COUNT NA 

LP RBLC VOC BACT Limits Summary

Other (non-BACT)-case-by

Emission L

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

L

IN-0070 NUCOR STEEL 6/20/1996

SNUB FURNACE ON NO.1 TUNNEL FURNACE TF 6 MMBTU/H PM FUEL SPEC: NATURAL GAS 0 SEE P2 BACT-PSD 

IN-0070 NUCOR STEEL 6/20/1996

SNUB FURNACE ON NO.1 TUNNEL FURNACE TF 6 MMBTU/H PM10 FUEL SPEC: NATURAL GAS 0 SEE P2 BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 TUNNEL FURNACE TF 160 MMBTU/H SO2 NATURAL GAS COMBUSTION ONLY 0.0006 LB/MMBTU BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 TUNNEL FURNACE TF 160 MMBTU/H VOC NATURAL GAS COMBUSTION ONLY 0.005 LB/MMBTU BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 TUNNEL FURNACE TF 160 MMBTU/H PM10 NATURAL GAS COMBUSTION ONLY 0.0076 LB/MMBTU BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 TUNNEL FURNACE TF 160 MMBTU/H CO GOOD COMBUSTION PRACTICE 0.037 LB/MMBTU BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 TUNNEL FURNACE TF 160 MMBTU/H NOX LOW NOX BURNERS 0.1 LB/MMBTU BACT-PSD 

IN-0070 NUCOR STEEL 6/20/1996

SNUB FURNACE ON NO.1 TUNNEL FURNACE TF 6 MMBTU/H NOX LOW NOX BURNERS 0.19 LB/MMBTU BACT-PSD 

BACT-PSD lb/MMBTU Emission Limits

PM10 0.0076 lb/MMBTU

SO2 0.0006 lb/MMBTU

VOC 0.0050 lb/MMBTU

CO 0.0370 lb/MMBTU

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

TF RBLC BACT Limits Summary

Other (non-BACT)-case

No Perform

Other (non-BACT)-case-by

No Perform

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 

L

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 ROADS, PAVED & UNPAVED MH & Fug PM10 P

WATER APPLICATON TO CONTROL FUGITIVE

EMISSIONS. 6.9 T/YR BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 MATERIAL HANDLING SILOS MH & Fug PM10 A FABRIC FILTERS 0.01 GR/DSCF BACT-PSD AR-0077 BLUEWATER PROJECT 7/22/2004 ROADWAY EMISSIONS MH & Fug PM10 P APPLICATION OF WETTING AGENT 26.9 T/YR BACT-PSD AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 MATERIAL HANDLING MH & Fug PM10 A FABRIC FILTER 0.01 GR/DSCF BACT-PSD 

AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 LIME SILO MH & Fug PM10 A FABRIC FILTER 0.1 LB/H BACT-PSD 0.1 T/

AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 CARBON SILO MH & Fug PM10 A FABRIC FILTER 0.1 LB/H BACT-PSD 0.5 T/

IN-0073

QUALITECH STEEL CORP. 10/31/1996

MATL. CRUSHING, HANDLING, & STORAGE MH & Fug 5 LB/H PM10 P

WORK PRACTICES; VE AVERAGE AS CALCULATED BY METHOD 9. 3 % OPAC BACT-PSD 

IN-0073

QUALITECH STEEL CORP. 10/31/1996

MATL. HANDLING, BAGHOUSE WASTE MH & Fug 100 T/BINS PM10 P

COVERED CONVEYORS, BINS WITH FILTERS LOADING INTO SEALED TRUCKS WITH ENCLOSED SHED BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 LMS BAGHOUSE SILO MH & Fug PM10 P BIN VENT FILTER 0.01 GR/DSCF BACT-PSD IN-0090 NUCOR STEEL 1/19/2001

STORAGE SILO FOR BLASTING MEDIA MH & Fug 1000 DSCFM PM10 A BIN VENT 0.01 GR/DSCF BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 TRANSPORTATION ON ROADS MH & Fug PM10 P

SPEED LIMITS, VACUUMING/SWEEPING EVERY 14 DAYS. DUST SUPPRESSANT ON UNPAVED ROADS AT A RATE OF 0.16 GAL/YD2 ONCE PER MONTH. EMISSION UNIT IS LB SILT PER MILE 16.8 LB/MI BACT-PSD 

KY-0095 RECMIX OF PA, INC. 8/6/2004 UNPAVED ROAD MH & Fug PM10 P WATERING 0.78 T/YR BACT-PSD KY-0095 RECMIX OF PA, INC. 8/6/2004 STOCKPILES MH & Fug 20000 t PM10 P MATERIAL HAS HIGH MOISTURE CONTENT 0.78 T/YR BACT-PSD KY-0095 RECMIX OF PA, INC. 8/6/2004

OVERSIZE SLAG HANDLING, STOCKPILES MH & Fug 84000 t/yr PM10 P COVERS TO OPENINGS 0.78 T/YR BACT-PSD 

KY-0095 RECMIX OF PA, INC. 8/6/2004

OVERSIZE SLAG HANDLING, CONVEYOR TO STOCKPILES MH & Fug 84000 t/yr PM10 P WATERING 0.78 T/YR BACT-PSD 

KY-0095 RECMIX OF PA, INC. 8/6/2004 CRUSHING OPERATION MH & Fug 79800 t/yr PM10 P

WATER MIST SPRAYS AT MULTIPLE LOCATIONS 0.78 T/YR BACT-PSD 

KY-0095 RECMIX OF PA, INC. 8/6/2004

FINAL AGGREGATE HANDLING, STORAGE MH & Fug 266000 t/yr PM10 P HIGH MOISTURE CONTENT 0.78 T/YR BACT-PSD 

KY-0095 RECMIX OF PA, INC. 8/6/2004

FINAL AGGREGATE HANDLING, EXIT PILE MH & Fug 266000 t/yr PM10 P HIGH MOISTURE CONTENT 0.78 T/YR BACT-PSD 

MN-0061 ERIE NUGGET 6/26/2005 COAL & FLUX UNLOADING MH & Fug 4000000 DSCF PM10 A FF 0.005 GR/DSCF BACT-PSD MN-0061 ERIE NUGGET 6/26/2005 RAIL LOADOUT MH & Fug 4000000 DSCF PM10 A FF 0.005 GR/DSCF BACT-PSD MN-0061 ERIE NUGGET 6/26/2005

MATERIAL TRANSFER OPERATIONS MH & Fug 6000000 DSCF/H PM10 A FF 0.005 GR/DSCF BACT-PSD 

MN-0064

NORTHSHORE MINING COMPANY 3/22/2006

TERTIARY CRUSHING (CRUSHER LINE 4 AND CRUSHER LINE 104) MH & Fug 700 LT/H Ore Particulate Matt A FABRIC FILTER 0.0025 GR/DSCF BACT-PSD 

MN-0064

NORTHSHORE MINING COMPANY 3/22/2006

CONCENTRATOR BINS (WEST STORAGE BINS #2, #3, #4, #5, #6, #7, #8, #9 AND #10) MH & Fug 200 LT/H concent Particulate Matt A FABRIC FILTER 0.003 GR/DSCF BACT-PSD 

MN-0064

NORTHSHORE MINING COMPANY 3/22/2006 FURNACE 5 DISCHARGE MH & Fug 160 LT/H pellets Particulate Matt A FABRIC FILTER 0.01 GR/DSCF BACT-PSD 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003

BAGHOUSE DUST HANDLING SYSTEM MH & Fug PM10 A FABRIC FILTER 0.01 GR/DSCF Other Case-by-Cas 0.27 LB

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

COKE AND BREEZE CRUSHING/SCREENING/CONVEYING MH & Fug PM10 A BAGHOUSE WITH 0.008 GR/DSCF 3.43 LB/H BACT-PSD 15.02 T/

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001 ROADWAYS AND PARKING MH & Fug PM10 P

WATERING AS SUFFICIENT FREQUENCY TO ENSURE COMPLIANCE 1.56 T/YR BACT-PSD 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

LOAD IN AND LOAD OUT OF COKE/COAL STORAGE PILES MH & Fug PM10 P

LOAD-IN COAL, COKE, AND COKE BREEZE W/ STACKING TUBE; LOAD-IN COAL W/WATER SPRAYS/DUST SUPPRESSANT; LOAD-OUT COAL UNDER PILE GRAVITY FEED AND WATER SPRAY; LOAD-OUT COKE W/ UNDER PILE GRAVITY FEED. 1.98 T/YR BACT-PSD 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

COAL HANDLING, CONVEYING, AND TRANSFER MH & Fug 6602850 T/YR PM10 P

RAIL CAR BOTTOM DUMPING AND ENCLOSED; BELT CONVEYORS ENCLOSED; WET AND/OR CHEMICAL SUPPRESSION 3.77 T/YR BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 SILOS CARBON, LIME, AND DUST MH & Fug 50 T/H PM10 A BIN VENT 0.45 T/YR BACT-PSD OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005

BASIC OXYGEN FURNACES (2 VESSELS), FUGITIVE EMISSIONS MH & Fug 375 t/h PM10 N 28.06 LB/H RACT 61.37 T/

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR EAF MH & Fug 2.5 MM t/yr PM10 A BAGHOUSE AND BIN VENT FILTERS 8.28 T/YR 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR BOF MH & Fug PM10 A THREE BAGHOUSES 16.83 T/

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR LMF MH & Fug 2.5 mm t/yr PM10 A BIN VENT FILTERS 0.882 T/

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 

L

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 GRIZZLY TO STOCK MH & Fug PM10 N NONE INDICATED 0.0002 LB/H Other Case-by-Cas 0.0001 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

RAILCAR LOADING FROM PELLETIZER SILO/BAGHOUSE DUST MH & Fug PM10 N NONE INDICATED 0.0003 LB/H Other Case-by-Cas 0.0011 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

SCREEN TO CONV TO CONV, S15&16 MH & Fug PM10 N NONE INDICATED 0.0003 LB/H Other Case-by-Cas 0.0002 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

SCREEN TO CONV TO STOCK, S20&21 MH & Fug PM10 N NONE INDICATED 0.0005 LB/H Other Case-by-Cas 0.0003 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO CONV, S11 MH & Fug PM10 N NONE INDICATED 0.0008 LB/H Other Case-by-Cas 0.0005 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO CONV, S12 MH & Fug PM10 N NONE INDICATED 0.0008 LB/H Other Case-by-Cas 0.0005 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO SCREEN, S13 MH & Fug PM10 N NONE INDICATED 0.0009 LB/H Other Case-by-Cas 0.0005 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

SCREEN TO CONV TO STOCK, S22&23 MH & Fug PM10 N NONE INDICATED 0.001 LB/H Other Case-by-Cas 0.0006 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

OUTDOOR & INDOOR ALLOY HANDLING, 11A&B MH & Fug PM10 N NONE INDICATED 0.0011 LB/H Other Case-by-Cas 0.0042 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

FEEDER TO FEEDER TO CONV TOSCREEN, S7-9 MH & Fug PM10 N NONE INDICATED 0.0018 LB/H Other Case-by-Cas 0.0011 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SHREDDER FUGITIVES, 16 MH & Fug PM10 N NONE INDICATED 0.0024 LB/H Other Case-by-Cas 0.006 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

CONV TO CRUSHER TO CONV, S30&32 MH & Fug PM10 N NONE INDICATED 0.0026 LB/H Other Case-by-Cas 0.0016 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN TO CONV, S28 MH & Fug PM10 N NONE INDICATED 0.0101 LB/H Other Case-by-Cas 0.006 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

CONV TO CONV TO BIN TO TRUCK, S17-19 MH & Fug PM10 N NONE INDICATED 0.0103 LB/H Other Case-by-Cas 0.0062 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

GRIZZLY TO CONV TO CONV, S4 & S5 MH & Fug PM10 N NONE INDICATED 0.0118 LB/H Other Case-by-Cas 0.0071 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN, S14 MH & Fug PM10 N NONE INDICATED 0.013 LB/H Other Case-by-Cas 0.008 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 VIBRATING SCREEN, 22 MH & Fug PM10 N NONE INDICATED 0.015 LB/H Other Case-by-Cas 0.065 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN TO CONV, S29 MH & Fug PM10 N NONE INDICATED 0.0176 LB/H Other Case-by-Cas 0.0106 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO CONV, S33 MH & Fug PM10 N NONE INDICATED 0.0176 LB/H Other Case-by-Cas 0.01 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

FEEDER TO FEEDER TO CONV TOSCREEN, S24-26 MH & Fug PM10 N NONE INDICATED 0.0277 LB/H Other Case-by-Cas 0.0166 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO FEEDER, S6 MH & Fug PM10 N NONE INDICATED 0.029 LB/H Other Case-by-Cas 0.018 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN, S10 MH & Fug PM10 N NONE INDICATED 0.031 LB/H Other Case-by-Cas 0.019 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CRUSHER, S31 MH & Fug PM10 A BAGHOUSE 0.032 LB/H Other Case-by-Cas 0.019 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 PELLETIZER SILO, 15A MH & Fug PM10 A BAGHOUSE 0.0324 LB/H Other Case-by-Cas 0.1296 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 MATERIAL HANDLING, 23 MH & Fug PM10 N NONE INDICATED 0.15 LB/H Other Case-by-Cas 0.67 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

FRONT-END LOADER DROP @ MIXING BLDG, S35 MH & Fug PM10 N NONE INDICATED 0.221 LB/H Other Case-by-Cas 0.98 T/

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 

L

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CRUSHER, SBH-1 MH & Fug PM10 N

THE BAGHOUSE IS A CONTROL DEVICE FOR THE CRUSHER, BUT THESE EMISSION LIMITS ARE LISTED SPECIFICALLY FOR THE BAGHOUSE. 0.343 LB/H Other Case-by-Cas 0.2 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN, S27 MH & Fug PM10 N NONE INDICATED 0.484 LB/H Other Case-by-Cas 0.291 T/

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

UNPROCESSED RESIDUE & RESIDUE STORAGE PILE, 20A&21 MH & Fug PM10 N NONE INDICATED 0.14 T/YR Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

FINES/COARSE SAND/LIGHT ORGANIC MATERIAL STORAGE MH & Fug PM10 N NONE INDICATED 0.14 T/YR Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 STOCKPILE, S37 MH & Fug PM10 N NONE INDICATED 0.21 T/YR Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 IN-PLANT VEHICLE TRAFFIC MH & Fug PM10 P CHEMICAL AND WATER SPRAY 12.5 T/YR Other Case-by-Case 

TX-0398 NUCOR JEWETT PLANT 5/5/2000 LIME & DOLOMITE STORAGE MH & Fug PM10 A FF 0.09 LB/H BACT-PSD 0.38 T/TX-0398 NUCOR JEWETT PLANT 5/5/2000 LIME STORAGE MH & Fug PM10 A FF 0.09 LB/H BACT-PSD 0.38 T/TX-0398 NUCOR JEWETT PLANT 5/5/2000 DOLMITE STORAGE MH & Fug PM10 N 0.09 LB/H BACT-PSD 0.38 T/VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

UNPAVED RDS,STORAGE PILES & MATERIAL TRANSFER OP. MH & Fug 0 PM10 P

DUST MANAGEMENT PLAN; WORK PRACTICE (90%) 0.1 LB/H Other Case-by-Cas 0 

BACT-PSD PM gr/dscf Emission Limits

MIN 0.0025 gr/dscf MIN 0.0100 g

MAX 0.010 gr/dscf MAX 0.020 g

MEDIAN 0.010 gr/dscf MEDIAN 0.010 g

COUNT 11 CASES COUNT 3 C

MH & Fug RBLC PM BACT Limits Summary

Other (non-BACT)-case-by-case 

Emission Limits

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY-CASE BASIS EMISSION LIMIT 2 Emissio

Limit 2 U

IN-0073

QUALITECH STEEL CORP. 10/31/1996

MATL. CRUSHING, HANDLING, & STORAGE MH & Fug 5 LB/H PM P

WORK PRACTICES; VE AVERAGE AS CALCULATED BY METHOD 9. 3 % OPAC BACT-PSD 

MN-0061 ERIE NUGGET 6/26/2005 COAL & FLUX UNLOADING MH & Fug 4000000 DSCF PM A FF 0.005 GR/DSCF BACT-PSD MN-0061 ERIE NUGGET 6/26/2005 RAIL LOADOUT MH & Fug 4000000 DSCF PM A FF 0.005 GR/DSCF BACT-PSD MN-0061 ERIE NUGGET 6/26/2005

MATERIAL TRANSFER OPERATIONS MH & Fug 6000000 DSCF/H PM A FF 0.005 GR/DSCF BACT-PSD 

IN-0119 AUBURN NUGGET 5/31/2005 SILOS MH & Fug PM A BIN FILTERS 0.01 GR/DSCF BACT-PSD OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR LMF MH & Fug 2.5 mm t/yr PM A BIN VENT FILTERS 0.02 GR/DSCF 1.11 T/YR 

*NC-0112 NUCOR STEEL 11/23/2004 RAW MATERIAL STORAGE SILOS MH & Fug PM A BIN VENT FILTERS 0.01 GR/DSCF BACT-PSD NC-0113 NUCOR STEEL 11/23/2004 RAW MATERIAL STORAGE SILOS MH & Fug PM A BIN VENT FILTERS 0.01 GR/DSCF TX-0417 NUCOR CORP. 1/15/2003

RAW MATERIAL RECEIVING AND HANDLING MH & Fug PM A FILTER SYSTEM 0.01 GR/DSCF BACT-PSD 

TN-0134 PLANT 6 8/24/2001 PHASE I SPENT DUST HANDLING MH & Fug 80 T/H SAND PM A PULSE-JET FABRIC FILTER BAGHOUSE 0.005 GR/DSCF BACT-PSD 1 LB/H IA-0036 IPSCO STEEL INC 3/14/1996 LIME/DOLOMITE STORAGE MH & Fug 230 T/H PM A

BAGHOUSE-POLYBAGS PULSE-JET BAGHOUSE FILTER AREA=180 SQ. FT. 0.0903 GR/DSCF BACT-PSD 2.31 LB/H 

IA-0036 IPSCO STEEL INC 3/14/1996 CARBON STORAGE MH & Fug 230 T/H PM A

BAGHOUSE-POLYBAGS PULSE JET FILTER AREA = 318 SQ. FT 0.043 GR/DSCF BACT-PSD 0.23 LB/H 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR BOF MH & Fug PM A THREE BAGHOUSES 1.8 LB/H 19.84 T/YR 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR EAF MH & Fug 2.5 MM t/yr PM A BAGHOUSE AND BIN VENT FILTERS 1.8 LB/H 14.9 T/YR 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005

BASIC OXYGEN FURNACES (2 VESSELS), FUGITIVE EMISSIONS MH & Fug 375 t/h PM N 61.01 LB/H BACT-PSD 133.41 T/YR 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

COKE AND BREEZE CRUSHING/SCREENING/CONVEYING MH & Fug PM A BAGHOUSE WITH 0.008 GR/DSCF 68.6 LB/H BACT-PSD 15.02 T/YR 

WI-0173

WAUPACA FOUNDRY INC. - PLANT 1 7/11/2000 LINE 1 & 2 GRINDING - P69, S29 MH & Fug PM B

BAGHOUSE, SHOULD DEMONSTRATE COMPLIANCE. 0.73 LB/H Other Case-by-Case 

TN-0066

WAUPACA FOUNDRY, INC. 4/28/2000 SPENT DUST HANDLING MH & Fug 0 PM A

PULSE-JET FABRIC FILTER BAGHOUSE CONTROL SYSTEM. 0.9 LB/H BACT-PSD 

TN-0073

WAUPACA FOUNDRY, INC. 4/28/2000 SPENT SAND/DUST HANDLING MH & Fug 80 T/H PM A

PULSE-JET FABRIC FILTER BAGHOUSE CONTROL SYSTEM 0.9 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

OUTDOOR & INDOOR ALLOY HANDLING, 11A&B MH & Fug PM N NONE INDICATED 0.0023 LB/H Other Case-by-Case 0.0089 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

RAILCAR LOADING FROM PELLETIZER SILO/BAGHOUSE DUST MH & Fug PM N NONE INDICATED 0.0006 LB/H Other Case-by-Case 0.0023 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 ALLOY PILES, 14 MH & Fug PM N NONE INDICATED 0.079 LB/H Other Case-by-Case 0.054 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SHREDDER FUGITIVES, 16 MH & Fug PM N NONE INDICATED 0.0056 LB/H Other Case-by-Case 0.014 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 VIBRATING SCREEN, 22 MH & Fug PM N NONE INDICATED 0.15 LB/H Other Case-by-Case 0.65 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 MATERIAL HANDLING, 23 MH & Fug PM N NONE INDICATED 0.32 LB/H Other Case-by-Case 1.41 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 GRIZZLY TO STOCK MH & Fug PM N NONE INDICATED 0.0004 LB/H Other Case-by-Case 0.0002 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

GRIZZLY TO CONV TO CONV, S4 & S5 MH & Fug PM N NONE INDICATED 0.0248 LB/H Other Case-by-Case 0.0149 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO FEEDER, S6 MH & Fug PM N NONE INDICATED 0.062 LB/H Other Case-by-Case 0.037 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

FEEDER TO FEEDER TO CONV TO SCREEN, S7-9 MH & Fug PM N NONE INDICATED 0.0037 LB/H Other Case-by-Case 0.0022 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN, S10 MH & Fug PM N NONE INDICATED 0.065 LB/H Other Case-by-Case 0.039 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO CONV, S11 MH & Fug PM N NONE INDICATED 0.0016 LB/H Other Case-by-Case 0.001 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO CONV, S12 MH & Fug PM N NONE INDICATED 0.0016 LB/H Other Case-by-Case 0.001 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO SCREEN, S13 MH & Fug PM N NONE INDICATED 0.0016 LB/H Other Case-by-Case 0.001 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

SCREEN TO CONV TO CONV, S15&16 MH & Fug PM N NONE INDICATED 0.0006 LB/H Other Case-by-Case 0.0004 T/YR 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

CONV TO CONV TO BIN TO TRUCK, S17-19 MH & Fug PM N NONE INDICATED 0.022 LB/H Other Case-by-Case 0.013 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

SCREEN TO CONV TO STOCK, S20&21 MH & Fug PM N NONE INDICATED 0.001 LB/H Other Case-by-Case 0.0006 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

SCREEN TO CONV TO STOCK, S22&23 MH & Fug PM N NONE INDICATED 0.0021 LB/H Other Case-by-Case 0.0013 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

FEEDER TO FEEDER TO CONV TO SCREEN, S24-26 MH & Fug PM N NONE INDICATED 0.0581 LB/H Other Case-by-Case 0.0349 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN, S27 MH & Fug PM N NONE INDICATED 1.02 LB/H Other Case-by-Case 0.61 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN TO CONV, S28 MH & Fug PM N NONE INDICATED 0.0211 LB/H Other Case-by-Case 0.0127 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN TO CONV, S29 MH & Fug PM N NONE INDICATED 0.037 LB/H Other Case-by-Case 0.0222 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

CONV TO CRUSHER TO CONV, S30&32 MH & Fug PM N NONE INDICATED 0.056 LB/H Other Case-by-Case 0.0033 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CRUSHER, S31 MH & Fug PM A BAGHOUSE 0.068 LB/H Other Case-by-Case 0.041 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CRUSHER, SBH-1 MH & Fug PM N

THE BAGHOUSE IS A CONTROL DEVICE FOR THE CRUSHER, BUT THESE EMISSION LIMITS ARE PROVIDED SPECIFICALLY FOR PM FROM THE BAGHOUSE. 0.343 LB/H Other Case-by-Case 0.2 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 CONV TO CONV, S33 MH & Fug PM N NONE INDICATED 0.037 LB/H Other Case-by-Case 0.022 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

FRONT-END LOADER DROP @ MIXING BLDG, S35 MH & Fug PM N NONE INDICATED 0.442 LB/H Other Case-by-Case 1.95 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SCREEN, S14 MH & Fug PM N NONE INDICATED 0.028 LB/H Other Case-by-Case 0.017 T/YR 

IN-0079 STEEL DYNAMICS, INC. 7/7/1999

SLAG, HANDLING AND PROCESSING MH & Fug 262800 T/YR PM B

WATER SUPPRESSION AND MINIMIZING DROP HEIGHTS 55.4 LB/H BACT-PSD 0 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999

HANDLING AND PROCESSING, SLAG MH & Fug 150 T/YR PM B

WATER SUPPRESSION AND MINIMIZING DROP HEIGHTS 55 LB/H BACT-PSD 0 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 EAF FLUX/ALLOY SYSTEM MH & Fug PM A BIN VENT FILTERS, VENT TO BAGHOUSE. 0.5 LB/H BACT-PSD 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 LMF FLUX/ALLOY SYSTEM MH & Fug PM A BIN VENT FILTERS 0.5 LB/H BACT-PSD 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

LOAD IN AND LOAD OUT OF COKE/COAL STORAGE PILES MH & Fug PM A

LOAD-IN COAL, COKE, AND COKE BREEZE W/ STACKING TUBE; LOAD-IN COAL W/WATER SPRAYS/DUST SUPPRESSANT; LOAD-OUT COAL UNDER PILE GRAVITY FEED AND WATER SPRAY; LOAD-OUT COKE W/ UNDER PILE GRAVITY FEED. 4 T/YR BACT-PSD 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

COAL HANDLING, CONVEYING, AND TRANSFER MH & Fug 6602850 T/YR PM P

RAIL CAR BOTTOM DUMPING AND ENCLOSED; BELT CONVEYORS ENCLOSED; WET AND/OR CHEMICAL SUPPRESSION 7.95 T/YR BACT-PSD 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001 ROADWAYS AND PARKING MH & Fug PM P

WATERING AS SUFFICIENT FREQUENCY TO ENSURE COMPLIANCE 8.01 T/YR BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

FINES/COARSE SAND/LIGHT ORGANIC MATERIAL STORAGE MH & Fug PM N NONE INDICATED 0.14 T/YR Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 IN-PLANT VEHICLE TRAFFIC MH & Fug PM P CHEMICAL AND WATER SPRAY 34.8 T/YR Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 STOCKPILE, S37 MH & Fug PM N 0.43 T/YR Other Case-by-Case 

*NC-0112 NUCOR STEEL 11/23/2004 UNPAVED ROADS MH & Fug PM P

PERIODIC APPLICATION OF WATER AND CHEMICAL DUST SUPPRESSANTS TO UNPAVED ROADWAYS AND POSTED SPEED LIMIT OF 10 MILES PER HOUR BACT-PSD 

NC-0113 NUCOR STEEL 11/23/2004 UNPAVED ROADS MH & Fug PM P

PERIODIC APPLICATION OF WATER AND CHEMICAL DUST SUPPRESSANTS TO UNPAVED ROADWAYS AND POSTED SPEED LIMIT OF 10 MILES PER HOUR 

UT-0061

NUCOR STEEL CORPORATION 8/29/1997

FUGITIVES / STOCK PILES / TRANSFER POINTS MH & Fug PM P

WATER SPRAYS INSTALLED AT ALL CONVEYOR TRANSFER POINTS AND BATCHING EQUIPMENT DROP POINTS. BACT-PSD

ENCLOSE TRANSFER PTS 

IN-0073

QUALITECH STEEL CORP. 10/31/1996

MATL. HANDLING, BAGHOUSE WASTE MH & Fug 100 T/BINS PM P

COVERED CONVEYORS, BINS WITH FILTERS LOADING INTO SEALED TRUCKS WITH ENCLOSED SHED BACT-PSD 

MN-0064

NORTHSHORE MINING COMPANY 3/22/2006

TERTIARY CRUSHING (CRUSHER LINE 4 AND CRUSHER LINE 104) MH & Fug 700 LT/H Ore Particulate MattA FABRIC FILTER 0.0025 GR/DSCF BACT-PSD 

MN-0064

NORTHSHORE MINING COMPANY 3/22/2006 FURNACE 5 DISCHARGE MH & Fug 160 LT/H pellets Particulate MattA HIGH EFFICIENCY WET SCRUBBER 0.005 GR/DSCF BACT-PSD 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

MN-0064

NORTHSHORE MINING COMPANY 3/22/2006

CONCENTRATOR BINS (WEST STORAGE BINS #2, #3, #4, #5, #6, #7, #8, #9 AND #10) MH & Fug 200 LT/H concentrParticulate MattA FABRIC FILTER 0.003 GR/DSCF BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

UNPAVED RDS,STORAGE PILES & MATERIAL TRANSFER OP. MH & Fug 0 TSP P

DUST MANAGEMENT PLAN; WORK PRACTICE (90%) 0.2 LB/H BACT-PSD 0 

BACT-PSD PM gr/dscf Emission Limits

MIN 0.0025 gr/dscf MIN 0.0100 gr/dscf

MAX 0.430 gr/dscf MAX 0.020 gr/dscf

MEDIAN 0.005 gr/dscf MEDIAN 0.010 gr/dscf

COUNT 11 CASES COUNT 4 CASES

MH & Fug RBLC PM BACT Limits Summary

Other (non-BACT)-case-by-case PM gr/dsc

Emission Limits

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUT-ANT CONTROL

CODE 

CONTROL EQUIPMENT EMISSION 

LIMIT 1

Emission 

Limit 1 Unit

CASE-BY-CASE 

BASIS 

EMISSION 

LIMIT 2

Emiss

Limit 2 

IN-0119 AUBURN NUGGET 5/31/2005 COAL CAR UNLOADING MH & Fug 165 T/H PM FILTERABLE A BAGHOUSE 0.0052 GR/DSCF BACT-PSD TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

SCREEN TO CONV TO STOCK, S22&23 MH & Fug PM FILTERABLE N NONE INDICATED 0.0021 LB/H BACT-PSD 0.0013 T/YR 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 STOCKPILE, S37 MH & Fug PM FILTERABLE N NONE INDICATED 0.43 T/YR BACT-PSD 

MIN 0.0052 gr/dscf MIN NA gr/dscf

MAX 0.0052 gr/dscf MAX NA gr/dscf

MEDIAN 0.0052 gr/dscf MEDIAN NA gr/dscf

COUNT 1 CASES COUNT 0 CASES

MH & Fug RBLC PM Filterable BACT Limits Summary

Other (non-BACT)-case-by-case PM 

Filterable gr/dscf Emission Limits

BACT-PSD PM Filterable gr/dscf steel Emission Limits

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT Control Equipment EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS E

TN-0134 PLANT 6 8/24/2001 PHASE I SPENT DUST HANDLING MH & Fug 80 T/H SAND PB PULSE-JET FABRIC FILTER BAGHOUSE 0.0003 LB/H BACT-PSD

TN-0066

WAUPACA FOUNDRY, INC. 4/28/2000 SPENT DUST HANDLING MH & Fug 0 PB

PULSE-JET FABRIC FILTER BAGHOUSE CONTROL SYSTEM. 0.0003 LB/H BACT-PSD

TN-0073

WAUPACA FOUNDRY, INC. 4/28/2000 SPENT SAND/DUST HANDLING MH & Fug 80 T/H PB

PULSE-JET FABRIC FILTER BAGHOUSE CONTROL SYSTEM 0.0003 LB/H BACT-PSD

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005

BASIC OXYGEN FURNACES (2 VESSELS), FUGITIVE EMISSIONS MH & Fug 375 t/h PB 0.077 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 PELLETIZER SILO, 15A MH & Fug PB BAGHOUSE 0.0009 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

RAILCAR LOADING FROM PELLETIZER SILO/BAGHOUSE DUST MH & Fug PB NONE INDICATED Other Case-by-Case

BACT-PSD Pb lb/t steel Emission Limits

MIN NA lb/t steel MIN NA 

MAX NA lb/t steel MAX NA 

MEDIAN NA lb/t steel MEDIAN NA 

COUNT NA CASES COUNT NA 

MH & Fug RBLC Pb BACT Limits Summary

Other (non-BACT)-ca

Emissio

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT Control Equipment EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS 

KY-0095 RECMIX OF PA, INC. 8/6/2004 RAW SLAG HANDLING Fug-Slag 280000 t/yr PM10 WATERING 0.78 T/YR BACT-PSD

KY-0095 RECMIX OF PA, INC. 8/6/2004 RAW SLAG HANDLING, HOPPER Fug-Slag PM10 ENCLOSURE TUNNEL 0.78 T/YR BACT-PSD

KY-0095 RECMIX OF PA, INC. 8/6/2004 SLAG SKULL HANDLING Fug-Slag 4200 t/yr PM10 WATERING 0.78 T/YR BACT-PSD

KY-0095 RECMIX OF PA, INC. 8/6/2004 SLAG SKULL SCREENING Fug-Slag PM10 HIGH MOISTURE CONTENT 0.78 T/YR BACT-PSD

OH-0276 CHARTER STEEL 4/14/2003 SLAG PROCESSING OPERATION Fug-Slag 250 T/H PM10 ENCLOSURE WHERE PRACTICLE 0.79 LB/H BACT-PSD AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 SLAG PROCESSING Fug-Slag 886950 T/YR PM10 WET SUPPRESSION 1.2 LB/H BACT-PSD

AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 SLAG PROCESSING Fug-Slag PM10 KEEP MATERIAL SUFFICIENTLY DAMP 1.8 LB/H BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 SLAG/MILL SCALE PROCESSING Fug-Slag PM10

WATER APPLICATION AND LIMITED DROP HEIGHTS 3.5 T/YR BACT-PSD

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SLAG SKUL POT DUMP, S34B Fug-Slag PM10 NONE INDICATED 0.065 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 MOLTEN SLAG POT DUMP, S34A Fug-Slag PM10 NONE INDICATED 1.19 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL 

MIDLOTHIAN STEEL MILL 4/24/2000 SLAG RAW FEED, S1 Fug-Slag PM10 NONE INDICATED 1.63 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SLAG ROAD EMISSIONS, S38 Fug-Slag PM10 NONE INDICATED 10.63 T/YR Other Case-by-Case

BACT-PSD PM10 lb/t steel Emission Limits

MIN NA lb/t steel MIN N

MAX NA lb/t steel MAX N

MEDIAN NA lb/t steel MEDIAN N

COUNT NA CASES COUNT N

Fug-Slag RBLC PM10 BACT Limits Summary

Other (non-BACT)-c

Emi

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

L

AR-0021

QUANEX CORPORATION - MACSTEEL DIVISION 2/18/1998 SLAG PROCESSING Fug-Slag 68350 T/YR, SLAG PM

THROUGHPUT LIMIT ON SLAG, WATER SPRAYS ON TRANSFERPOINTS 3.8 T/YR BACT-PSD 

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 SLAG PROCESSING Fug-Slag PM

WATER APPLICATION TO CONTROL FUGITIVE EMISSIONS. 5.7 LB/H BACT-PSD 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SLAG ROAD EMISSIONS, S38 Fug-Slag PM NONE INDICATED 21.26 T/YR BACT-PSD

AL-0202 CORUS TUSCALOOSA 6/3/2003

SLAG RECLAMATION OPERATIONS Fug-Slag 100 T/H PM WET SUPPRESSION BACT-PSD

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SLAG SKUL POT DUMP, S34B Fug-Slag PM NONE INDICATED 0.13 LB/H Other Case-by-Case 

TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000 SLAG RAW FEED, S1 Fug-Slag PM NONE INDICATED 3.25 LB/H Other Case-by-Case 

NC-0113 NUCOR STEEL 11/23/2004 SLAG HANDLING PROCESS Fug-Slag PM

SLAG PROCESS THROUGHPUT LIMITED TO 262,800 TONS PER 12 MONTH PERIOD. DROP HEIGHTS FROM CONVEYOR DISCHARGE LIMITED TO 15 FEET WITH SECONDARY PILES BY MOBILE EQUIPMENT LIMITED TO 4 FEET. 2.2 LB

*NC-0112 NUCOR STEEL 11/23/2004 SLAG HANDLING PROCESS Fug-Slag PM

SLAG PROCESS THROUGHPUT LIMITED TO 262,800 TONS PER 12 MONTH PERIOD. DROP HEIGHTS FROM CONVEYOR DISCHARGE LIMITED TO 15 FEET WITH SECONDARY PILES BY MOBILE EQUIPMENT LIMITED TO 4 FEET. 2.2 LB/H

BACT-PSD PM lb/t steel Emission Limits

MIN NA lb/t steel MIN NA 

MAX NA lb/t steel MAX NA 

MEDIAN NA lb/t steel MEDIAN NA 

COUNT NA CASES COUNT NA 

Fug-Slag RBLC PM BACT Limits Summary

Other (non-BACT)-cas

Emissio

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME 

PERMIT 

DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT Control Equipment EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EM

LI

IN-0100 ROCKPORT WORKS 2/13/1997

COOLING TOWERS (2), NONCONTACT CT PM DRIFT ELIMINATORS 0.005 % DRIFT BACT-PSD

IN-0119 AUBURN NUGGET 5/31/2005 COOLING TOWER CT 23450 GAL/M PM 0.005

% OF THROUGH PUT BACT-PSD

*NC-0112 NUCOR STEEL 11/23/2004 COOLING TOWERS CT PM

MIST ELIMINATORS WITH A 0.008 PERCENT DRIFT LOSS 0.008 PERCENT BACT-PSD

WI-0094

CHARTER STEEL DIVISION 2/26/1997 COOLING TOWER, P06 CT PM

USE OF A 3-PASS DRIFT ELIMINATOR TO REDUCE DRIFT OF WATER DROPLETS FROM THE COOLING TOWER AND TO KEEP THE AMOUNTS TOTAL DISSOLVED SOLIDS (TDS) IN THE COOLING WATER TO LESS THAN 1.2% BY WEIGHT. 1.3 LB/H BACT-PSD

AR-0078

NUCOR STEEL, ARKANSAS 9/9/1999 COOLING TOWER CT PM10 3.6 T/YR BACT-PSD

AR-0077 BLUEWATER PROJECT 7/22/2004 COOLING TOWERS CT PM10 DRIFT/MIST ELIMINATORS 6 LB/H BACT-PSD

IN-0119 AUBURN NUGGET 5/31/2005 COOLING TOWER CT 23450 GAL/M VE 20 % OPACITY BACT-PSD

IN-0108 NUCOR STEEL 11/21/2003 COOLING TOWERS CT 192352 GAL/MIN VE MIST ELIMINATORS 20 % OPACITY BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 COOLING TOWER SYSTEM CT 12000 GAL/MIN PM10

LIMIT IS DRIFT ELIMINATOR. NO NUMERICAL LIMIT BACT-PSD

WI-0094

CHARTER STEEL DIVISION 2/26/1997 COOLING TOWER, P06 CT VOC

MAY NOT USE MORE THAN 157 POUNDS OF VOC PER MONTH, AS DETERMINED BY AN AVERAGE OVER ANY 12 CONSECUTIVE MONTHS CONTAINED IN CHEMICAL ADDITIVES CONSUMED IN THE COOLING TOWER. SYNTHETIC MINOR LIMIT 0.21 LB/H Other Case-by-Case

NC-0113 NUCOR STEEL 11/23/2004 COOLING TOWERS CT PM

MIST ELIMINATORS WITH A 0.008 

PERCENT DRIFT LOSS

BACT-PSD PM %drift Emission Limits

MIN 0.005 %drift MIN 

MAX 0.008 %drift MAX 

MEDIAN 0.007 %drift MEDIAN 

COUNT 3 CASES COUNT 

CT RBLC PM BACT Limits Summary

Other (non-BACT)-case-by-

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

E

Li

IN-0108 11/21/2003 BOILER, NATURAL GAS, (2)

NATURAL GAS 34 MMBTU/H PM10

COMPLIANCE IS BY USING NATURAL GAS 0.0019 LB/MMBTU

BACTPSD 

AZ-0047 12/1/2004 AUXILIARY BOILER

NATURAL GAS 38 MMBTU/H PM10 0.0033 LB/MMBTU

BACTPSD 

OR-0040 3/12/2003 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 50000 LB/H PM10 0.0042 LB/MMBTU

BACTPSD 

AL-0179 10/3/2001 30 MMBTU/HR AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H PM10

NATURAL GAS AS EXCLUSIVE FUEL 0.005 LB/MMBTU

BACTPSD 0.2 LB

TN-0153 4/3/2002 CCR STABILIZATION REBOILER

NATURAL GAS 54 MMBTU/H PM10 0.005 LB/MMBTU

BACTPSD 

OH-0255 3/29/2001 BOILER, NATURAL GAS

NATURAL GAS 85.2 MMBTU/H PM10 0.43 LB/H

BACTPSD 1.87 T/

OH-0251 11/29/2001 BOILER, NATURAL GAS

NATURAL GAS 91.2 MMBTU/H PM10 0.46 LB/H

BACTPSD 2.06 T/

OH-0263 8/9/2001 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H PM10 0.41 LB/H

BACTPSD 1.8 T/

OK-0072 5/6/2002 AUXILIARY BOILER

NATURAL GAS 93 MMBUT/H PM10

USE OF NATURAL GAS/LOW ASH FUEL AND EFFICIENT COMBUSTION 0.0053 LB/MMBTU

BACTPSD 

VA-0271 3/24/2003 BOILER NO. 1

NATURAL GAS 43.2 MMBTU/H PM10

GOOD COMBUSTION PRACTICES 0.32 LB/H N/A 

VA-0261 9/6/2002 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H PM10

GOOD COMBUSTION PRACTICES. 0.58 LB/H

BACTPSD 0.87 T/

VA-0255 11/18/2002 BOILER, AUXILIARY

NATURAL GAS 99 MMBTU/H PM10

CLEAN FUEL AND GOOD COMBUSTION PRACTICES. 0.7 LB/H

Other Case-byCase 3.7 T/

OK-0046 5/17/2001 AUXILIARY BOILER

NATURAL GAS 20 MMBTU/H PM10 USE OF LOW ASH FUEL 0.0074 LB/MMBTU

BACTPSD 

OK-0051 10/1/1999 AUXILIARY BOILER

NATURAL GAS PM10

USE OF LOW ASH FUEL AND EFFICIENT COMBUSTION 0.0074 LB/MMBTU

BACTPSD 

IN-0087 6/6/2001 AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 46 MMBTU/H PM10

GOOD COMBUSTION. LB/H LIMIT IS FOR EACH BOILER. 0.0075 LB/MMBTU

BACTPSD 0.35 LB

AR-0086 6/11/2004 VTD BOILER

NATURAL GAS 50 MMBTU/H PM10

GOOD COMBUSTION PRACTICE 0.4 LB/H

BACTPSD 1.7 T/

AL-0191 3/23/2004 BOILERS, NATURAL GAS, (3)

NATURAL GAS 50 MMBTU/H PM10 CLEAN FUEL 0.38 LB/H

BACTPSD 0.0075 LB

IA-0062 12/20/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H PM10 LOW ASH FUEL, NG 0.0075 LB/MMBTU

Other Case-byCase 

NC-0094 1/9/2002 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 83 MMBTU/H PM10

GOOD COMBUSTION AND DESIGN 0.62 LB/H

BACTPSD 

TN-0153 4/3/2002 BOILER, NO. 9

NATURAL GAS 95 MMBTU/H PM10 0.0075 LB/MMBTU

BACTPSD 

OK-0056 2/12/2002 AUXILIARY BOILERS

NATURAL GAS 0 PM10

LOW ASH FUEL (NATURAL GAS) 0.0076 LB/MMBTU

BACTPSD 

AR-0077 7/22/2004 BOILERS

NATURAL GAS 22 MMBTU/H PM10

NATURAL GAS COMBUSTION ONLY 0.0076 LB/MMBTU

BACTPSD 

OK-0074 5/1/2001 AUXILIARY BOILER

NATURAL GAS 27.5 MMBTU/H PM10

GOOD COMBUSTION PRACTICES AND DESIGN 0.0076 LB/MMBTU

BACTPSD 

AL-0192 10/18/2002 BOILERS, NATURAL GAS, (3)

NATURAL GAS 30 MMBTU/H PM10

CLEAN FUEL, GOOD COMBUSTION 0.228 LB/H

BACTPSD 0.0076 LB

IN-0108 11/21/2003 BOILER, NATURAL GAS, (2)

NATURAL GAS 34 MMBTU/H PM10

COMPLIANCE BY USING NATURAL GAS 0.0076 LB/MMBTU

BACTPSD 

OK-0044 8/16/2001 AUXILIARY BOILERS, (2)

NATURAL GAS 48 MMBTU/H PM10

USE OF LOW ASH FUEL AND EFFICIENT COMBUSTION 0.72 LB/H

BACTPSD 3.13 T/

IA-0058 4/10/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H PM10 0.0076 LB/MMBTU

BACTPSD 2.27 T/

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

E

Li

WI-0227 10/13/2004 NATURAL GAS FIRED AUXILLIARY BOILER

NATURAL GAS 97.1 MMBTU/H PM10

NATURAL GAS FUEL, GOOD COMBUSTION PRACTICES 0.74 LB/H

BACTPSD 

OH-0248 9/24/2002 BOILER

NATURAL GAS 99 MMBTU/H PM10 0.76 LB/H

BACTPSD 0.0076 LB

OH-0265 10/16/2001 BOILER, NATURAL GAS

NATURAL GAS 49 MMBTU/H PM10 0.38 LB/H

BACTPSD 0.15 T/

TX-0364 1/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H PM10 NONE INDICATED 0.02 LB/H

Other Case-byCase 0.08 T/

TX-0354 12/19/2002 (2) STEAM BOILERS, X-426A AND X-426B

NATURAL GAS 15.8 MMBTU/H PM10 NONE INDICATED 0.12 LB/H

Other Case-byCase 0.53 T/

IN-0086 5/9/2001 AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 35 MMBTU/H PM10

GOOD COMBUSTION. LB/H LIMIT IS FOR EACH BOILER. 0.008 LB/MMBTU

BACTPSD 0.28 LB

TX-0378 11/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H PM10 NONE INDICATED 0.48 LB/H N/A 2.11 T/TX-0408 11/22/2002 AUXILIARY BOILER, (2)

NATURAL GAS 6 MMBTU/H PM10 0.05 LB/H

BACTPSD 0.2 T/

AR-0076 2/17/2004 BOILER, HOT WATER, (2) SN-PBCDF-05, -06

NATURAL GAS 0.01 MMDSCF/H PM10 NATURAL GAS ONLY. 0.1 LB/H

BACTPSD 

OK-0071 10/25/2001 AUXILIARY BOILER

NATURAL GAS 22 MMBTU/H PM10

USE OF LOW ASH FUELS 0.009 LB/MMBTU

BACTPSD 

NM-0044 6/27/2002 AUXILIARY BOILERS (AUX-1 AND AUX-2)

NATURAL GAS 33 MMBTU/H PM10

NATURAL GAS ONLY, GOOD COMBUSTION PRACTICE 0.3 LB/H

BACTPSD 

NV-0039 6/1/2001 AUXILIARY BOILERS

NATURAL GAS 44.1 MMBTU/H PM10

USE OF PIPELINEQUALITY NATURAL GAS AND GOOD COMBUSTION CONTROL 0.4 LB/H

BACTPSD 

CO-0041 5/6/1999 BOILER NO.2, TEST MINE HOT WATER (1)

NATURAL GAS 51.08 MMBTU PM10 COMBUSTION CONTROL 0.009 LB/MMBTU

BACTPSD 0.02 T/

IA-0048 6/1/1998 BOILER, BACKUP 77 MMBTU/H PM10 0.7 LB/H

BACTPSD 

OK-0043 10/22/2001 AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H PM10

USE OF LOW ASH FUEL & EFFICIENT COMBUSTION 0.01 LB/MMBTU

BACTPSD 

OH-0252 12/28/2004 BOILERS (2)

NATURAL GAS 30.6 MMBTU/H PM10 0.31 LB/H

BACTPSD 0.46

T/12MO

OH-0254 8/14/2003 BOILER

NATURAL GAS 30.6 MMBTU/H PM10 0.31 LB/H

BACTPSD 0.64

T/12MO

OK-0090 3/21/2003 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H PM10

USE OF LOW ASH FUEL AND EFFICIENT COMBUSTION 0.01 LB/MMBTU

BACTPSD 

OK-0070 6/13/2002 AUXILIARY BOILER

NATURAL GAS 33 MMBTU/H PM10

LOW ASH FUEL AND EFFICIENT COMBUSTION 0.01 LB/MMBTU

BACTPSD 

AR-0051 4/1/2002 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H PM10

GOOD OPERATING PRACTICE 0.01 LB/MMBTU

BACTPSD 

AR-0040 12/29/2000 BOILERS, AUXILIARY 2

NATURAL GAS 44.1 MMBTU/H PM10

CLEAN FUELS, PROPER COMBUSTION. LB/HR LIMIT FOR EACH BOILER. 0.01 LB/MMBTU

BACTPSD 0.5 LB

NM-0042 12/29/2000 AUX-1 AUXILARY BOILER

NATURAL GAS 44.1 MMBTU/H PM10

NATURAL GAS ONLY, PRE-FILTERING - LIMIT INCLUDES BOTH FRONT END AND BACK END OF SAMPLING TRAIN 0.4 LB/H

BACTPSD 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

E

Li

MN-0054 12/4/2003 BOILER, COMMERCIAL

NATURAL GAS 70 MMBTU/H PM10 CLEAN FUELS 0.008 LB/MMBTU

BACTPSD 

AL-0168 1/12/2001 BOILER

NATURAL GAS 83 MMBTU/H PM10 EFFICIENT COMBUSTION 0.01 LB/MMBTU

BACTPSD 0.63 LB

*LA-0112 2/13/1998 BOILER NO. 1

NATURAL GAS 95 MMBTU/H PM10

GOOD DESIGN, PROPER OPERATING PRACTICES,AND USE CLEAN NATURAL GAS AS FUEL. 0.95 LB/H

BACTPSD 4.16 T/

AR-0076 2/17/2004 BOILER, PROCESS STEAM, (2) SN-PBCDF-03, -04

NATURAL GAS 0.03 MMDSCF/H PM10 NATURAL GAS ONLY. 0.3 LB/H

BACTPSD 

CA-0736 9/19/1996 300 HP BOILER USED AS A BACKUP

PUC QUALITY NAT GAS 10 MMBTU/HR PM10 NO CONTROL 0.012 LB/MMBTU LAER 2.9 LB

AR-0070 8/23/2002 AUXILIARY BOILER

NATURAL GAS 33 MMBTU/H PM10

GOOD COMBUSTION PRACTICE 0.012 LB/MMBTU

BACTPSD 

CA-0790 12/30/1996 NEBRASKA BOILER, MODEL NS-B-40

NATURAL GAS 31.2 MMBTU/HR PM10 NO CONTROL 0.0137 LB/MMBTU LAER 0.014 LB

NJ-0042 2/5/1999 BOILER 1 (NATURAL GAS)

NATURAL GAS 84.4 MMBTU/H PM10 1.2 LB/H

BACTPSD 

*AZ-0049 9/4/2003 AUXILIARY BOILER FOR GE TURBINE

NATURAL GAS 41 MMBTU/H PM10 0.015 LB/MMBTU

BACTPSD 

*AZ-0049 9/4/2003 AUXILIARY BOILER FOR SIEMENS TURBINES

NATURAL GAS 55.34 MMBTU/H PM10 0.015 LB/MMBTU

BACTPSD 

OH-0258 2/15/2001 BOILERS (4)

NATURAL GAS 20.9 MMBTU/H PM10 0.04 LB/H N/A 0.18 T/

IN-0110 10/5/2001 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 35 MMBTU/H PM10

CLEAN FUEL, GOOD COMBUSTION PRACTICES 0.02 LB/MMBTU

Other Case-byCase 0.7 LB

AL-0169 2/5/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H PM10

GOOD COMBUSTION PRACTICES 0.02 LB/MMBTU

BACTPSD 0.8 LB

OH-0257 12/27/2001 AUXILIARY BOILER

NATURAL GAS 76 MMBTU/H PM10 1.52 LB/H

BACTPSD 2.28 T/

LA-0174 1/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H PM10 FIRED BY NATURAL GAS 3.33 LB/H

BACTPSD 2.2 T/

AR-0076 2/17/2004 BOILER, LABORATORY SN-PBCDF-16

NATURAL GAS 1.4 mmbtu/h PM10 NATURAL GAS ONLY. 0.1 LB/H

BACTPSD 

PA-0210 12/14/2001 BOILER, (2)

NATURAL GAS 33.5 MMBTU/H PM10 0.4 LB/MMBTU N/A 

IA-0054 5/20/1997 HIGH PRESSURE BOILER #1

NATURAL GAS 0.3 MMBTU/H PM10 0.18 LB/H

BACTPSD 0.8 T/

IA-0054 5/20/1997 BOILER #2 B2

NATURAL GAS 2.3 MMBTU/H PM10

LOW NOX BURNER, FLUE GAS RECIRC. 1.39 LB/H

BACTPSD 6.07 T/

IA-0054 5/20/1997 BOILER #1

NATURAL GAS 2.3 MMBTU/H PM10

LOW NOX BURNER , FLUE GAS RECIRCULATION 1.39 LB/H

BACTPSD 6.07 T/

IA-0054 5/20/1997 BOILER #3 B3

NATURAL GAS 2.3 MMBTU/HR PM10

LOW NOX BURNER, FLUE GAS RECIRCULATION 1.39 LB/H

BACTPSD 6.07 T/

*AK-0062 8/19/2005 NATCO TEG REBOILER

NATURAL GAS 1.34 MMBtu/hr PM10

GOOD OPERATION PRACTICES

BACTPSD 

TX-0389 12/31/2002 BACK-UP BOILER

NATURAL GAS 13.4 MMBUT/H PM10 0.1 LB/H

Other Case-byCase 0.44 T/

OK-0041 1/19/2000 AUXILIARY BOILER

NATURAL GAS 22 MMBTU/H PM10 CLEAN FUEL 0.1 T/YR

BACTPSD

OH-0276 4/14/2003 BOILER FOR VACUUM OXYGEN DEGASSER VESSEL

NATURAL GAS 25 MMBTU/H PM10 0.19 LB/H

BACTPSD 0.83 T/

VA-0243 12/1/2002 BOILER, NAT GAS & OIL

NATURAL GAS 26.5 MMBTU/H PM10

NO CONTROLS LISTED. EMISSION LIMITS IN T/YR

ONLY 0.9 T/YR

Other Case-byCase

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

E

Li

*WA-0292 10/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H PM10 7 LB/D

Other Case-byCase

AL-0181 10/23/2001 31.4 MMBTU/HR NATURAL GAS FIRED BOILER

NATURAL GAS 31.4 MMBTU/H PM10

NATURAL GAS IS EXCLUSIVE FUEL. 0.009 LB/MMBTU

BACTPSD 0.31 LB

AL-0180 12/11/2001 35 MMBTU/HR NAT. GAS FIRED AUXILIARY BOILER

NATURAL GAS 35 MMBTU/H PM10

NATURAL GAS AS EXCLUSIVE FUEL. 0.009 LB/MMBTU

BACTPSD 0.31 LB

AL-0185 7/12/2002 TWO (2) 40 MMBTU/H AUXILIARY BOILERS

NATURAL GAS 40 MMBTU/H PM10 NATURAL GAS ONLY 0.0075 LB/MMBTU

BACTPSD 0.3 LB

MD-0033 9/27/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H PM10

EXCLUSIVE USE OF NATURAL GAS, ADVANCED DRY LOWNOX BURNERS; GOOD COMBUSTION CONTROLS ANNUAL FUEL USE LIMIT

BACTPSD

VA-0271 3/24/2003 BOILER NO. 3

NAT GAS OR DIS OIL 43.2 MMBTU PM10

GOOD COMBUSTION PRACTICES 2.75 T/YR N/A

WI-0226 8/27/2004 NATURAL GAS FIRED BOILER

NATURAL GAS 46.2 MMBTU/H PM10 NATURAL GAS 0.8 LB/H N/A

IA-0060 7/23/2002 AUXILIARY BOILER (48.5 MMBTU/H)

NATUAL GAS 48.69

MILLION CF/YR PM10 GCP 0.007 LB/MMBTU

BACTPSD

NV-0037 5/14/2004 AUXILIARY BOILER

NATURAL GAS 60 MMBTU/H PM10

RESTRICTION OF OPERATION TO NATURAL GAS 0.5 LB/H LAER

OK-0054 8/21/2001 BOILERS

NATURAL GAS 62.77 MMBTU/H PM10

NATURAL GAS FUEL, GOOD COMBUSTION PRACTICE 0.63 LB/H

BACTPSD 2.76 T/

IN-0097 12/3/2001 BOILERS 1 & 2

NATURAL GAS 75 MMBTU/H PM10 794.13

LB/MMCF NG

Other Case-byCase

TX-0363 11/13/2000 BOILER NO. 2 NAT GAS PM10 NONE INDICATED 0.12 LB/H

Other Case-byCase 0.27 T/

TX-0363 11/13/2000 BOILER NO 3 NAT GAS PM10 NONE INDICATED 0.08 LB/H

Other Case-byCase 0.36 T/

TX-0300 10/13/1998 GLYCOL REBOILER NAT GAS PM10

FUEL IS LIMITED TO PIPELINE-QUALITY, SWEET NATURAL GAS CONTAINING NO MORE THAN 5 GR S/100 DSCF 0.02 LB/H

Other Case-byCase 0.09 T/

BACT-PSD PM10 lb/MMBtu Emission Limits

MIN 0.0019 lb/MMBtu MIN 0.007 lb/

MAX 0.6 lb/MMBtu MAX 0.4 lb/

MEDIAN 0.0085 lb/MMBtu MEDIAN 0.008 lb/

COUNT 59 CASES COUNT 11 CA

RBLC PM10 BACT Limits Summary

Other (non-BACT) PM10 lb/MMBt

Limits

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-by

case 

basis

GA-0063 4/3/1996 BOILER, NATURAL GAS

NATURAL GAS 60 MMBTU/H PM

COMPLETE COMBUSTION 0.005 LB/MMBTU

BACTPSD 

NJ-0046 3/7/1996

BOILERS 4&5, COMBUSTION CONTROLS, OXYGEN TRIM, ETC

NATURAL GAS 94 MMBTU/H

Total Suspended Particulates N/A 0.49 LB/H

BACTPSD 

IA-0060 7/23/2002 AUXILIARY BOILER (48.5 MMBTU/H)

NATUAL GAS 48.69

MILLION CF/YR PM GCP 0.007 LB/MMBTU

Other Case-byCase 

TX-0274 4/3/2000 AUXILIARY BOILER

NATURAL GAS 54.01 MMBTU/H PM

FUEL SPECIFICATIONS OF NO MORE THAN 2.5 GRAINS TOTAL SULFUR PER 100 DRY STANDARD CUBIC FEET ON A SHORT-TERM BASIS AND 0.5 GRAIN TOTAL SULFUR PER 100 DSCF ON A ROLLING 12- 0.4 LB/H N/A 

IN-0097 12/3/2001 BOILERS 1 & 2

NATURAL GAS 75 MMBTU/H PM 7.6

LB/MMSCF NATURAL GAS

Other Case-byCase 

VA-0261 9/6/2002 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H PM

GOOD COMBUSTION PRACTICES. 0.58 LB/H

BACTPSD 

MA-0029 9/29/1999 BOILER, AUXILIARY

NATURAL GAS 96 MMBTU/H PM NATURAL GAS FUEL 0.7 LB/H

BACTPSD 

CA-0919 11/23/1999 BOILER, FIRE TUBE

NATURAL GAS 31.5 MMBTU/H PM

NO BACT LIMITS WERE

APPLIED TO PM. DEFAULT EMISSION FACTORS ARE THE BASIS OF THE PM LEVEL LISTED HERE. 0.0071 LB/MMBTU

Other Case-byCase 

AK-0045 6/6/2000 DRILLING BOILER NO. 1

NATURAL GAS 100 HP PM NONE INDICATED 0.05 GR/DSCF N/A 

AK-0038 2/5/1999 GLYCOL REBOILER, UNIT 13

NATURAL GAS 5 MMBTU/H PM 0.05 GR/DSCF

Other Case-byCase 

AK-0038 2/5/1999 RIG BOILER (NATURAL GAS), UNIT 206, 207

NATURAL GAS 6.3 MMBTU/H PM

GOOD OPERATIONS PRACTICES 0.05 GR/DSCF

Other Case-byCase 

WI-0207 1/21/2004 BOILER, S52/B52, 11 MMBTU/H

NATURAL GAS 11 MMBTU/H PM

NATURAL GAS / PROPANE; GOOD COMBUSTION CONTROL 0.0075 LB/MMBTU

BACTPSD 

IN-0095 12/7/2001 AUXILLIARY BOILER

NATURAL GAS 21 MMBTU/H PM

NATURAL GAS AS SOLE FUEL 0.0075 LB/MMBTU

BACTPSD 

WI-0207 1/21/2004 BOILER, S53 / B53, 34 MMBTU/H

NATURAL GAS 34 MMBTU/H PM

NATURAL GAS / PROPANE; GOOD COMBUSTION CONTROL 0.0075 LB/MMBTU

BACTPSD 

WI-0207 1/21/2004 BOILER, S50/B50, 60 MMBTU/H

NATURAL GAS 60 MMBTU/H PM

NATURAL GAS/ PROPANE; GOOD COMBUSTION CONTROL 0.0075 LB/MMBTU

BACTPSD 

IA-0062 12/20/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H PM LOW ASH FUEL, NG 0.0075 LB/MMBTU

Other Case-byCase 

page 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 2
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-by

case 

basis

WI-0207 1/21/2004 BOILER, S51/B51, 80 MMBTU/H

NATURAL GAS 80 MMBTU/H PM

NATURAL GAS, GOOD COMBUSTION CONTROL 0.0075 LB/MMBTU

BACTPSD 

AL-0140 6/19/1997 BOILER, NATURAL GAS FIRED, 2

NATURAL GAS 11.7 MMBTU/H PM CLEAN FUEL 0.0076 LB/MMBTU

BACTPSD 

AL-0139 6/19/1997 BOILER, NATURAL GAS FIRED, 2

NATURAL GAS 13.4 MMBTU/H PM CLEAN FUEL. 0.0076 LB/MMBTU

BACTPSD 

MN-0053 7/15/2004 BOILER, NATURAL GAS (1)

NATURAL GAS 40 MMBTU/H PM

CLEAN FUEL AND GOOD COMBUSTION. 0.008 LB/MMBTU

BACTPSD 

WV-0021 6/9/2004 BOILER, NATURAL GAS, 39.00 MMBTU

NATURAL GAS 365 MMSCF/YR PM 0.32 PPH

BACTPSD 

GA-0098 3/24/2003 AUXILIARY BOILER

NATURAL GAS 83 MMBTU/H PM 0.0084 LB/MMBTU

Other Case-byCase 

IA-0048 6/1/1998 BOILER, BACKUP 77 MMBTU/H PM 0.7 LB/H

BACTPSD 

MA-0027 5/7/2000 AUXILIARY BOILER

NATURAL GAS 26.6 MMBTU/H PM NATURAL GAS FUEL 0.3 LB/H

BACTPSD 

GA-0101 10/23/2002 BOILER, AUXILIARY

NATURAL GAS 31.4 MMBTU/H PM

GOOD COMBUSTION PRACTICE, CLEAN FUEL 0.01 LB/MMBTU

BACTPSD 

MN-0054 12/4/2003 BOILER, COMMERCIAL

NATURAL GAS 70 MMBTU/H PM CLEAN FUELS 0.008 LB/MMBTU

BACTPSD 

VA-0271 3/24/2003 BOILER NO. 1

NATURAL GAS 43.2 MMBTU/H PM

GOOD COMBUSTION PRACTICES 0.62 LB/H N/A 

IN-0068 1/19/1996 BOILERS, NATURAL GAS

NATURAL GAS 93.9 MMBTU/H PM 1.29 LB/H

BACTPSD 

WI-0181 8/2/2000 BOILER

NATURAL GAS 10 MMBTU/H PM

BACT FOR PM IS DETERMINED TO BE GOOD COMBUSTION CONTROL & THE USE OF NAT. GAS TO FUEL THE BOILER 0.016 LB/MMBTU

BACTPSD 

LA-0174 1/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H PM FIRED BY NATURAL GAS 3.33 LB/H

BACTPSD 

ND-0018 7/9/1998 BOILER, NEBRASKA, NAT GAS

NATURAL GAS 28 MMBTU/H PM 2.4 LB/H

BACTPSD 

KY-0068 5/29/1997 BOILER (NATURAL GAS)

NATURAL GAS 96 MMBTU/H PM FABRIC FILTER 0.1 LB/MMBTU

BACTPSD 

IN-0069 8/9/1996 BOILERS, NATURAL GAS FIRED (6)

NATURAL GAS 58 MMBTU/H PM

LOW NOX BURNERS & FUEL SPEC: USE OF NATURAL GAS AS FUEL. 0.2 LB/MMBTU

BACTPSD 

KY-0087 7/12/2002 BOILER, NATURAL GAS, #4

NATURAL GAS 33.5 MMBTU/H PM 0.308 LB/MMBTU

BACTPSD 

IA-0054 5/20/1997 HIGH PRESSURE BOILER #1

NATURAL GAS 0.3 MMBTU/H

Total Suspended Particulates 0.18 LB/H

BACTPSD 

page 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 2
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-by

case 

basis

IA-0054 5/20/1997 BOILER #2 B2

NATURAL GAS 2.3 MMBTU/H

Total Suspended Particulates

LOW NOX BURNER, FLUE GAS RECIRC 1.39 LB/H

BACTPSD 

IA-0054 5/20/1997 BOILER #1

NATURAL GAS 2.3 MMBTU/H

Total Suspended Particulates

LOW NOX BURNER, FLUE GAS RECIRCULATION 1.39 LB/H

BACTPSD 

IA-0054 5/20/1997 BOILER #3 B3

NATURAL GAS 2.3 MMBTU/HR

Total Suspended Particulates

LOW NOX BURNER, FLUE GAS RECIRC. 1.39 LB/H

BACTPSD 

WY-0034 2/6/1998 BOILER, NATURAL GAS

NATURAL GAS 100 MMBTU/H PM

MINIMAL PARTICULATE EMISSIONS AND LOW EMITTING FUEL 5 LB/MMBTU

BACTPSD 

AL-0178 1/5/2001 TWO (2) 11.7 MMBTU/H BOILERS

NATURAL GAS 11.7 MMBTU/H PM 0.0076 LB/MMBTU

BACTPSD 

AL-0178 1/5/2001 TWO (2) 13.4 MMBTU/H BOILERS

NATURAL GAS 13.4 MMBTU/H PM 0.0076 LB/MMBTU

BACTPSD 

VA-0243 12/1/2002 BOILER, NAT GAS & OIL

NATURAL GAS 26.5 MMBTU/H PM

EMISSION LIMITS IN T/YR ONLY 1.1 T/YR

Other Case-byCase

VA-0271 3/24/2003 BOILER NO. 3

NAT GAS

OR DIS OIL 43.2 MMBTU PM

GOOD COMBUSTION PRACTICES 3.37 T/YR N/A

AK-0053 3/21/2000 LISTER BOILER, DR11 100 HP PM NONE INDICATED 0.05 GR/DSCF N/AAK-0053 3/21/2000 LISTER BOILER, DR12 100 HP PM NONE INDICATED 0.05 GR/DSCF N/A

BACT-PSD PM lb/MMBtu Emission Limits

MIN 0.005 lb/MMBtu MIN 

MAX 5 lb/MMBtu MAX 

MEDIAN 0.010 lb/MMBtu MEDIAN 

COUNT 29 CASES COUNT 

RBLC PM BACT Limits Summary

Other (

page 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 2
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Em

Li

AZ-0032 9/1/1996 BOILERS, GENERATORS 0 SO2 FUEL SPEC: 0.055 WT% S OIL 5 TPY

Other Case-byCase 

TX-0354 12/19/2002 (2) STEAM BOILERS, X-426A AND X-426B

NATURAL GAS 15.8 MMBTU/H SO2

FUEL GAS SHALL BE SWEET NATURAL GAS CONTAINING NO MORE THAN 5 GR S/100 DSCF. 0.01 LB/H

Other Case-byCase 

IN-0095 12/7/2001 AUXILLIARY BOILER

NATURAL GAS 21 MMBTU/H SO2

LOW SULFUR CONTENT NATURAL GAS 0.0006 LB/MMBTU

BACTPSD 

AR-0077 7/22/2004 BOILERS

NATURAL GAS 22 MMBTU/H SO2 NATURAL GAS COMBUSTION ONLY 0.0006 LB/MMBTU

BACTPSD 

IN-0108 11/21/2003 BOILER, NATURAL GAS, (2)

NATURAL GAS 34 MMBTU/H SO2

COMPLIANCE BY USING NATURAL GAS 0.0006 LB/MMBTU

BACTPSD 

IN-0086 5/9/2001 AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 35 MMBTU/H SO2

LOW SULFUR NATURAL GAS ONLY (LESS THAN 0.8% BY WEIGHT). LB/H LIMIT IS FOR EACH BOILER. 0.0006 LB/MMBTU

BACTPSD 

IN-0087 6/6/2001 AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 46 MMBTU/H SO2

NATURAL GAS AS FUEL. LIMIT IS FOR EACH BOILER. 0.0006 LB/MMBTU

BACTPSD 

AR-0086 6/11/2004 VTD BOILER

NATURAL GAS 50 MMBTU/H SO2

GOOD COMBUSTION PRACTICE, NATURAL GAS COMBUSTION 0.1 LB/H

BACTPSD 

IA-0062 12/20/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H SO2 LOW SULFUR FUEL, NG 0.0006 LB/MMBTU

Other Case-byCase 

OH-0255 3/29/2001 BOILER, NATURAL GAS

NATURAL GAS 85.2 MMBTU/H SO2

LOW S NATURAL GAS, 2 GR/100 SCF 0.05 LB/H

BACTPSD 

OH-0251 11/29/2001 BOILER, NATURAL GAS

NATURAL GAS 91.2 MMBTU/H SO2 0.055 LB/H N/A 

IN-0068 1/19/1996 BOILERS, NATURAL GAS

NATURAL GAS 93.9 MMBTU/H SO2 0.0558 LB/H

BACTPSD 

CA-0919 11/23/1999 BOILER, FIRE TUBE

NATURAL GAS 31.5 MMBTU/H SO2

NO BACT LIMITS WERE APPLIED TO SOX. DEFAULT EMISSION FACTORS ARE THE BASIS OF THE SOX LEVEL LISTED HERE. 0.0008 LB/MMBTU

Other Case-byCase 

OK-0071 10/25/2001 AUXILIARY BOILER

NATURAL GAS 22 MMBTU/H SO2

USE OF PIPELINE QUALITY NATURAL GAS 0.001 LB/MMBTU

BACTPSD 

OH-0252 12/28/2004 BOILERS (2)

NATURAL GAS 30.6 MMBTU/H SO2

THE MAXIMUM S CONTENT OF THE NATURAL GAS SHALL NOT EXCEED 2 GRAINS PER 100 CUBIC FEET. 0.031 LB/H

BACTPSD 

OH-0254 8/14/2003 BOILER

NATURAL GAS 30.6 MMBTU/H SO2 0.031 LB/H

BACTPSD 

OH-0265 10/16/2001 BOILER, NATURAL GAS

NATURAL GAS 49 MMBTU/H SO2

THE MAXIMUM SULFUR CONTENT OF THE NATURAL GAS SHALL NOT EXCEED 0.3 GRAINS PER 100 STANDARD CUBIC FEET. 0.05 LB/H

BACTPSD 

MN-0054 12/4/2003 BOILER, COMMERCIAL

NATURAL GAS 70 MMBTU/H SO2 LOW SULFUR FUEL 0.001 LB/MMBTU

BACTPSD 

AL-0168 1/12/2001 BOILER

NATURAL GAS 83 MMBTU/H SO2 0.001 LB/MMBTU

BACTPSD 

NJ-0042 2/5/1999 BOILER 1 (NATURAL GAS)

NATURAL GAS 84.4 MMBTU/H SO2 NONE LISTED 0.1 LB/H

BACTPSD 

VA-0255 11/18/2002 BOILER, AUXILIARY

NATURAL GAS 99 MMBTU/H SO2

LOW SULFUR FUEL AND GOOD COMBUSTION PRACTICES. 0.1 LB/H

Other Case-byCase 

NJ-0045 1/14/1997 BOILERS - NAT GAS (3)

NATURAL GAS 99.5 MMBTU/H SO2 NONE 0.1 LB/H

BACTPSD 

AL-0140 6/19/1997 BOILER, NATURAL GAS FIRED, 2

NATURAL GAS 11.7 MMBTU/H SO2 CLEAN FUEL 0.014 LB/H

BACTPSD 

AL-0139 6/19/1997 BOILER, NATURAL GAS FIRED, 2

NATURAL GAS 13.4 MMBTU/H SO2 CLEAN FUEL 0.016 LB/H

BACTPSD 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Em

Li

TX-0408 11/22/2002 AUXILIARY BOILER, (2)

NATURAL GAS 6 MMBTU/H SO2 0.01 LB/H

BACTPSD 

MA-0027 5/7/2000 AUXILIARY BOILER

NATURAL GAS 26.6 MMBTU/H SO2

NATURAL GAS FUEL OF < .8 GRAINS PER 100 SCF. 0.06 LB/H

BACTPSD 

AZ-0047 12/1/2004 AUXILIARY BOILER

NATURAL GAS 38 MMBTU/H SO2 0.0023 LB/MMBTU

BACTPSD 

*AZ-0049 9/4/2003 AUXILIARY BOILER FOR GE TURBINE

NATURAL GAS 41 MMBTU/H SO2 0.0025 LB/MMBTU

BACTPSD 

*AZ-0049 9/4/2003 AUXILIARY BOILER FOR SIEMENS TURBINES

NATURAL GAS 55.34 MMBTU/H SO2 0.0025 LB/MMBTU

BACTPSD 

MA-0029 9/29/1999 BOILER, AUXILIARY

NATURAL GAS 96 MMBTU/H SO2

NATURAL GAS FUEL WITH NO MORE THAN .8 GRAINS OF SULFUR PER 100 CU FT. 0.3 LB/H

BACTPSD 

NM-0044 6/27/2002 AUXILIARY BOILERS (AUX-1 AND AUX-2)

NATURAL GAS 33 MMBTU/H SO2

NATURAL GAS, GOOD COMBUSTION PRACTICE 0.1 LB/H

BACTPSD 

AR-0076 2/17/2004

BOILER, PROCESS STEAM, (2) SN-PBCDF-03, -

04

NATURAL GAS 0.03 MMDSCF/H SO2 LOW-SULFUR NATURAL GAS ONLY. 0.1 LB/H

BACTPSD 

LA-0174 1/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H SO2 FIRING NATURAL GAS 0.26 LB/H

BACTPSD 

OH-0248 9/24/2002 BOILER

NATURAL GAS 99 MMBTU/H SO2 0.56 LB/H

BACTPSD 

OK-0090 3/21/2003 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H SO2

BACT IS USE OF PIPE-LINE QUALITY NATURAL GAS 0.2 LB/H

BACTPSD 

IN-0110 10/5/2001 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 35 MMBTU/H SO2 GOOD COMBUSTION PRACTICE 0.006 LB/MMBTU

BACTPSD 

AL-0169 2/5/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H SO2 GOOD COMBUSTION PRACTICES 0.006 LB/MMBTU

BACTPSD 

AR-0040 12/29/2000 BOILERS, AUXILIARY 2

NATURAL GAS 44.1 MMBTU/H SO2 LOW SULFUR FUELS 2 GR/DSCF

BACTPSD 

OH-0257 12/27/2001 AUXILIARY BOILER

NATURAL GAS 76 MMBTU/H SO2

LOW SULFUR FUEL, NATURAL GAS SULFUR LIMIT - 2 GR/100 SCF 0.5 LB/H

BACTPSD 

OH-0263 8/9/2001 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H SO2 0.48 LB/H

BACTPSD 

WI-0227 10/13/2004 NATURAL GAS FIRED AUXILLIARY BOILER

NATURAL GAS 97.1 MMBTU/H SO2 NATURAL GAS FUEL 0.06 LB/H

BACTPSD 

OK-0051 10/1/1999 AUXILIARY BOILER

NATURAL GAS SO2 USE OF NATURAL GAS 0.006 LB/MMBTU

BACTPSD 

TX-0364 1/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H SO2 NONE INDICATED 0.02 LB/H

Other Case-byCase 

AR-0076 2/17/2004 BOILER, HOT WATER, (2) SN-PBCDF-05, -06

NATURAL GAS 0.01 MMDSCF/H SO2 LOW-SULFUR NATURAL GAS ONLY. 0.1 LB/H

BACTPSD 

NV-0039 6/1/2001 AUXILIARY BOILERS

NATURAL GAS 44.1 MMBTU/H SO2

USE OF PIPELINE-QUALITY NATURAL GAS 0.4 LB/H

BACTPSD 

TX-0274 4/3/2000 AUXILIARY BOILER

NATURAL GAS 54.01 MMBTU/H SO2

FUEL SPECIFICATIONS OF NO MORE THAN 2.5 GRAINS TOTAL SULFUR PER 100 DRY STANDARD CUBIC FEET ON A SHORT-TERM BASIS AND 0.5 GRAIN TOTAL SULFUR PER 100 DSCF ON A ROLLING 12-MONTH AVERAGE BASIS. 0.77 LB/H N/A 

TX-0378 11/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H SO2 NONE INDICATED 0.95 LB/H N/A AK-0045 6/6/2000 DRILLING BOILER NO. 1

NATURAL GAS 100 HP SO2

USE NATURAL GAS WITH A HYDROGEN SULFIDE CONTENT NOT TO EXCEED 200 PPM AND FUEL OIL WITH A SULFUR CONTENT NOT TO EXCEED 0.25% BY WEIGHT. 500 PPM N/A 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Em

Li

VA-0271 3/24/2003 BOILER NO. 1

NATURAL GAS 43.2 MMBTU/H SO2

CONTINUOUS EMISSION MONITORING SYSTEM AND GOOD COMBUSTION PRACTICES. 2.19 LB/H N/A 

AR-0076 2/17/2004 BOILER, LABORATORY SN-PBCDF-16

NATURAL GAS 1.4 mmbtu/h SO2 LOW-SULFUR NATURAL GAS ONLY. 0.1 LB/H

BACTPSD 

OK-0044 8/16/2001 AUXILIARY BOILERS, (2)

NATURAL GAS 48 MMBTU/H SO2

USE OF PIPELINE NATURAL GAS W/SULFUR CONTENT 2 GRAINS SULFUR/100 SCF 0.57 LB/H

BACTPSD 

KY-0068 5/29/1997 BOILER (NATURAL GAS)

NATURAL GAS 96 MMBTU/H SO2

THE SULFUR CONTENT OF NO.2 FUEL SHALL NOT EXCEED 0.3%. 0.3 LB/MMBTU

BACTPSD 

SC-0041 8/14/1996 BOILERS, (2)

NATURAL GAS 95 MMBTU/H SO2

USE OF NATURAL GAS AS PRIMARY FUEL, AND <= 0.5% SULFUR FUEL AS BACK UP 0.5 LB/MMBTU

BACTPSD 

IA-0054 5/20/1997 BOILER #1

NATURAL GAS 2.3 MMBTU/H SO2

SO2 LIMITS SET TO STAY BELOW PSD SIGNIFICANCE 9.46 T/YR

Other Case-byCase 

KY-0087 7/12/2002 BOILER, NATURAL GAS, #4

NATURAL GAS 33.5 MMBTU/H SO2

CLEAN FUEL: FUEL OIL LIMITED TO < 0.5% S BY WT 1.057 LB/MMBTU

BACTPSD 

*AK-0062 8/19/2005 NATCO TEG REBOILER

NATURAL GAS 1.34 MMBtu/hr SO2

LIMIT SULFUR CONTENT OF FUEL COMBUSTED 250 PPMV

BACTPSD 

AK-0038 2/5/1999 GLYCOL REBOILER, UNIT 13

NATURAL GAS 5 MMBTU/H SO2

HYDROGEN SULFIDE CONTENT OF NATURAL GAS FUEL SHALL NOT EXCEED 50 PPMV. 500 PPM

Other Case-byCase 

AK-0038 2/5/1999 RIG BOILER (NATURAL GAS), UNIT 206, 207

NATURAL GAS 6.3 MMBTU/H SO2

HYDROGEN SULFIDE CONTENT OF NATURAL GAS FUEL SHALL NOT EXCEED 50 PPMV 500 PPM

Other Case-byCase 

PA-0210 12/14/2001 BOILER, (2)

NATURAL GAS 33.5 MMBTU/H SO2 LOW SULFUR FUEL 4 LB/MMBTU N/A 

TX-0389 12/31/2002 BACK-UP BOILER

NATURAL GAS 13.4 MMBUT/H SO2 0.01 LB/H

Other Case-byCase 

OH-0276 4/14/2003

BOILER FOR VACUUM OXYGEN DEGASSER VESSEL

NATURAL GAS 25 MMBTU/H SO2 0.01 LB/H 

VA-0243 12/1/2002 BOILER, NAT GAS & OIL

NATURAL GAS 26.5 MMBTU/H SO2 EMISSION LIMITS IN T/YR ONLY 16 T/YR

Other Case-byCase

*WA-0292 10/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H SO2 0.07 LB/H

BACTPSD 

OK-0043 10/22/2001 AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H SO2 USE OF NATURAL GAS 150 PPM

BACTPSD

AL-0181 10/23/2001 31.4 MMBTU/HR NATURAL GAS FIRED BOILER

NATURAL GAS 31.4 MMBTU/H SO2 NATURAL GAS IS EXCLUSIVE FUEL. 0.0057 LB/MMBTU

BACTPSD 

AR-0051 4/1/2002 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H SO2 FUELS LIMIT: < 2 GR/100 DSCF

BACTPSD

AL-0180 12/11/2001

35 MMBTU/HR NAT. GAS FIRED AUXILIARY BOILER

NATURAL GAS 35 MMBTU/H SO2 NATURAL GAS 0.0057 LB/MMBTU

BACTPSD 

MN-0053 7/15/2004 BOILER, NATURAL GAS (1)

NATURAL GAS 40 MMBTU/H SO2

LOW SULFUR FUEL 0.8 GR/SCF, CALENDAR YEAR AVERAGE

BACTPSD

VA-0271 3/24/2003 BOILER NO. 3

NAT GAS OR DIS OIL 43.2 MMBTU SO2

CONTINUOUS EMISSION MONITORING SYSTEM AND GOOD COMBUSTION PRACTICES. 4.76 T/YR N/A

WI-0226 8/27/2004 NATURAL GAS FIRED BOILER

NATURAL GAS 46.2 MMBTU/H SO2 NATURAL GAS FUEL ONLY 0.05 LB/H N/A

NV-0037 5/14/2004 AUXILIARY BOILER

NATURAL GAS 60 MMBTU/H SO2

USE OF LOW-SULFUR NATURAL GAS 0.04 LB/H

BACTPSD

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Em

Li

NJ-0046 3/7/1996

BOILERS 4&5, COMBUSTION CONTROLS, OXYGEN TRIM, ETC

NATURAL GAS 94 MMBTU/H SO2 0 LB/H

BACTPSD

AK-0053 3/21/2000 LISTER BOILER, DR11 100 HP SO2

USE ONLY FUEL GAS WITH A HYDROGEN SULFIDE CONTENT NOT TO EXCEED 200 PPM, AND USE ONLY DISTILLATE FUEL OIL WITH A SULFUR CONTENT NOT TO EXCEED 0.15% 500 PPM N/A

AK-0053 3/21/2000 LISTER BOILER, DR12 100 HP SO2

USE ONLY FUEL GAS WITH A H2S CONTENT NOT TO EXCEED 200 PPM, AND USE ONLY DISTILLATE FUEL OIL WITH A S CONTENT NOT TO EXCEED 0.15% 500 PPM N/A

TX-0363 11/13/2000 BOILER NO. 2 NAT GAS SO2 NONE INDICATED 0.04 LB/H

Case-byCase 

TX-0363 11/13/2000 BOILER NO 3 NAT GAS SO2 NONE INDICATED 0.03 LB/H N/A TX-0300 10/13/1998 GLYCOL REBOILER NAT GAS SO2

FUEL IS LIMITED TO PIPELINEQUALITY, SWEET NATURAL GAS CONTAINING NO MORE THAN 5 GR S/100 DSCF 0.01 LB/H

Other Case-byCase 

OK-0074 5/1/2001 AUXILIARY BOILER

NATURAL GAS 27.5 MMBTU/H SO2

USE OF NATURAL GAS WITH LOW SULFUR CONTENT 2

GR/100 SCF

BACTPSD

BACT-PSD SO2 lb/MMBtu Emission Limits

MIN 0.0006 lb/MMBtu MIN 

MAX 1.28 lb/MMBtu MAX 

MEDIAN 0.0025 lb/MMBtu MEDIAN 

COUNT 44 CASES COUNT 

RBLC SO2 BACT Limits Summary

Other (non-BA

Emiss

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

Emission 

Limit Unit 2

STD 

Emissio

Limit

*AK-0062 8/19/2005 NATCO TEG REBOILER

NATURAL GAS 1.34 MMBtu/hr NOx

CONVENTIONAL BURNER TECHNOLOGY 0.08 LB/MMBTU

BACTPSD 0.0

OH-0252 12/28/2004 BOILERS (2)

NATURAL GAS 30.6 MMBTU/H NOx 1.07 LB/H

BACTPSD 1.6

T/ROLLING 12-MONTHS 0.03

AZ-0047 12/1/2004 AUXILIARY BOILER

NATURAL GAS 38 MMBTU/H NOx LOW NOX BURNERS 0.37 LB/MMBTU

BACTPSD 0.3

AL-0212 11/22/2004 BOILER, NATURAL GAS (2)

NATURAL GAS 24.5 mmbtu/h NOx LOW NOX BURNERS 0.35 LB/MMBTU

BACTPSD 0.3

WI-0227 10/13/2004

NATURAL GAS FIRED AUXILLIARY BOILER

NATURAL GAS 97.1 MMBTU/H NOx

NATURAL GAS FUEL, COMBUSTION OPTIMIZATION (BASED ON CAPACITY FACTOR DURING OZONE SEASON EXCEEDING 20%) 13.7 LB/H N/A 0.14

WI-0226 8/27/2004 NATURAL GAS FIRED BOILER

NATURAL GAS 46.2 MMBTU/H NOx

BURNER DESIGN, NATURAL GAS FUELED 1.67 LB/H N/A 0.03

AR-0077 7/22/2004 BOILERS

NATURAL GAS 22 MMBTU/H NOx LOW NOX BURNERS 0.08 LB/MMBTU

BACTPSD 0.0

MN-0053 7/15/2004 BOILER, NATURAL GAS (1)

NATURAL GAS 40 MMBTU/H NOx LOW NOX BURNER; FGR. 0.04 LB/MMBTU

BACTPSD 0.0

*NE-0023 6/22/2004 AUXILIARY BOILER (OIL)

NATURAL GAS 73.3 MMBTU/H NOx

OPERATION LIMITED TO 500 HOURS PER YEAR. 0.1 LB/MMBTU

BACTPSD 0

WV-0021 6/9/2004

BOILER, NATURAL GAS, 39.00 MMBTU

NATURAL GAS 365 MMSCF/YR NOx

LOW-NOX BURNERS/FLUEGAS RECIRCULATION 2.08 PPH BACT- PSD 9.13 T/YR 0.0

NV-0037 5/14/2004 AUXILIARY BOILER

NATURAL GAS 60 MMBTU/H NOx

LOW NOX BURNER (WITH EITHER INTERNAL OR EXTERNAL FLUE GAS RECIRCULATION) 0.035 LB/MMBTU

BACTPSD 9.6 TONS/YR 0.03

ID-0015 4/5/2004 BOILER, 64 MMBTU/H

NATURAL GAS 64 MMBTU/H NOx LOW-NOX BURNER 2.88 LB/H RACT 12.63 T/YR 0.04

AL-0191 3/23/2004 BOILERS, NATURAL GAS, (3)

NATURAL GAS 50 MMBTU/H NOx

NATURAL GAS ONLY; LOW NOX BURNERS 1.75 LB/H

BACTPSD 0.035 LB/MMBTU 0.03

AR-0076 2/17/2004

BOILER, HOT WATER, (2) SNPBCDF-05, -06 NATURAL GAS 0.01 MMDSCF/H NOx

LOW-NOX BURNERS WITHOUT FLUE GAS RECIRCULATION. 0.6 LB/H

BACTPSD 0.05

AR-0076 2/17/2004

BOILER, PROCESS STEAM, (2) SN-PBCDF-03, -04

NATURAL GAS 0.03 MMDSCF/H NOx

LOW-NOX BURNERS WITHOUT FLUE GAS RECIRCULATION. 1.5 LB/H

BACTPSD 0.052

AR-0076 2/17/2004

BOILER, LABORATORY SNPBCDF-16 NATURAL GAS 1.4 mmbtu/h NOx

LOW-NOX BURNERS WITHOUT FLUE GAS RECIRCULATION. 0.2 LB/H

BACTPSD 0.14

WI-0207 1/21/2004

BOILER, S52/B52, 11 MMBTU/H

NATURAL GAS 11 MMBTU/H NOx

NATURAL GAS / PROPANE; LOW NOX BURNER 0.04 LB/MMBTU

BACTPSD 0.0

WI-0207 1/21/2004

BOILER, S53 / B53, 34 MMBTU/H

NATURAL GAS 34 MMBTU/H NOx

NATURAL GAS / PROPANE; LOW NOX BURNER 0.04 LB/MMBTU

BACTPSD 0.0

WI-0207 1/21/2004

BOILER, S50/B50, 60 MMBTU/H

NATURAL GAS 60 MMBTU/H NOx LOW NOX BURNER 0.04 LB/MMBTU

BACTPSD 0.0

WI-0207 1/21/2004

BOILER, S51/B51, 80 MMBTU/H

NATURAL GAS 80 MMBTU/H NOx

NAT. GAS / PROPANE, LOW NOX BURNER 0.04 LB/MMBTU

BACTPSD 0.0

OR-0039 12/30/2003

BOILERS, AUXILIARY, NATURAL GAS, (2)

NATURAL GAS 80 MMBTU/H NOx

LOW NOX BURNERS AND FLUE GAS RECIRCULATION 0.035 LB/MMBTU

BACTPSD 0.03

MN-0054 12/4/2003 BOILER, COMMERCIAL

NATURAL GAS 70 MMBTU/H NOx

DRY LOW NOX AND FLUE GAS RECIRCULATION 0.036 LB/MMBTU 0.03

IN-0108 11/21/2003 BOILER, NATURAL GAS, (2)

NATURAL GAS 34 MMBTU/H NOx

LOW NOX BURNERS, NATURAL GAS 0.035 LB/MMBTU

BACTPSD 0.03

MI-0355 9/16/2003 BOILER, GAS-FIRED

NATURAL GAS 98.51 MMBTU/H NOx

LOW NOX BURNERS AND FLUE GAS RECIRCULATION. 0.08 LB/MMBTU

BACTPSD 0.0

*AZ-0049 9/4/2003

AUXILIARY BOILER FOR GE TURBINE

NATURAL GAS 41 MMBTU/H NOx LOW NOX BURNERS 0.027 LB/MMBTU

BACTPSD 0.02

*AZ-0049 9/4/2003

AUXILIARY BOILER FOR SIEMENS TURBINES

NATURAL GAS 55.34 MMBTU/H NOx LOW NOX BURNERS 0.036 LB/MMBTU

BACTPSD 0.03

OH-0254 8/14/2003 BOILER

NATURAL GAS 30.6 MMBTU/H NOx 1.08 LB/H

BACTPSD 2.3

T/ROLLING 12-MONTHS 0.03

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

Emission 

Limit Unit 2

STD 

Emissio

Limit

OH-0276 4/14/2003

BOILER FOR VACUUM OXYGEN DEGASSER VESSEL

NATURAL GAS 25 MMBTU/H NOx LOW NOX BURNER 2.45 LB/H

BACTPSD 10.7 T/YR

WA-0316 3/27/2003 BOILER, NATURAL GAS

NATURAL GAS 4.19 MMBTU/H NOx

GOOD COMBUSTION PRACTICE 34

PPMDV @ 3% O2

BACTPSD 4 LB/D 0.0

GA-0098 3/24/2003 AUXILIARY BOILER

NATURAL GAS 83 MMBTU/H NOx 0.055 LB/MMBTU

Other Case-byCase 0.05

VA-0271 3/24/2003 BOILER NO. 1

NATURAL GAS 43.2 MMBTU/H NOx

FLUE GAS RECIRCULATION WITH LOW NOX BURNERS. CONTINUOUS EMISSION MONITORING SYSTEM. GOOD COMBUSTION PRACTICES. 6.17 LB/H

Other Case-byCase 0.

VA-0271 3/24/2003 BOILER NO. 3

NAT GAS OR DIS OIL 43.2 MMBTU NOx

FLUE GAS RECIRCULATION WITH LOW NOX BURNER. CONTINUOUS EMISSION MONITORING SYSTEM AND GOOD COMBUSTION PRACTICES. 40.31 T/YR

Other Case-byCase

OK-0090 3/21/2003 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H NOx LOW-NOX BURNERS 0.05 LB/MMBTU

BACTPSD 0.0

OR-0040 3/12/2003

BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 50000 LB/H NOx 30

PPMVD @ 3% O2

BACTPSD

TX-0364 1/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H NOx NONE INDICATED 0.29 LB/H

Other Case-byCase 1.07 T/YR 0.1

PA-0216 1/13/2003 BOILER, DRAP LINE

NATURAL GAS 33.5 MMBTU/H NOx ULTRA LOW NOX BURNER 30

PPM @ 3% O2

Other Case-byCase 0.0

WA-0291 1/3/2003 BOILER, AUXILIARY

NATURAL GAS 55.3 MMBTU/H NOx LNB PLUS FGR 30

PPMDV @ 3% O2

Other Case-byCase 12.7 LB/H 0.2

TX-0389 12/31/2002 BACK-UP BOILER

NATURAL GAS 13.4 MMBUT/H NOx 1.4 LB/H

Other Case-byCase 6.12 T/YR

IA-0062 12/20/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H NOx DLN 0.049 LB/MMBTU

Other Case-byCase 0.04

TX-0354 12/19/2002

(2) STEAM BOILERS, X-426A AND X-426B

NATURAL GAS 15.8 MMBTU/H NOx LOW NOX BURNERS 2.05 LB/H

Other Case-byCase 9 T/YR 0.

VA-0243 12/1/2002 BOILER, NAT GAS & OIL

NATURAL GAS 26.5 MMBTU/H NOx

EMISSION LIMITS IN T/YR ONLY 12.8 T/YR

Other Case-byCase

TX-0408 11/22/2002 AUXILIARY BOILER, (2)

NATURAL GAS 6 MMBTU/H NOx 0.59 LB/H

BACTPSD 2.58 T/YR 0.09

VA-0260 11/21/2002 AUXILIARY BOILER, (2)

NATURAL GAS 40 MMBTU/H NOx

LOW NOX BURNERS AND CLEAN FUEL. 3.2 LB/H

BACTPSD 4.8 T/YR 0.0

VA-0255 11/18/2002 BOILER, AUXILIARY

NATURAL GAS 99 MMBTU/H NOx

LOW NOX BURNERS AND LOW NOX FUEL. 0.036 LB/MMBTU

Other Case-byCase 18 T/YR 0.03

GA-0101 10/23/2002 BOILER, AUXILIARY

NATURAL GAS 31.4 MMBTU/H NOx

DRY LOW NOX BURNERS, FLUE GAS RECIRCULATION 30

PPM @ 3% O2

BACTPSD 0.03

AL-0192 10/18/2002 BOILERS, NATURAL GAS, (3)

NATURAL GAS 30 MMBTU/H NOx

LOW NOX BURNERS, CLEAN FUEL, GOOD COMBUSTION 1.05 LB/H

BACTPSD 0.035 LB/MMBTU 0.03

CA-1023 10/8/2002 BOILER, 39 MMBTU/H

NATURAL GAS 39 MMBTU/H NOx

ULTRA-LOW NOX BURNER WITH FGR 9

PPMVD @ 3% O2 N/A

OH-0248 9/24/2002 BOILER

NATURAL GAS 99 MMBTU/H NOx LOW NOX BURNERS 4.95 LB/H

BACTPSD 0.05 LB/MMBTU 0.0

VA-0261 9/6/2002 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H NOx

LOW NOX BURNERS AND GOOD COMBUSTION PRACTICES. 3.82 LB/H

BACTPSD 5.73 T/YR 0.0

*WA-0297 8/30/2002 BOILER

NATURAL GAS 4.19 MMBTU/H NOx

GOOD COMBUSTION PRACTICE 34

PPM @ 3% O2

BACTPSD 4 LB/D

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

Emission 

Limit Unit 2

STD 

Emissio

Limit

AR-0070 8/23/2002 AUXILIARY BOILER

NATURAL GAS 33 MMBTU/H NOx

LOW NOX OPTION (LOW NOX BURNER AND/OR FLUE GAS RECIRCULATION) 0.04 LB/MMBTU

BACTPSD 0.0

IA-0060 7/23/2002

AUXILIARY BOILER (48.5 MMBTU/H)

NATUAL GAS 48.69

MILLION CF/YR NOx GCP 0.034 LB/MMBTU

BACTPSD 0.03

AL-0185 7/12/2002

TWO (2) 40 MMBTU/H AUXILIARY BOILERS

NATURAL GAS 40 MMBTU/H NOx LOW NOX BURNERS 0.05 LB/MMBTU

BACTPSD 2 LB/H

TX-0437 7/5/2002 BOILERS, AUXILIARY

NATURAL GAS 40 mmbtu/h NOx

LOW NOX BURNERS, CLEAN FUEL. BOILER WILL OPERATE A MAXIMUM OF 3000 H/YR

BACTPSD

NM-0044 6/27/2002

AUXILIARY BOILERS (AUX-1 AND AUX-2)

NATURAL GAS 33 MMBTU/H NOx

CLEAN FUEL, GOOD COMBUSITON PRACTICE 1.2 LB/H

BACTPSD 0.03

OK-0070 6/13/2002 AUXILIARY BOILER

NATURAL GAS 33 MMBTU/H NOx LOW NOX BURNERS 0.035 LB/MMBTU

BACTPSD 0.03

OK-0072 5/6/2002 AUXILIARY BOILER

NATURAL GAS 93 MMBUT/H NOx LOW NOX BURNERS 0.075 LB/MMBTU

BACTPSD 0.07

IA-0058 4/10/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H NOx 0.05 LB/MMBTU

BACTPSD 16.4 T/YR 0.0

TN-0153 4/3/2002

CCR STABILIZATION REBOILER

NATURAL GAS 54 MMBTU/H NOx 0.06 LB/MMBTU

BACTPSD 0.0

TN-0153 4/3/2002 BOILER, NO. 9

NATURAL GAS 95 MMBTU/H NOx 0.084 LB/MMBTU

BACTPSD 0.08

AR-0051 4/1/2002 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H NOx 0.035 LB/MMBTU

BACTPSD 0.03

OK-0055 2/12/2002 AUXILIARY BOILER

NATURAL GAS 31 MMBTU/H NOx COMBUSTION CONTROL 0.01 LB/MMBTU

Other Case-byCase 0.0

OK-0056 2/12/2002 AUXILIARY BOILERS

NATURAL GAS 0 NOx

GOOD COMBUSTION PRACTICES AND DESIGN 0.1 LB/MMBTU

BACTPSD 0

LA-0174 1/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H NOx LOW-NOX BURNERS 61.34 LB/H

Other Case-byCase 40.47 T/YR 0

NC-0094 1/9/2002

BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 83 MMBTU/H NOx LOW NOX BURNERS 4.07 LB/H

BACTPSD 0.04

OH-0257 12/27/2001 AUXILIARY BOILER

NATURAL GAS 76 MMBTU/H NOx

LOW NOX BURNERS INSTALLED 6.69 LB/H

BACTPSD 10.03 T/YR 0.0

PA-0210 12/14/2001 BOILER, (2)

NATURAL GAS 33.5 MMBTU/H NOx LO-NOX BURNERS 30

PPMDV @ 3% O2 N/A 0.03

AL-0180 12/11/2001

35 MMBTU/HR NAT. GAS FIRED AUXILIARY BOILER

NATURAL GAS 35 MMBTU/H NOx LOW NOX BURNERS 0.108 LB/MMBTU

BACTPSD 3.77 LB/H

IN-0095 12/7/2001 AUXILLIARY BOILER

NATURAL GAS 21 MMBTU/H NOx LOW NOX BURNERS 0.049 LB/MMBTU

BACTPSD 0.04

OH-0251 11/29/2001 BOILER, NATURAL GAS

NATURAL GAS 91.2 MMBTU/H NOx

USE OF LOW-NOX BURNERS. 3.21 LB/H N/A 22.7 T/YR 0.035

TX-0378 11/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H NOx ULTRA LOW-NOX BURNERS 0.9 LB/H

Other Case-byCase 3.94 T/YR 0.0

OK-0071 10/25/2001 AUXILIARY BOILER

NATURAL GAS 22 MMBTU/H NOx

NATURAL GAS FUEL AND GOOD COMBUSTION CONTROL 0.036 LB/MMBTU

BACTPSD 0.03

*WA-0292 10/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H NOx

FGR AND LOW-NOX BURNERS 1.03 LB/H

BACTPSD 30 PPM @ 3% O2

AL-0181 10/23/2001

31.4 MMBTU/HR NATURAL GAS FIRED BOILER

NATURAL GAS 31.4 MMBTU/H NOx LOW NOX BURNERS 0.108 LB/MMBTU

BACTPSD 3.77 LB/H

OK-0043 10/22/2001 AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H NOx LOW NOX BURNERS 0.05 LB/MMBTU

BACTPSD 0.0

OH-0265 10/16/2001 BOILER, NATURAL GAS

NATURAL GAS 49 MMBTU/H NOx 4.9 LB/H

BACTPSD 1.96 T/YR 0

IN-0110 10/5/2001

BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 35 MMBTU/H NOx

CLEAN FUEL, LOW NOX BURNERS 0.08 LB/MMBTU

BACTPSD 2.8 LB/H 0.0

AL-0179 10/3/2001

30 MMBTU/HR AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H NOx LOW NOX COMBUSTION 0.096 LB/MMBTU

BACTPSD 2.9 LB/H 0.09

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

Emission 

Limit Unit 2

STD 

Emissio

Limit

MD-0033 9/27/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H NOx

EXCLUSIVE USE OF NATURAL GAS, ADVANCED DRY LOW-NOX BURNERS; GOOD COMBUSTION CONTROLS HEAT INPUT TO THE AUXILIARY BOILERS (2) SHALL BE LIMITED TO 210,240 MMBTU FOR ANY CONSECUTIVE 12-MONTH PERIOD LAER

CA-1099 9/4/2001

BOILER: 5 TO < 33.5 MMBTU/HR

NATURAL GAS 21.46 MMBTU/H NOx ULTRA LOW-NOX BURNER 9

PPMD @ 3% O2

BACTPSD

WV-0013 8/30/2001 BOILER

NATURAL GAS 54.4 MMBTU/H NOx

LOW NOX BURNERS AND FLUE-GAS RECIRCULATION 0.035 LB/MMBTU

BACTPSD 0.03

WV-0013 8/30/2001 BOILERS, 3

NATURAL GAS 65.78 MMBTU/H NOx

LOW-NOX BURNERS AND FLUE-GAS RECIRCULATION 0.035 LB/MMBTU

BACTPSD 0.03

OK-0054 8/21/2001 BOILERS

NATURAL GAS 62.77 MMBTU/H NOx LOW NOX BURNERS 0.035 LB/MMBTU

BACTPSD 2.48 LB/H 0.03

OK-0044 8/16/2001 AUXILIARY BOILERS, (2)

NATURAL GAS 48 MMBTU/H NOx

DRY LOW NOX BURNERS, OPERATES IN PRE-MIX MODE. 9.41 LB/H

BACTPSD 41.22 T/YR 0

OH-0263 8/9/2001 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H NOx LOW NOX BURNERS 2.72 LB/H

BACTPSD 11.9 T/YR 0.03

IN-0087 6/6/2001

AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 46 MMBTU/H NOx

GOOD COMBUSTION. LOW NOX BURNERS. LIMIT IS FOR EACH BOILER. 0.049 LB/MMBTU

BACTPSD 2.28 LB/H 0.04

NV-0039 6/1/2001 AUXILIARY BOILERS

NATURAL GAS 44.1 MMBTU/H NOx

GOOD COMBUSTION CONTROL 30

PPMVD@3% O2

BACTPSD 5.2 LB/H 0.1

OK-0046 5/17/2001 AUXILIARY BOILER

NATURAL GAS 20 MMBTU/H NOx LOW NOX BURNERS 0.049 LB/MMBTU

BACTPSD 0.04

IN-0086 5/9/2001

AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 35 MMBTU/H NOx

LOW NOX BURNERS. GOOD COMBUSTION. NATURAL GAS. LB/H LIMIT IS FOR EACH BOILER. 0.049 LB/MMBTU

BACTPSD 1.72 LB/H 0.04

OK-0074 5/1/2001 AUXILIARY BOILER

NATURAL GAS 27.5 MMBTU/H NOx LOW NOX BURNERS 0.1 LB/MMBTU

BACTPSD 0

MS-0045 4/2/2001 BOILER

NATURAL GAS 35 MMBTU NOx LOW NOX BURNERS 0.12 LB/MMBTU

BACTPSD 0.

OH-0255 3/29/2001 BOILER, NATURAL GAS

NATURAL GAS 85.2 MMBTU/H NOx 3.07 LB/H

BACTPSD 13.4 T/YR 0.03

OH-0258 2/15/2001 BOILERS (4)

NATURAL GAS 20.9 MMBTU/H NOx LOW NOX BURNERS. 0.69 LB/H N/A 3.02 T/YR 0.03

AL-0169 2/5/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H NOx LOW NOX BURNERS 0.08 LB/MMBTU

BACTPSD 3.2 LB/H 0.0

AL-0168 1/12/2001 BOILER

NATURAL GAS 83 MMBTU/H NOx LOW NOX BURNERS 0.05 LB/MMBTU

BACTPSD 4.18 LB/H 0.0

AL-0178 1/5/2001

TWO (2) 11.7 MMBTU/H BOILERS

NATURAL GAS 11.7 MMBTU/H NOx LOW NOX BURNERS 0.036 LB/MMBTU

BACTPSD 0.53 LB/H

AL-0178 1/5/2001

TWO (2) 13.4 MMBTU/H BOILERS

NATURAL GAS 13.4 MMBTU/H NOx LOW NOX BURNERS 0.036 LB/MMBTU

BACTPSD 0.75 LB/H

NM-0042 12/29/2000 AUX-1 AUXILARY BOILER

NATURAL GAS 44.1 MMBTU/H NOx

DRY LOW NOX BURNERS, NATURAL GAS COMBUSTION, AND GOOD ENGINEERING PRACTICE. 1.5 LB/H

BACTPSD 0.0

AR-0040 12/29/2000 BOILERS, AUXILIARY 2

NATURAL GAS 44.1 MMBTU/H NOx

LOW NOX COMBUSTER & PROPER OPERATION. LB/HR LIMIT FOR EACH BOILER. 0.12 LB/MMBTU

BACTPSD 5.3 LB/H 0.

TX-0363 11/13/2000 BOILER NO. 2 NAT GAS NOx NONE INDICATED 3.4 LB/H

Other Case-byCase 7.45 T/YR

TX-0363 11/13/2000 BOILER NO 3 NAT GAS NOx NONE INDICATED 2.29 LB/H

Other Case-byCase 10.01 T/YR

WI-0181 8/2/2000 BOILER

NATURAL GAS 10 MMBTU/H NOx

NATURAL GAS FUEL, LOW -NOX BURNER(LNB`S) AND FLU GAS RECIRCULATION (FGR). 30

PPMVD AT 3% OXYGEN

BACTPSD 0.035 LB/MMBTU 0.03

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

Emission 

Limit Unit 2

STD 

Emissio

Limit

WY-0056 7/25/2000

BOILER (AUXILLARY), TRAIN III

NATURAL GAS 76.7 MMBTU/H NOx LOW NOX BURNER 9.5 T/YR

BACTPSD 9.2 LB/HR 0.

CA-0946 7/12/2000 BOILER

NATURAL GAS 21 MMBTU/H NOx

SELECTIVE CATALYTIC REDUCTION 7 PPMVD LAER 0.00

CA-1100 7/12/2000

BOILER: 5 TO < 33.5 MMBTU/HR

NATURAL GAS 21 MMBTU/H NOx SCR 7

PPMVD@3% O2

BACTPSD

MA-0027 5/7/2000 AUXILIARY BOILER

NATURAL GAS 26.6 MMBTU/H NOx

SCR, DRY LOW NOX COMBUSTOR 1.1 LB/H LAER 0.0

CA-1020 5/1/2000 BOILER 4.2 MMBTU/H

NATURAL GAS 4.2 MMBTU/H NOx

SCONOX CATALYTIC ABSORPTION SYSTEM 2

PPMVD @ 3% O2

BACTPSD

CA-0943 4/6/2000 BOILER

NATURAL GAS 6.3 MMBTU/H NOx

LOW NOX BURNERS AND FLUE GAS RECIRCULATION 12 PPMVD LAER 0.0

TX-0274 4/3/2000 AUXILIARY BOILER

NATURAL GAS 54.01 MMBTU/H NOx NONE INDICATED 5.4 LB/H

BACTPSD 0.47 T/YR 0

CA-0945 3/17/2000 BOILER

NATURAL GAS 16.3 MMBTU/H NOx ULTRA LOW NOX BURNER 12

PPM @ 3% O2 LAER 127 LB/MO 0.0

CA-1005 3/16/2000 BOILER, 5.05 MMBTU/H

NATURAL GAS 5.05 MMBTU/H NOx

LOW NOX BURNER AND FLUE GAS RECIRCULATION 20

PPMV @ 3% O2

BACTPSD 0.0

CA-0940 3/15/2000 BOILER, PORTABLE

NATURAL GAS 28.8 MMBTU/H NOx 9 PPMVD LAER 0.0

CA-0947 3/15/2000 BOILER

NATURAL GAS 7.5 MMBTU/H NOx LOW NOX BURNERS 12 PPMVD LAER 0.0

CA-0944 3/10/2000 BOILER

NATURAL GAS 16.3 MMBTU/H NOx

LOW NOX BURNERS AND FLUE GAS RECIRCULATION 12 PPMVD LAER 0.0

AL-0142 2/29/2000

BOILERS, NATURAL GAS FIRED

NATURAL GAS 10 MMBTU/H NOx

NATURAL GAS FUEL ONLY, LOW NOX BURNERS 0.35 LB/H

BACTPSD 0.035 LB/MMBTU 0.03

PA-0165 2/24/2000 BOILERS, (3)

NATURAL GAS 90 MMBTU/H NOx LOW NOX BURNERS 0.1 LB/MMBTU

BACTPSD 0

CA-0942 2/15/2000 BOILER, NATURAL GAS

NATURAL GAS 6 MMBTU/H NOx LOW NOX BURNERS 12 PPMVD LAER 0.0

CA-0941 1/28/2000 BOILER, NATURAL GAS

NATURAL GAS 16.3 MMBTU/H NOx

LOW NOX BURNERS AND FLUE GAS RECIRCULATION 15 PPMVD LAER 0.0

OK-0041 1/19/2000 AUXILIARY BOILER

NATURAL GAS 22 MMBTU/H NOx COMBUSTION CONTROL 0.035 LB/MMBTU

BACTPSD 0.03

CA-1006 12/16/1999 BOILER, 20.9 MMBTU/H

NATURAL GAS 20.9 MMBTU/H NOx LOW NOX BURNER 9

PPMVD@3%O2

BACTPSD 0.0

CA-0939 12/16/1999 BOILER

NATURAL GAS 20.9 MMBTU/H NOx LOW NOX BURNERS 9 PPMVD LAER 0.0

CA-1021 12/7/1999 BOILER: 16.5 MMBTU/H

NATURAL GAS 16.5 MMBTU/H NOx

SELCTIVE CATALYTIC REDUTION, AMMONIA SLIP 5 PPMVD @ 3%O2 7

PPMVD@3% O2

BACTPSD

CA-0938 12/2/1999 BOILER, (3)

NATURAL GAS 33.9 MMBTU/H NOx

HONEYCOMB TYPE CATALYST BED WITH ANHYDROUS AMMONIA INJECTION GRID (SCR) 7 PPMVD LAER 0.008

CA-0918 12/2/1999

CLAYTON WATER-TUBE BOILER

NATURAL GAS 4.29 MMBTU/H NOx

ULTRA LOW-NOX BURNER SYSTEM 12

PPMVD @ 3% O2

BACTPSD 0.0

CA-0919 11/23/1999 BOILER, FIRE TUBE

NATURAL GAS 31.5 MMBTU/H NOx

COEN LOW-NOX BURNER, PEERLESS MFG. COMPANY SELECTIVE CATALYTIC REDUCTION SYSTEM WITH NH3 INJECTION 7

PPMVD @ 3% O2

BACTPSD 0.008

OK-0051 10/1/1999 AUXILIARY BOILER

NATURAL GAS NOx LOW NOX BURNERS 0.049 LB/MMBTU

BACTPSD 0.04

MA-0029 9/29/1999 BOILER, AUXILIARY

NATURAL GAS 96 MMBTU/H NOx SCR 3.4 LB/H

BACTPSD 0.03

CA-0948 9/9/1999 BOILER, (2)

NATURAL GAS 8.18 MMBTU/H NOx LOW NOX BURNERS 15 PPMVD LAER 0.0

CO-0041 5/6/1999

BOILER NO.2, TEST MINE HOT WATER (1)

NATURAL GAS 51.08 MMBTU NOx

LOW NOX COMBUSTION SYSTEM. NO ADD-ON COSTS. COSTS PART OF OPERATION. 0.05 LB/MMBTU

BACTPSD 0.0

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

Emission 

Limit Unit 2

STD 

Emissio

Limit

CO-0040 5/6/1999

INDUSTRIAL BOILER, NATURAL GAS

NATURAL GAS 80.8 MMBTU/H NOx

LOW NOX COMBUSTION SYSTEM. CAPITAL COSTS ARE INCLUDED IN EQUIPMENT COSTS; ANNUALIZED COSTS ARE INCLUDED IN OPERATION AND MAINTENANCE 0.05 LB/MMBTU

BACTPSD 0.0

NJ-0042 2/5/1999 BOILER 1 (NATURAL GAS)

NATURAL GAS 84.4 MMBTU/H NOx 33.8 LB/H

BACTPSD 0.4 LB/MMBTU 0

MS-0041 10/27/1998 BOILER, NATURAL GAS

NATURAL GAS 99 MMBTU/H NOx

LOW NOX BURNER AND FLUE GAS RECIRCULATION. EMISSION LIMIT BASIS IS PSD AND NSPS. 0.042 LB/MMBTU

BACTPSD 0.04

TX-0300 10/13/1998 GLYCOL REBOILER NAT GAS NOx NONE INDICATED 0.55 LB/H

Other Case-byCase 2.41 T/YR

IN-0104 8/14/1998

BOILERS, REFINERY & HYDROGEN PLANT REFORMER

NATURAL GAS 10 MMBTU/H NOx

LOW NOX BURNERS AND FLUE GAS RECIRCULATION 0.0365 LB/MMBTU

BACTPSD 0.036

ND-0018 7/9/1998

BOILER, NEBRASKA, NAT GAS

NATURAL GAS 28 MMBTU/H NOx 5.8 LB/H

BACTPSD 0.2

IA-0048 6/1/1998 BOILER, BACKUP 77 MMBTU/H NOx 13.6 LB/H

Other Case-byCase 0.

WY-0042 4/3/1998

BOILER, AUXILIARY, NATURAL GAS 22.89 MMBTU/H NOx 2.3 LB/H

Other Case-byCase 0 

*LA-0112 2/13/1998 BOILER NO. 1

NATURAL GAS 95 MMBTU/H NOx LOW NOX BURNERS 4.75 LB/H

BACTPSD 20.81 T/YR 0.0

WY-0034 2/6/1998 BOILER, NATURAL GAS

NATURAL GAS 100 MMBTU/H NOx

LOW NOX" BURNER SYSTEM" 0.038 LB/MMBTU LAER 0 

PA-0149 11/26/1997 HEAT RECOVERY BOILER

NG SUPPLEMENT 24000

LB/HR STEAM NOx 0.1 LB/MMBTU

Other Case-byCase 5.03 LB/HR 0

AL-0140 6/19/1997

BOILER, NATURAL GAS FIRED, 2

NATURAL GAS 11.7 MMBTU/H NOx

CLEAN FUEL, LOW NOX BRUNERS 0.03 LB/MMBTU

BACTPSD 0.7 LB/H 0.0

AL-0139 6/19/1997

BOILER, NATURAL GAS FIRED, 2

NATURAL GAS 13.4 MMBTU/H NOx

LOW NOX BURNERS, CLEAN FUEL 0.03 LB/MMBTU

BACTPSD 0.8 LB/H 0.0

KY-0068 5/29/1997 BOILER (NATURAL GAS)

NATURAL GAS 96 MMBTU/H NOx N/A 0.1 LB/MMBTU

BACTPSD 0

IA-0054 5/20/1997 BOILER #2 B2

NATURAL GAS 2.3 MMBTU/H NOx

LOW NOX BURNER FLUE GAS RECIRC. ADDITIONAL EMISSION LIMIT: 70 PPM 6.8 LB/H

BACTPSD 11.79 T/YR 

IA-0054 5/20/1997 BOILER #1

NATURAL GAS 2.3 MMBTU/H NOx

LOW NOX BURNER, FLUE GAS RECIRC. 6.81 LB/H

BACTPSD 11.79 T/YR 

IA-0054 5/20/1997 BOILER #3 B3

NATURAL GAS 2.3 MMBTU/HR NOx

LOW NOX BURNER, FLUE GAS RECIRC. ADDITIONAL EMISSION LIMIT: 70 PPM 6.81 LB/H

BACTPSD 11.79 T/YR 

IA-0054 5/20/1997 HIGH PRESSURE BOILER #1

NATURAL GAS 0.3 MMBTU/H NOx

ADDITIONAL EMISSION 

LIMIT: 130 PPM 1.66 LB/H

BACTPSD 5.96 T/YR 5

AR-0019 3/4/1997

BOILER, COGENERATION/WASTE HEAT RECOVERY

NATURAL GAS 68 MMBTU/H NOx LOW NOX COMBUSTORS 25

PPM @ 15% O2

BACTPSD 0 

IN-0100 2/13/1997

BOILERS (2), NATURAL GAS FIRED, BH NO. 2

NATURAL GAS 76 MMBTU/H NOx LOW NOX BURNERS 6.08 LB/H

BACTPSD 0.0

IN-0100 2/13/1997

BOILERS (3), NATURAL GAS FIRED, BH NO. 1

NATURAL GAS 76 MMBTU/H NOx LOW NOX BURNERS 9.12 LB/H

BACTPSD 0.0

CA-0802 1/27/1997

PVI INDUSTRIES MODEL 3500 BOILER

NATURAL GAS 2.8 MMBTU/HR NOx

OPERATION LIMITED TO 80% UTILIZATION. RECORDKEEPING REQUIRED FOR COMPLIANCE VERIFICATION 0

NO NUMERIC LIMIT LAER 0 

CA-0775 1/15/1997

CLAYTON INDUSTRIES MODEL SEG-204-2-LNB BOILER

NATURAL GAS 8.1 MMBTU/HR NOx

PREMIXED LEAN BURN COMBUSTION TECHNOLOGY 0.012 MMBTU/HR LAER 0 

NJ-0045 1/14/1997 BOILERS - NAT GAS (3)

NATURAL GAS 99.5 MMBTU/H NOx ULTRA LOW-NOX BURNERS 1.1 LB/H

Other Case-byCase 0.011 LB/MMBTU 0.0

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible 

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

Emission 

Limit 2

Emission 

Limit Unit 2

STD 

Emissio

Limit

CA-0790 12/30/1996

NEBRASKA BOILER, MODEL NS-B-40

NATURAL GAS 31.2 MMBTU/HR NOx

LOW-NOX BURNER, FLUE GAS RECIRCULATION (FGR) 0.036 LB/MMBTU LAER 0.052 LB/MMBTU 0.03

IN-0073 10/31/1996

BOILERS, NATURAL GASFIRED 67.5 MMBTU/H NOx 81 LB/MMCF BACT- PSD 0 

CA-0722 10/24/1996 TWO HOT-WATER BOILERS

PROPANE (LPG) 8.4

MMBTU/HR/UNIT NOx

LOW EMISSIONS FLAMELESS BURNER 15

PPMVD AT 3% OXYGEN

Other Case-byCase 0.15 LB/HR/UNIT 

CA-0736 9/19/1996

300 HP BOILER USED AS A BACKUP

PUC QUALITY NAT GAS 10 MMBTU/HR NOx NO CONTROL 0.106 LB/MMBTU LAER 25 LB/DAY 0.10

AZ-0032 9/1/1996 BOILERS (10) 54 MMBTU NOx

LOW NOX BURNERS < 50 PPM NOX 49 TPY

Other Case-byCase 0 

SC-0041 8/14/1996 BOILERS, (2)

NATURAL GAS 95 MMBTU/H NOx

LOW NOX BURNER AND FLUE GAS RECIRCULATION 24

LB/H EA. BOILER

BACTPSD 0 

IN-0069 8/9/1996

BOILERS, NATURAL GAS FIRED (6)

NATURAL GAS 58 MMBTU/H NOx

LOW NOX BURNERS & FUEL SPEC: USE OF NATURAL GAS AS FUEL 0.1 LB/MMBTU

BACTPSD 0 0

GA-0063 4/3/1996 BOILER, NATURAL GAS

NATURAL GAS 60 MMBTU/H NOx

DRY LOW NOX BURNER WITH FGR 0.1 LB/MMBTU

BACTPSD 0 0

NJ-0046 3/7/1996

BOILERS 4&5, COMBUSTION CONTROLS, OXYGEN TRIM, ETC

NATURAL GAS 94 MMBTU/H NOx LOW NOX BURNER 4.76 LB/H

BACTPSD 0.050

AZ-0028 2/1/1996 BOILER, GAS-FIRED

NATURAL GAS 42 MMBTU/HR NOx

FLUE GAS RECIRCULATION (FGR) NOX NOT TO EXCEED 30 PPM 49 TPY

BACTPSD 0 

IN-0068 1/19/1996 BOILERS, NATURAL GAS

NATURAL GAS 93.9 MMBTU/H NOx LOW-NOX BURNER 6.94 LB/H

BACTPSD 0 0.0

BACT-PSD NOx 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 Summary

Other (non-BACT) NOx lb/MMBtu Emission Limits

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 

Unit

Case-bycase 

basis

Emission 

Limit 2

Emi

Limit 

WY-0035 10/13/1997 BOILER, NATURAL GAS NATURAL GAS 431.6 MMBTU/H NOx LOW NOX" BURNERS WITH 16% FLUE GAS RECIRCULATION" 0.05 LB/MMBTU BACT-PSD 21.58 LB/H 

AZ-0046 4/14/2005 ATMOSPHERIC CRUDE CHARGE HEATER

NATURAL GAS OR REFINERY FUEL GAS

346 MMBTU/H NOx

LOW NOX BURNERS AND SELECTIVE CATALYTIC REDUCTION

0.0125 LB/MMBTU BACT-PSD 

AZ-0046 4/14/2005

BUTANE CONVERSION UNIT DEHYDROGENATION REACTOR CHARGE HEATER

REFINERY FUEL GAS OR NATURAL GAS

311 MMBTU/H NOx

LOW NOX BURNERS AND SELECTIVE CATALYTIC REDUCTION

0.0125 LB/MMBTU BACT-PSD 

AZ-0046 4/14/2005

BUTANE CONVERSION UNIT DEHYDROGENATION REACTOR INTERHEATER

REFINERY FULE GAS OR NATURAL GAS

328 MMBTU/H NOx

LOW NOX BURNERS AND SELECTIVE CATALYTIC REDUCTION

0.0125 LB/MMBTU BACT-PSD 

AZ-0046 4/14/2005 STEAM BOILERS NOS. 1 AND 2 NATURAL GAS 419 MMBTU/H NOx LOW NOX BURNERS AND FLUE GAS RECIRCULATION 0.0125 LB/MMBTU BACT-PSD WA-0301 4/20/2005 BOILER, NATURAL GAS NATURAL GAS 363 MMBTU/H NOx ULNB + FGR 10.1 LB/H BACT-PSD AL-0160 6/7/2000 BOILER, NAT GAS NATURAL GAS 378 MMBTU/H NOx LOW NOX BURNERS WITH FLUE GAS RECIRCULATION. 0.036 LB/MMBTU BACT-PSD OR-0024 1/27/1998 AUXILLIARY BOILER NATURAL GAS 400 MMBTU/H NOx LOW NOX BURNER AND FLUE GAS RECIRCULATION 30 PPMDV @ 3%O2 BACT-PSD 14.4 LB/H LA-0177 9/8/2005 NATURAL GAS-FIRED BOILER NATURAL GAS 363 MMBTU/H NOx LOW NOX BURNERS WITH FLUE GAS RECIRCULATION 14.53 LB/H BACT-PSD 63.64 T/YR SC-0091 7/3/2003 BOILER, NATURAL GAS NATURAL GAS 550 MMBTU/H NOx LOW NOX BURNERS, FLUE GAS RECIRCULATION 0.04 LB/MMBTU BACT-PSD SC-0071 4/9/2001 BOILERS, AUXILIARY, NATURAL GAS, (2) NATURAL GAS 350 MMBTU/H NOx

LOW NOX BURNER WITH FGR ALONG WITH HAVING GOOD COMBUSTION PRACTICES

0.04 LB/MMBTU BACT-PSD 

TX-0419 3/22/2000 BOILER, AUXILIARY, (3) NATURAL GAS 380 MMBTU/H NOx GOOD COMBUSTION PRACTICE 22.8 LB/H BACT-PSD *LA-0171 12/22/1998 BOILER, HIGH PRESSURE, B-76001 NATURAL GAS 418 MMBTU/H NOx ULTRA LOW-NOX BURNERS 11.5 LB/H BACT-PSD 25.2 T/YR NE-0024 6/22/2004 BOILER D (NO. 21) NATURAL GAS 276.67 MMBTU/H NOx LOW NOX BURNERS AND INDUCED FLUE GAS RECIRCULATION AT 16%. 0.05 LB/MMBTU Other Case- by-Case AL-0199 11/15/2002 BOILER, 300 MMBTU/H, NATURAL GAS NATURAL GAS 300 MMBTU/H NOx LOW NOX BURNERS 0.05 LB/MMBTU BACT-PSD 15 LB/H TX-0373 10/24/2002 F BOILER STACK, EYFBLRST NAT GAS 370 MMBTU/H NOx

USING ONLY GASEOUS FUELS, DRY LOW NOX COMBUSTORS & FLUE GAS RECIRCULATION TECHNOLOGY

25.9 LB/H BACT-PSD 97.2 T/YR 

NE-0013 9/30/1999 BOILER NATURAL GAS ONLY 276.67 MMBTU/H NOx

LOW NOX BURNERS, INDUCED FUEL GAS RECIRCULATION WITH 110% OF TOTAL EXHAUST FLOW

0.05 LB/MMBTU BACT-PSD 

IL-0060 12/24/1998 BOILER (11), GAS FIRED NATURAL GAS 350 MMBTU/H NOx LOW-NOX BURNERS; FUEL SELECTION 0.05 LB/MMBTU BACT-PSD 0 TX-0323 12/22/1998 EXIST STEAM BOILER, PHASE 1, 2&3, STK-801 NAT GAS 352.2 MMBTU/H NOx NONE INDICATED 17.61 LB/H Other Case- by-Case 24.75 T/YR TX-0237 9/8/1998 HEATERS, FRESH FEED CRACKING, (8) NATURAL GAS 445.41 MMBTU/H NOx LOW NOX BURNERS 35.63 LB/H BACT-PSD 122.91 T/YR TX-0237 9/8/1998 BOILER, SUPPLEMENTAL, (2) NATURAL GAS 416 MMBTU/H NOx PARTIAL FLUE GAS RECIRCULATION (FGR) 24.96 LB/H BACT-PSD 91.1 T/YR LA-0115 11/3/1997 BOILER NATURAL GAS 300 MMBTU/H NOx LOW NOX BURNER AND INTERNAL FLUE GAS RECIRCULATION (FGR) 0.05 MMBTU/H BACT-PSD 0 GA-0084 6/16/1997 BOILER (NATURAL GAS) NATURAL GAS 352 MMBTU/H NOx LOW NOX BURNER, FLUE GAS RECIRCULATION 0.05 LB/MMBTU- NAT GAS BACT-PSD 

page 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 Revisio
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 

Unit

Case-bycase 

basis

Emission 

Limit 2

Emi

Limit 

AL-0085 5/10/1996 POWER BOILER, NATURAL GAS NATURAL GAS 346.4 MMBTU/H NOx LOW NOX BURNERS AND FLUE GAS RECIRCULATION (FGR) 0.05 LB/MMBTU BACT-PSD 17.32 LB/H *WI-0076 10/28/1993 BOILER, NATURAL GAS NATURAL GAS 330 MMBTU/H NOx LOW NOX BURNER, FLUE GAS RECIRCULATION 0.05 LB/MMBTU BACT-PSD 0 TX-0293 6/16/1999 (2) AUX PACKAGE BOILERS, EPN103 &104 NAT GAS 405 MMBTU/H NOx FIRED ONLY WITH PIPELINE QUALITY NATURAL GAS 11.2 T/YR BACT-PSD 21.9 LB/H TX-0419 3/22/2000 BOILER, AUXILIARY, (3) PROCESS GAS NATURAL GAS 380 mmbtu/h NOx GOOD COMBUSTION PRACTICE 0.06 LB/MMBTU BACT-PSD LA-0124 11/23/1999 TEMPORARY BOILER NO.1 AND NO.2 (EACH) NATURAL GAS 356 MMBTU/H NOx LOW NOX BURNERS AND FLUE GAS RECIRCULATION. 21.36 LB/H BACT-PSD 74.85 T/YR TX-0310 1/6/1999 BOILER, B108 NAT GAS 264 MMBTU/H NOx NONE INDICATED 15.88 LB/H Other Case- by-Case 69.55 T/YR TX-0371 2/4/2000 (3) AUXILIARY BOILERS 1-3, AB1-3 NAT GAS 315 MMBTU/H NOx NONE INDICATED 18.84 LB/H BACT-PSD OH-0271 7/27/2004 BOILER (1) NATURAL GAS 281 MMBTU/H NOx LOW NOX BURNERS WITH FLUE GAS RECIRCULATION 539.52 LB/D BACT-PSD 98.5 T/YR MT-0028 11/6/2001 BOILER, NATURAL GAS NATURAL GAS 358 MMBTU/H NOx FLUE GAS RECIRCULATION AND LOW NOX BURNERS 29.7 LB/H Other Case- by-Case 0.08 LB/MM*LA-0171 12/22/1998 CTU HEATER, NO.3, H-1101 NATURAL GAS 264 MMBTU/H NOx ULTRA LOW-NOX BURNERS 19 LB/H BACT-PSD 79.9 T/YR TX-0237 9/8/1998 FURNACE, RECYCLE ETHANE CRACKING NATURAL GAS 342.5 MMBTU/H NOx LOW NOX BURNERS 27.4 LB/H BACT-PSD 94.52 T/YR LA-0105 10/16/1996 UTILITY BOILER NATURAL GAS 320 MMBTU/H NOx LOW NOX BURNERS 0.08 LB/MMBTU BACT-PSD 25.56 LB/H TX-0416 11/24/1999 BOILER, PHENOL/ACETONE PLANT NATURAL GAS 357 MMBTU/H NOx GOOD COMBUSTION PRACTICE 30.24 LB/H BACT-PSD 132.47 T/YR IA-0045 5/29/1998 BOILER, NATURAL GAS NATURAL GAS 278 MMBTU/H NOx LOW NOX BURNER WITH STEAM INJECTION 0.1 LB/MMBTU BACT-PSD 27.8 LB/H MS-0029 9/10/1996 BOILER, NATURAL GAS 400 MMBTU/H NOx

LOW NOX BURNERS WITH FLUE GAS RECIRCULATION (FGR)

0.1 LB/MMBTU BACT-PSD 0 

TX-0373 10/24/2002 C BOILER STACK, EY003ST NAT GAS 320 MMBTU/H NOx NONE INDICATED 38.4 LB/H Other Case- by-Case 168.2 T/YR AL-0160 6/7/2000 BOILER, BACKUP OIL NATURAL GAS 378 MMBTU/H NOx LOW NOX BURNERS AND FLUE GAS RECIRCULATION 0.15 LB/MMBTU BACT-PSD OR-0037 12/29/2000 AUXILIARY BOILER NAT GAS 400 MMBTU/H NOx LOW NOX BURNERS AND FLUE GAS RECIRCULATION 60 PPMVD @ 3% O2 Other Case- by-Case 80 PPMVD 

O2 

OR-0032 10/13/1998 AUXILIARY BOILERS NATURAL GAS 720 MMBTU/H NOx 0.2 LB/MMBTU BACT-PSD 

BACT-PSD PM lb/MMBtu Emission Limits

MIN 0.0125 lb/MMBtu MIN 0.05 lb/MM

MAX 0.2 lb/MMBtu MAX 0.2 lb/MM

MEDIAN 0.05 lb/MMBtu MEDIAN 0.07 lb/MM

COUNT 36 CASES COUNT 6 CASE

RBLC NOx BACT Limits Summary

Other (non-BACT) PM lb/MMBtu Em

Limits

page 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 Revisio
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case

cas

bas

AR-0019 3/4/1997 BOILER, COGENERATION/WASTE HEAT RECOVERY

NATURAL GAS 68 MMBTU/H CO

GOOD COMBUSTION PRACTICES 10.6 LB/H

BACTPSD 

OH-0258 2/15/2001 BOILERS (4)

NATURAL GAS 20.9 MMBTU/H CO 0.23 LB/H N/A 

IA-0062 12/20/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H CO CATALYTIC OXIDATION 0.0164 LB/MMBTU

Other Case-Case 

NM-0042 12/29/2000 AUX-1 AUXILARY BOILER

NATURAL GAS 44.1 MMBTU/H CO

GOOD COMBUSTION CONTROL, NATURAL GAS COMBUSTION 6.6 LB/H

BACTPSD 

OR-0040 3/12/2003 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 50000 LB/H CO 0.035 LB/MMBTU

BACTPSD 

ND-0018 7/9/1998 BOILER, NEBRASKA, NAT GAS

NATURAL GAS 28 MMBTU/H CO 1 LB/H

BACTPSD 

NV-0039 6/1/2001 AUXILIARY BOILERS

NATURAL GAS 44.1 MMBTU/H CO GOOD COMBUSTION CONTROL 100

PPMVD@3% O2

BACTPSD 

WI-0226 8/27/2004 NATURAL GAS FIRED BOILER

NATURAL GAS 46.2 MMBTU/H CO BOILER DESIGN 1.67 LB/H N/A 

NJ-0042 2/5/1999 BOILER 1 (NATURAL GAS)

NATURAL GAS 84.4 MMBTU/H CO NONE LISTED 3 LB/H

BACTPSD 

NJ-0045 1/14/1997 BOILERS - NAT GAS (3)

NATURAL GAS 99.5 MMBTU/H CO NONE 3.6 LB/H

BACTPSD 

CA-0942 2/15/2000 BOILER, NATURAL GAS

NATURAL GAS 6 MMBTU/H CO 50 PPMVD LAER 

CA-0945 3/17/2000 BOILER

NATURAL GAS 16.3 MMBTU/H CO 50

PPM @ 3% O2 LAER 

CA-0941 1/28/2000 BOILER, NATURAL GAS

NATURAL GAS 16.3 MMBTU/H CO FLUE GAS RECIRCULATION 50 PPMVD LAER 

CA-0946 7/12/2000 BOILER

NATURAL GAS 21 MMBTU/H CO 50 PPMVD LAER 

CA-0940 3/15/2000 BOILER, PORTABLE

NATURAL GAS 28.8 MMBTU/H CO GOOD COMBUSTION PRACTICE 50 PPMVD LAER 

*WA-0292 10/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H CO 50

PPM @ 3% O2

BACTPSD 

OH-0252 12/28/2004 BOILERS (2)

NATURAL GAS 30.6 MMBTU/H CO 1.13 LB/H

BACTPSD 

GA-0101 10/23/2002 BOILER, AUXILIARY

NATURAL GAS 31.4 MMBTU/H CO GOOD COMBUSTION PRACTICE 0.037 LB/MMBTU

BACTPSD 

CA-0919 11/23/1999 BOILER, FIRE TUBE

NATURAL GAS 31.5 MMBTU/H CO

GOOD COMBUSTION PRATICES. 50

PPMVD @ 3% O2

BACTPSD 

OK-0070 6/13/2002 AUXILIARY BOILER

NATURAL GAS 33 MMBTU/H CO

BOILER DESIGN AND GOOD OPERATING PRACTICES 0.037 LB/MMBTU

BACTPSD 

CA-0938 12/2/1999 BOILER, (3)

NATURAL GAS 33.9 MMBTU/H CO GOOD COMBUSTION PRACTICE 50 PPMVD LAER 

OR-0039 12/30/2003 BOILERS, AUXILIARY, NATURAL GAS, (2)

NATURAL GAS 80 MMBTU/H CO GOOD COMBUSTION 0.037 LB/MMBTU

BACTPSD 

AR-0070 8/23/2002 AUXILIARY BOILER

NATURAL GAS 33 MMBTU/H CO GOOD COMBUSTION PRACTICE 0.04 LB/MMBTU

BACTPSD 

GA-0063 4/3/1996 BOILER, NATURAL GAS

NATURAL GAS 60 MMBTU/H CO COMPLETE COMBUSTION 0.05 LB/MMBTU

BACTPSD 

CA-1005 3/16/2000 BOILER, 5.05 MMBTU/H

NATURAL GAS 5.05 MMBTU/H CO 50

PPMV @ 3% O2

BACTPSD 

MN-0054 12/4/2003 BOILER, COMMERCIAL

NATURAL GAS 70 MMBTU/H CO GOOD COMBUSTION 0.06 LB/MMBTU

BACTPSD 

*LA-0112 2/13/1998 BOILER NO. 1

NATURAL GAS 95 MMBTU/H CO

GOOD DESIGN, PROPER OPERATING PRACTICES AND 2% EXCESS O2 5.7 LB/H

BACTPSD 

IN-0108 11/21/2003 BOILER, NATURAL GAS, (2)

NATURAL GAS 34 MMBTU/H CO

GOOD COMBUSTION PRACTICES, NATURAL GAS 0.061 LB/MMBTU

BACTPSD 

CA-1006 12/16/1999 BOILER, 20.9 MMBTU/H

NATURAL GAS 20.9 MMBTU/H CO 100

PPMVD @ 3% O2

BACTPSD 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -CO

NM-0044 6/27/2002 AUXILIARY BOILERS (AUX-1 AND AUX-2)

NATURAL GAS 33 MMBTU/H CO

DRY LOW NOX (DLN) TECHNOLOGY, GOOD COMBUSTION PRACTICES 4.9 LB/H

BACTPSD 

OK-0072 5/6/2002 AUXILIARY BOILER

NATURAL GAS 93 MMBUT/H CO

BOILER DESIGN AND GOOD OPERATING PRACTICES 0.07 LB/MMBTU

BACTPSD 

AL-0179 10/3/2001 30 MMBTU/HR AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H CO EFFICIENT COMBUSTION 0.073 LB/MMBTU

BACTPSD 

VA-0260 11/21/2002 AUXILIARY BOILER, (2)

NATURAL GAS 40 MMBTU/H CO

GOOD COMBUSTION AND DESIGN. CLEAN FUEL. 2.9 LB/H

BACTPSD 

IA-0060 7/23/2002 AUXILIARY BOILER (48.5 MMBTU/H)

NATUAL GAS 48.69

MILLION CF/YR CO GCP 0.073 LB/MMBTU

BACTPSD 

CA-0943 4/6/2000 BOILER

NATURAL GAS 6.3 MMBTU/H CO 100 PPMVD LAER 

CA-0947 3/15/2000 BOILER

NATURAL GAS 7.5 MMBTU/H CO 100 PPMVD LAER 

CA-0948 9/9/1999 BOILER, (2)

NATURAL GAS 8.18 MMBTU/H CO 100 PPMVD LAER 

CA-0944 3/10/2000 BOILER

NATURAL GAS 16.3 MMBTU/H CO 100 PPMVD LAER 

CA-0939 12/16/1999 BOILER

NATURAL GAS 20.9 MMBTU/H CO

GOOD COMBUSTION PRACTICES 10 PPMVD LAER 

OH-0255 3/29/2001 BOILER, NATURAL GAS

NATURAL GAS 85.2 MMBTU/H CO 6.3 LB/H

BACTPSD 

CA-0918 12/2/1999 CLAYTON WATER-TUBE BOILER

NATURAL GAS 4.29 MMBTU/H CO

ULTRA LOW-NOX BURNER SYSTEM 100

PPMVD @ 3% O2

BACTPSD 

NJ-0046 3/7/1996

BOILERS 4&5, COMBUSTION CONTROLS, OXYGEN TRIM, ETC

NATURAL GAS 94 MMBTU/H CO N/A 7.28 LB/H

BACTPSD 

WI-0207 1/21/2004 BOILER, S52/B52, 11 MMBTU/H

NATURAL GAS 11 MMBTU/H CO

NATURAL GAS / PROPANE ; GOOD COMBUSTION CONTROL 0.08 LB/MMBTU

BACTPSD 

TX-0354 12/19/2002 (2) STEAM BOILERS, X-426A AND X-426B

NATURAL GAS 15.8 MMBTU/H CO NONE INDICATED 1.33 LB/H

Other Case-Case 

PA-0216 1/13/2003 BOILER, DRAP LINE

NATURAL GAS 33.5 MMBTU/H CO 2.75 LB/H

Other Case-Case 

WI-0207 1/21/2004 BOILER, S53 / B53, 34 MMBTU/H

NATURAL GAS 34 MMBTU/H CO

NATURAL GAS / PROPANE; GOOD COMBUSTION CONTROL 0.08 LB/MMBTU

BACTPSD 

AZ-0047 12/1/2004 AUXILIARY BOILER

NATURAL GAS 38 MMBTU/H CO 0.08 LB/MMBTU

BACTPSD 

AL-0169 2/5/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H CO

GOOD COMBUSTION PRACTICES 0.08 LB/MMBTU

BACTPSD 

VA-0271 3/24/2003 BOILER NO. 1

NATURAL GAS 43.2 MMBTU/H CO

CONTINUOUS EMISSION MONITORING SYSTEM AND GOOD COMBUSTION PRACTICES. 3.56 LB/H N/A 

TX-0274 4/3/2000 AUXILIARY BOILER

NATURAL GAS 54.01 MMBTU/H CO NONE INDICATED 4.45 LB/H N/A 

TX-0378 11/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H CO NONE INDICATED 4.84 LB/H

Other Case-Case 

NV-0037 5/14/2004 AUXILIARY BOILER

NATURAL GAS 60 MMBTU/H CO

EFFECTIVE COMBUSTION SYSTEM DESIGN, 10:1 TURNDOWN CAPABILITY, AND LNB TECHNOLOGY 0.08 LB/MMBTU LAER 

WI-0207 1/21/2004 BOILER, S50/B50, 60 MMBTU/H

NATURAL GAS 60 MMBTU/H CO

NATURAL GAS / PROPANE; GOOD COMBUSTION CONTROL 0.08 LB/MMBTU

BACTPSD 

WI-0207 1/21/2004 BOILER, S51/B51, 80 MMBTU/H

NATURAL GAS 80 MMBTU/H CO

NAT. GAS / PROPANE, GOOD COMBUSTION CONTROL 0.08 LB/MMBTU

BACTPSD 

VA-0261 9/6/2002 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H CO

GOOD COMBUSTION PRACTICES. 6.42 LB/H

BACTPSD 

MA-0029 9/29/1999 BOILER, AUXILIARY

NATURAL GAS 96 MMBTU/H CO OXIDATION CATALYST 7.7 LB/H

BACTPSD 

WI-0227 10/13/2004 NATURAL GAS FIRED AUXILLIARY BOILER

NATURAL GAS 97.1 MMBTU/H CO

NATURAL GAS FUEL, GOOD COMBUSTION PRACTICES 7.77 LB/H

BACTPSD 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -CO

IN-0095 12/7/2001 AUXILLIARY BOILER

NATURAL GAS 21 MMBTU/H CO

GOOD COMBUSTION PRACTICES 0.082 LB/MMBTU

BACTPSD 

IN-0110 10/5/2001 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 35 MMBTU/H CO

CLEAN FUEL, GOOD COMBUSTION PRACTICE 0.082 LB/MMBTU

BACTPSD 

IN-0087 6/6/2001 AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 46 MMBTU/H CO

GOOD COMBUSTION. LIMIT IS FOR EACH BOILER. 0.082 LB/MMBTU

BACTPSD 

OH-0257 12/27/2001 AUXILIARY BOILER

NATURAL GAS 76 MMBTU/H CO 6.86 LB/H

BACTPSD 

NC-0094 1/9/2002 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 83 MMBTU/H CO

GOOD C OMBUSTION PRACTICES AND DESIGN 6.84 LB/H

BACTPSD 

OK-0051 10/1/1999 AUXILIARY BOILER

NATURAL GAS CO

BOILER DESIGN & GOOD OPERATING PRACTICES 0.082 LB/MMBTU

BACTPSD 

AR-0086 6/11/2004 VTD BOILER

NATURAL GAS 50 MMBTU/H CO GOOD COMBUSTION PRACTICE 4.2 LB/H

BACTPSD 

TX-0408 11/22/2002 AUXILIARY BOILER, (2)

NATURAL GAS 6 MMBTU/H CO 0.5 LB/H

BACTPSD 

WA-0291 1/3/2003 BOILER, AUXILIARY

NATURAL GAS 55.3 MMBTU/H CO 111

PPMDV @ 3% O2

Other Case-Case 

OK-0056 2/12/2002 AUXILIARY BOILERS

NATURAL GAS 0 CO

GOOD COMBUSTION PRACTICES & DESIGN 0.084 LB/MMBTU

BACTPSD 

OK-0074 5/1/2001 AUXILIARY BOILER

NATURAL GAS 27.5 MMBTU/H CO

GOOD OPERATING PRACTICES AND DESIGN 0.084 LB/MMBTU

BACTPSD 

AL-0192 10/18/2002 BOILERS, NATURAL GAS, (3)

NATURAL GAS 30 MMBTU/H CO

CLEAN FUEL, GOOD COMBUSTION PRACTICES. 2.52 LB/H

BACTPSD 

OK-0055 2/12/2002 AUXILIARY BOILER

NATURAL GAS 31 MMBTU/H CO COMBUSTION CONTROL 0.084 LB/MMBTU

BACTPSD 

MN-0053 7/15/2004 BOILER, NATURAL GAS (1)

NATURAL GAS 40 MMBTU/H CO GOOD COMBUSTION. 0.084 LB/MMBTU

BACTPSD 

OK-0044 8/16/2001 AUXILIARY BOILERS, (2)

NATURAL GAS 48 MMBTU/H CO COMBUSTION CONTROL 7.91 LB/H

BACTPSD 

OH-0265 10/16/2001 BOILER, NATURAL GAS

NATURAL GAS 49 MMBTU/H CO 4.12 LB/H

BACTPSD 

IA-0058 4/10/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H CO 0.084 LB/MMBTU

Other Case-Case 

OH-0248 9/24/2002 BOILER

NATURAL GAS 99 MMBTU/H CO 8.32 LB/H

BACTPSD 

OK-0043 10/22/2001 AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H CO

BOILER DESIGN & GOOD OPERATING PRACTICES 0.085 LB/MMBTU

BACTPSD 

OK-0090 3/21/2003 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H CO

BOILER DESIGN AND GOOD OPERATING PRACTICES 0.085 LB/MMBTU

BACTPSD 

AL-0168 1/12/2001 BOILER

NATURAL GAS 83 MMBTU/H CO EFFICIENT COMBUSTION 0.085 LB/MMBTU

BACTPSD 

CA-0790 12/30/1996 NEBRASKA BOILER, MODEL NS-B-40

NATURAL GAS 31.2 MMBTU/HR CO GOOD COMBUSTION 0.089 LB/MMBTU LAER 

*AZ-0049 9/4/2003 AUXILIARY BOILER FOR GE TURBINE

NATURAL GAS 41 MMBTU/H CO 0.09 LB/MMBTU

BACTPSD 

AL-0191 3/23/2004 BOILERS, NATURAL GAS, (3)

NATURAL GAS 50 MMBTU/H CO CLEAN FUEL 4.5 LB/H

BACTPSD 

CO-0041 5/6/1999 BOILER NO.2, TEST MINE HOT WATER (1)

NATURAL GAS 51.08 MMBTU CO GOOD COMBUSTION 0.09 LB/MMBTU

BACTPSD 

CO-0040 5/6/1999 INDUSTRIAL BOILER, NATURAL GAS

NATURAL GAS 80.8 MMBTU/H CO

GOOD COMBUSTION MANAGEMENT. CAPITAL AND ANNUALIZED COSTS ARE INCLUDED IN OPERATION AND MAINTENANCE 0.09 LB/MMBTU

BACTPSD 

TN-0153 4/3/2002 BOILER, NO. 9

NATURAL GAS 95 MMBTU/H CO 0.09 LB/MMBTU

BACTPSD 

WV-0021 6/9/2004 BOILER, NATURAL GAS, 39.00 MMBTU

NATURAL GAS 365 MMSCF/YR CO 3.5 PPH

BACTPSD 

GA-0098 3/24/2003 AUXILIARY BOILER

NATURAL GAS 83 MMBTU/H CO 0.093 LB/MMBTU

Other Case-Case 

OH-0263 8/9/2001 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H CO 7.84 LB/H

BACTPSD 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -CO

TX-0364 1/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H CO NONE INDICATED 0.25 LB/H

Other Case-Case 

TN-0153 4/3/2002 CCR STABILIZATION REBOILER

NATURAL GAS 54 MMBTU/H CO 0.1 LB/MMBTU

BACTPSD 

PA-0149 11/26/1997 HEAT RECOVERY BOILER

NG SUPPLEMENT 24000

LB/HR STEAM CO 0.1 LB/MMBTU

Other Case-Case 

OH-0254 8/14/2003 BOILER

NATURAL GAS 30.6 MMBTU/H CO 3.34 LB/H

BACTPSD 

OH-0251 11/29/2001 BOILER, NATURAL GAS

NATURAL GAS 91.2 MMBTU/H CO 12.2 LB/H N/A 

*AZ-0049 9/4/2003 AUXILIARY BOILER FOR SIEMENS TURBINES

NATURAL GAS 55.34 MMBTU/H CO 0.14 LB/MMBTU

BACTPSD 

*AK-0062 8/19/2005 NATCO TEG REBOILER

NATURAL GAS 1.34 MMBtu/hr CO

GOOD OPERATIONAL PRACTICES 0.15 LB/MMBTU

BACTPSD 

MA-0027 5/7/2000 AUXILIARY BOILER

NATURAL GAS 26.6 MMBTU/H CO OXIDATION CATALYST 4 LB/H

BACTPSD 

AR-0051 4/1/2002 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H CO GOOD OPERATING PRACTICE 0.15 LB/MMBTU

BACTPSD 

AR-0040 12/29/2000 BOILERS, AUXILIARY 2

NATURAL GAS 44.1 MMBTU/H CO

PROPER COMBUSTION PROCEDURES. LB/HR LIMIT FOR EACH BOILER. 0.15 LB/MMBTU

BACTPSD 

VA-0255 11/18/2002 BOILER, AUXILIARY

NATURAL GAS 99 MMBTU/H CO

GOOD COMBUSTION PRACTICES. 14.9 LB/H

Other Case-Case 

WY-0056 7/25/2000 BOILER (AUXILLARY), TRAIN III

NATURAL GAS 76.7 MMBTU/H CO 13.4 T/YR

BACTPSD 

PA-0165 2/24/2000 BOILERS, (3)

NATURAL GAS 90 MMBTU/H CO LOW NOX BURNERS 0.173 LB/MMBTU

BACTPSD 

IN-0068 1/19/1996 BOILERS, NATURAL GAS

NATURAL GAS 93.9 MMBTU/H CO LOW-NOX BURNER 19.2 LB/H

BACTPSD 

PA-0210 12/14/2001 BOILER, (2)

NATURAL GAS 33.5 MMBTU/H CO GOOD COMBUSTION PRACTICE 400

PPMDV @ 3% O2

Other Case-Case 

OK-0071 10/25/2001 AUXILIARY BOILER

NATURAL GAS 22 MMBTU/H CO USE OF NATURAL GAS FUEL 0.37 LB/MMBTU

BACTPSD 

LA-0174 1/25/2002 POWER BOILER NO. 2 NAT GAS 65.5 MMBTU/H CO

GOOD EQUIPMENT DESIGN AND PROPER COMBUSTION TECHNIQUES 36.8 LB/H

BACTPSD 

VA-0271 3/24/2003 BOILER NO. 3

NAT GAS OR DIS OIL 43.2 MMBTU CO

CONTINUOUS EMISSION MONITORING SYSTEM AND GOOD COMBUSTION PRACTICES. 30.21 T/YR N/A 

IN-0086 5/9/2001 AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 35 MMBTU/H CO

GOOD COMBUSTION. LB/H LIMIT IS FOR EACH BOILER. 0.824 LB/MMBTU

BACTPSD 

AR-0077 7/22/2004 BOILERS

NATURAL GAS 22 MMBTU/H CO GOOD COMBUSTION PRACTICE 0.84 LB/MMBTU

BACTPSD 

IA-0054 5/20/1997 HIGH PRESSURE BOILER #1

NATURAL GAS 0.3 MMBTU/H CO 1.3 LB/H

BACTPSD 

IA-0054 5/20/1997 BOILER #2 B2

NATURAL GAS 2.3 MMBTU/H CO

LOW NOX BURNER , FLUE GAS RECIRC. 9.9 LB/H

BACTPSD 

IA-0054 5/20/1997 BOILER #1

NATURAL GAS 2.3 MMBTU/H CO

LOW NOX BURNER, FLEE GAS RECIRC. 9.9 LB/H

BACTPSD 

IA-0054 5/20/1997 BOILER #3 B3

NATURAL GAS 2.3 MMBTU/HR CO

LOW NOX BURNER, FLUE GAS RECIRC. 9.9 LB/H

BACTPSD 

IN-0104 8/14/1998

BOILERS, REFINERY & HYDROGEN PLANT REFORMER

NATURAL GAS 10 MMBTU/H CO COMBUSTION CONTROL 0.074 MMBTU/H

BACTPSD 

CA-0722 10/24/1996 TWO HOT-WATER BOILERS

PROPANE (LPG) 8.4

MMBTU/HR/UNIT CO

LOW EMISSIONS FLAMELESS BURNER 50

PPMVD AT 3% OXYGEN

Other Case-Case 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT Report -Attachment L - EPA RACT BACT LAER Clearinghouse DataTable L-41: Samll Gas Fired Boilers and Heaters -CO

WI-0181 8/2/2000 BOILER

NATURAL GAS 10 MMBTU/H CO

BACT FOR CO IS DETERMINED TO BE GOOD COMBUSTION CONTROL AND THE USE OF NATURAL GAS TO FUEL THE BOILER. NO EMISSION RATE LIMIT.

BACTPSD

TX-0389 12/31/2002 BACK-UP BOILER

NATURAL GAS 13.4 MMBUT/H CO 1.11 LB/H

Other Case-Case 

CA-1021 12/7/1999 BOILER: 16.5 MMBTU/H

NATURAL GAS 16.5 MMBTU/H CO 50

PPMVD @ 3% O2

BACTPSD

CA-1100 7/12/2000 BOILER: 5 TO < 33.5 MMBTU/HR

NATURAL GAS 21 MMBTU/H CO SCR 50

PPMVD@3% O2

BACTPSD

CA-1099 9/4/2001 BOILER: 5 TO < 33.5 MMBTU/HR

NATURAL GAS 21.46 MMBTU/H CO ULTRA LOW-NOX BURNER 100

PPMD @ 3% O2

BACTPSD

OH-0276 4/14/2003 BOILER FOR VACUUM OXYGEN DEGASSER VESSEL

NATURAL GAS 25 MMBTU/H CO 2.06 LB/H

BACTPSD 

VA-0243 12/1/2002 BOILER, NAT GAS & OIL ` 26.5 MMBTU/H CO EMISSION LIMITS IN T/YR ONLY 9.4 T/YR

Other Case-Case

AL-0181 10/23/2001 31.4 MMBTU/HR NATURAL GAS FIRED BOILER

NATURAL GAS 31.4 MMBTU/H CO EFFICIENT COMBUSTION. 0.135 LB/MMBTU

BACTPSD 

AL-0180 12/11/2001 35 MMBTU/HR NAT. GAS FIRED AUXILIARY BOILER

NATURAL GAS 35 MMBTU/H CO GOOD COMBUSTION 0.135 LB/MMBTU

BACTPSD 

CA-1023 10/8/2002 BOILER, 39 MMBTU/H

NATURAL GAS 39 MMBTU/H CO 100

PPMVD @ 3% 02 N/A

AL-0185 7/12/2002 TWO (2) 40 MMBTU/H AUXILIARY BOILERS

NATURAL GAS 40 MMBTU/H CO

GOOD COMBUSTION PRACTICES 0.082 LB/MMBTU

BACTPSD 

MD-0033 9/27/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H CO

EXCLUSIVE USE OF NATURAL GAS, ADVANCED DRY LOWNOX BURNERS; GOOD COMBUSTION CONTROLS HEAT INPUT TO THE AUXILIARY BOILERS (2) SHALL BE LIMITED TO 210,240 MMBTU FOR ANY CONSECUTIVE 12-MONTH PERIOD

BACTPSD

OK-0054 8/21/2001 BOILERS

NATURAL GAS 62.77 MMBTU/H CO

GOOD COMBUSTION/MAINTENANCE 10.81 T/YR

BACTPSD 

TX-0363 11/13/2000 BOILER NO. 2 NAT GAS CO NONE INDICATED 0.85 LB/H

Other Case-Case 

TX-0363 11/13/2000 BOILER NO 3 NAT GAS CO NONE INDICATED 0.57 LB/H

Other Case-Case 

TX-0300 10/13/1998 GLYCOL REBOILER NAT GAS CO NONE INDICATED 0.14 LB/H

Other Case-Case 

BACT-PSD CO lb/MMBtu Emission Limits

MIN 0.022 lb/MMBtu MI

MAX 4.3 lb/MMBtu MA

MEDIAN 0.082 lb/MMBtu MED

COUNT 81 CASES COU

RBLC CO BACT Limits Summary

Oth

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

WA-0279 11/16/1996 NATURAL GAS FIRED BOILERS

NATURAL GAS 800 HP VOC FUEL SPEC: NATURAL GAS 50.7 LB/D

BACTPSD 

NJ-0042 2/5/1999 BOILER 1 (NATURAL GAS)

NATURAL GAS 84.4 MMBTU/H VOC NONE LISTED 0.2 LB/H

BACTPSD 

IN-0108 11/21/2003 BOILER, NATURAL GAS, (2)

NATURAL GAS 34 MMBTU/H VOC

COMPLIANCE BY USING NATURAL GAS 0.0026 LB/MMBTU

BACTPSD 

NJ-0045 1/14/1997 BOILERS - NAT GAS (3)

NATURAL GAS 99.5 MMBTU/H VOC NONE 0.33 LB/H

BACTPSD 

AL-0179 10/3/2001 30 MMBTU/HR AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H VOC EFFICIENT COMBUSTION 0.004 LB/MMBTU

BACTPSD 

VA-0255 11/18/2002 BOILER, AUXILIARY

NATURAL GAS 99 MMBTU/H VOC

GOOD COMBUSTION PRACTICES. 0.4 LB/H

Other Case-byCase 

OH-0255 3/29/2001 BOILER, NATURAL GAS

NATURAL GAS 85.2 MMBTU/H VOC 0.35 LB/H

BACTPSD 

OK-0046 5/17/2001 AUXILIARY BOILER

NATURAL GAS 20 MMBTU/H VOC 0.005 LB/MMBTU

BACTPSD 

OH-0258 2/15/2001 BOILERS (4)

NATURAL GAS 20.9 MMBTU/H VOC 0.11 LB/H N/A 

GA-0063 4/3/1996 BOILER, NATURAL GAS

NATURAL GAS 60 MMBTU/H VOC COMPLETE COMBUSTION 0.005 LB/MMBTU

BACTPSD 

IN-0095 12/7/2001 AUXILLIARY BOILER

NATURAL GAS 21 MMBTU/H VOC

GOOD COMBUSTION PRACTICES 0.0054 LB/MMBTU

BACTPSD 

IN-0086 5/9/2001 AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 35 MMBTU/H VOC

GOOD COMBUSTION. LB/H LIMIT IS FOR EACH BOILER. 0.0054 LB/MMBTU

BACTPSD 

IN-0087 6/6/2001 AUXILARY BOILER, NATURAL GAS (2)

NATURAL GAS 46 MMBTU/H VOC

GOOD COMBUSTION. LIMIT IS FOR EACH BOILER. 0.0054 LB/MMBTU

BACTPSD 

NC-0094 1/9/2002 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 83 MMBTU/H VOC

GOOD COMBUSTION PRACTICES AND DESIGN 0.45 LB/H

BACTPSD 

OK-0051 10/1/1999 AUXILIARY BOILER

NATURAL GAS VOC

BOILER DESIGN AND GOOD OPERATING PRACTICES 0.0054 LB/MMBTU

BACTPSD 

OK-0056 2/12/2002 AUXILIARY BOILERS

NATURAL GAS 0 VOC

GOOD COMBUSTION PRACTICES AND DESIGN 0.0055 LB/MMBTU

BACTPSD 

OK-0044 8/16/2001 AUXILIARY BOILERS, (2)

NATURAL GAS 48 MMBTU/H VOC COMBUSTION CONTROL 0.52 LB/H

BACTPSD 

WI-0227 10/13/2004 NATURAL GAS FIRED AUXILLIARY BOILER

NATURAL GAS 97.1 MMBTU/H VOC

NATURAL GAS FUEL, GOOD COMBUSTION PRACTICES 0.53 LB/H

BACTPSD 

OH-0248 9/24/2002 BOILER

NATURAL GAS 99 MMBTU/H VOC 0.545 LB/H

BACTPSD 

OH-0265 10/16/2001 BOILER, NATURAL GAS

NATURAL GAS 49 MMBTU/H VOC 0.29 LB/H

BACTPSD 

AL-0168 1/12/2001 BOILER

NATURAL GAS 83 MMBTU/H VOC EFFICIENT COMBUSTION 0.006 LB/MMBTU

BACTPSD 

IN-0068 1/19/1996 BOILERS, NATURAL GAS

NATURAL GAS 93.9 MMBTU/H VOC 0.55 LB/H

BACTPSD 

NJ-0046 3/7/1996

BOILERS 4&5, COMBUSTION CONTROLS, OXYGEN TRIM, ETC

NATURAL GAS 94 MMBTU/H VOC N/A 0.79 LB/H

BACTPSD 

*AZ-0049 9/4/2003 AUXILIARY BOILER FOR SIEMENS TURBINES

NATURAL GAS 55.34 MMBTU/H VOC 0.01 LB/MMBTU

BACTPSD 

OH-0257 12/27/2001 AUXILIARY BOILER

NATURAL GAS 76 MMBTU/H VOC 0.92 LB/H

BACTPSD 

MA-0027 5/7/2000 AUXILIARY BOILER

NATURAL GAS 26.6 MMBTU/H VOC

COMBUSTION CONTROLS, OXIDATION CATALYST. 0.4 LB/H

BACTPSD 

OK-0043 10/22/2001 AUXILIARY BOILER

NATURAL GAS 30 MMBTU/H VOC 0.016 LB/MMBTU

BACTPSD 

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

OH-0252 12/28/2004 BOILERS (2)

NATURAL GAS 30.6 MMBTU/H VOC 0.49 LB/H

BACTPSD 

OH-0254 8/14/2003 BOILER

NATURAL GAS 30.6 MMBTU/H VOC 0.49 LB/H

BACTPSD 

AR-0051 4/1/2002 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H VOC GOOD OPERATING PRACTICE 0.016 LB/MMBTU

BACTPSD 

AR-0040 12/29/2000 BOILERS, AUXILIARY 2

NATURAL GAS 44.1 MMBTU/H VOC

CLEAN FUELS, PROPER COMBUSTION. LB/HR LIMIT FOR EACH BOILER. 0.016 LB/MMBTU

BACTPSD 

NM-0042 12/29/2000 AUX-1 AUXILARY BOILER

NATURAL GAS 44.1 MMBTU/H VOC GOOD COMBUSTION DESIGN 0.7 LB/H

BACTPSD 

NV-0039 6/1/2001 AUXILIARY BOILERS

NATURAL GAS 44.1 MMBTU/H VOC GOOD COMBUSTION CONTROL 0.8 LB/H

BACTPSD 

AL-0169 2/5/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H VOC

GOOD COMBUSTION PRACTICES 0.02 LB/MMBTU

BACTPSD 

MA-0029 9/29/1999 BOILER, AUXILIARY

NATURAL GAS 96 MMBTU/H VOC EMISSION OFFSET 0.8 LB/H LAER 

IA-0054 5/20/1997 HIGH PRESSURE BOILER #1

NATURAL GAS 0.3 MMBTU/H VOC 0.25 LB/H

BACTPSD 

IA-0054 5/20/1997 BOILER #2 B2

NATURAL GAS 2.3 MMBTU/H VOC

LOW NOX BURNER, FLUE GAS RECIRC. ADDITIONAL EMISSIONLIMIT: 70 PPM 2.37 LB/H

BACTPSD 

IA-0054 5/20/1997 BOILER #1

NATURAL GAS 2.3 MMBTU/H VOC

LOW NOX BURNER, FLUE GAS RECIRC. 2.37 LB/H

BACTPSD 

IA-0054 5/20/1997 BOILER #3 B3

NATURAL GAS 2.3 MMBTU/HR VOC

LOW NOX BURNER FLUE GAS RECIRCULATION 2.37 LB/H

BACTPSD 

TX-0364 1/31/2003 GLYCOL REBOILER, EPN11 NAT GAS 2.5 MMBTU/H VOC NONE INDICATED 0.02 LB/H

Other Case-byCase 

TX-0408 11/22/2002 AUXILIARY BOILER, (2)

NATURAL GAS 6 MMBTU/H VOC 0.01 LB/H

BACTPSD 

WI-0181 8/2/2000 BOILER

NATURAL GAS 10 MMBTU/H VOC

BACT FOR VOC IS DETERMINED TO BE USE OF NATURAL GAS TO FUEL BOILER. NO EMISSION RATE LIMIT.

BACTPSD

WI-0207 1/21/2004 BOILER, S52/B52, 11 MMBTU/H

NATURAL GAS 11 MMBTU/H VOC

NATURAL GAS / PROPANE; GOOD COMBUSTION CONTROL 0.0054 LB/MMBTU

BACTPSD

TX-0389 12/31/2002 BACK-UP BOILER

NATURAL GAS 13.4 MMBUT/H VOC 0.08 LB/H

Other Case-byCase 

TX-0354 12/19/2002 (2) STEAM BOILERS, X-426A AND X-426B

NATURAL GAS 15.8 MMBTU/H VOC NONE INDICATED. 0.09 LB/H

Other Case-byCase 

AR-0077 7/22/2004 BOILERS

NATURAL GAS 22 MMBTU/H VOC

NATURAL GAS COMBUSTION ONLY 0.0055 LB/MMBTU

BACTPSD

OK-0041 1/19/2000 AUXILIARY BOILER

NATURAL GAS 22 MMBTU/H VOC COMBUSTION CONTROLS 0.2 T/YR

BACTPSD

OH-0276 4/14/2003 BOILER FOR VACUUM OXYGEN DEGASSER VESSEL

NATURAL GAS 25 MMBTU/H VOC 0.13 LB/H

BACTPSD 

OK-0074 5/1/2001 AUXILIARY BOILER

NATURAL GAS 27.5 MMBTU/H VOC

GOOD COMBUSTION PRACTICES AND DESIGN 0.0055 LB/MMBTU

BACTPSD

*WA-0292 10/23/2001 AUXILIARY BOILER NAT GAS 29.3 MMBTU/H VOC 0.16 LB/H

BACTPSD

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

OK-0055 2/12/2002 AUXILIARY BOILER

NATURAL GAS 31 MMBTU/H VOC COMBUSTION CONTROL 0.0055 LB/MMBTU

Other Case-byCase

GA-0101 10/23/2002 BOILER, AUXILIARY

NATURAL GAS 31.4 MMBTU/H VOC GOOD COMBUSTION PRACTICE 0.0127 LB/MMBTU

BACTPSD

AL-0181 10/23/2001 31.4 MMBTU/HR NATURAL GAS FIRED BOILER

NATURAL GAS 31.4 MMBTU/H VOC EFFICIENT COMBUSTION. 0.0104 LB/MMBTU

BACTPSD 

OK-0090 3/21/2003 BOILER, AUXILIARY

NATURAL GAS 33 MMBTU/H VOC

BOILER DESIGN AND GOOD OPERATING PRACTICES 0.016 LB/MMBTU

BACTPSD

AR-0070 8/23/2002 AUXILIARY BOILER

NATURAL GAS 33 MMBTU/H VOC GOOD COMBUSTION PRACTICE 0.018 LB/MMBTU

BACTPSD

NM-0044 6/27/2002 AUXILIARY BOILERS (AUX-1 AND AUX-2)

NATURAL GAS 33 MMBTU/H VOC

CLEAN FUELS, GOOD COMBUSTION PRACTICE 0.5 LB/H

BACTPSD

OK-0070 6/13/2002 AUXILIARY BOILER

NATURAL GAS 33 MMBTU/H VOC

BOILER DESIGN AND GOOD COMBUSTION PRACTICES 0.016 LB/MMBTU

BACTPSD

WI-0207 1/21/2004 BOILER, S53 / B53, 34 MMBTU/H

NATURAL GAS 34 MMBTU/H VOC

NATURAL GAS / PROPANE; GOOD COMBUSTION CONTROL 0.0054 LB/MMBTU

BACTPSD

AL-0180 12/11/2001 35 MMBTU/HR NAT. GAS FIRED AUXILIARY BOILER

NATURAL GAS 35 MMBTU/H VOC GOOD COMBUSTION 0.014 LB/MMBTU

BACTPSD 

IN-0110 10/5/2001 BOILER, AUXILIARY, NATURAL GAS

NATURAL GAS 35 MMBTU/H VOC

CLEAN FUEL, GOOD COMBUSTION PRACTICE 0.011 LB/MMBTU

BACTPSD 

AZ-0047 12/1/2004 AUXILIARY BOILER

NATURAL GAS 38 MMBTU/H VOC 0.0033 LB/MMBTU

BACTPSD

MN-0053 7/15/2004 BOILER, NATURAL GAS (1)

NATURAL GAS 40 MMBTU/H VOC GOOD COMBUSTION. 0.006 LB/MMBTU

BACTPSD

AL-0185 7/12/2002 TWO (2) 40 MMBTU/H AUXILIARY BOILERS

NATURAL GAS 40 MMBTU/H VOC

GOOD COMBUSTION PRACTICES 0.0054 LB/MMBTU

BACTPSD 

TX-0437 7/5/2002 BOILERS, AUXILIARY

NATURAL GAS 40 mmbtu/h VOC

GOOD COMBUSTION PRACTICES PROPER DESIGN, CLEAN FUEL 0.02 LB/MMBTU

BACTPSD

MD-0033 9/27/2001 AUXILIARY BOILER

NATURAL GAS 40 MMBTU/H VOC

EXCLUSIVE USE OF NATURAL GAS, ADVANCED DRY LOWNOX BURNERS; GOOD COMBUSTION CONTROLS HEAT INPUT TO THE AUXILIARY BOILERS (2) SHALL BE LIMITED TO 210,240 MMBTU FOR ANY CONSECUTIVE 12-MONTH PERIOD LAER

*AZ-0049 9/4/2003 AUXILIARY BOILER FOR GE TURBINE

NATURAL GAS 41 MMBTU/H VOC 0.01 LB/MMBTU

BACTPSD

VA-0271 3/24/2003 BOILER NO. 3

NAT GAS OR DIS OIL 43.2 MMBTU VOC

GOOD COMBUSTION PRACTICES. 1.97 T/YR N/A

VA-0271 3/24/2003 BOILER NO. 1

NATURAL GAS 43.2 MMBTU/H VOC

GOOD COMBUSTION PRACTICES. 0.23 LB/H N/A

IA-0060 7/23/2002 AUXILIARY BOILER (48.5 MMBTU/H)

NATUAL GAS 48.69

MILLION CF/YR VOC GCP 0.005 LB/MMBTU

BACTPSD

TX-0274 4/3/2000 AUXILIARY BOILER

NATURAL GAS 54.01 MMBTU/H VOC NONE INDICATED. 0.29 LB/H N/A 

TX-0378 11/5/2001 PACKAGE BOILER BO-4 NAT GAS 60 MMBTU/H VOC NONE INDICATED 0.35 LB/H

Other Case-byCase 

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLCID Permit Date Process Fuel Throughput

Throughput 

Unit Pollutant Control Desc.

Emission 

Limit 1

Emission 

Limit 1 Unit

Case-bycase 

basis

NV-0037 5/14/2004 AUXILIARY BOILER

NATURAL GAS 60 MMBTU/H VOC

EFFECTIVE COMBUSTION SYSTEM DESIGN, 10:1 TURNDOWN CAPABILITY AND LOW NOX BURNER TECHNOLOGY 0.4 LB/H LAER

WI-0207 1/21/2004 BOILER, S50/B50, 60 MMBTU/H

NATURAL GAS 60 MMBTU/H VOC

NATURAL GAS / PROPANE, GOOD COMBUSTION CONTROLS 0.0054 LB/MMBTU

BACTPSD

OK-0054 8/21/2001 BOILERS

NATURAL GAS 62.77 MMBTU/H VOC

GOOD COMBUSTION/MAINTENANCE 4.38 T/YR

BACTPSD

IA-0062 12/20/2002 AUXILIARY BOILER

NATURAL GAS 68 MMBTU/H VOC CATALYTIC OXIDATION 0.0054 LB/MMBTU

Other Case-byCase

MN-0054 12/4/2003 BOILER, COMMERCIAL

NATURAL GAS 70 MMBTU/H VOC GOOD COMBUSTION 0.007 LB/MMBTU

BACTPSD

WI-0207 1/21/2004 BOILER, S51/B51, 80 MMBTU/H

NATURAL GAS 80 MMBTU/H VOC

NAT. GAS / PROPANE; GOOD COMBUSTION CONTROL 0.0054 LB/MMBTU

BACTPSD

VA-0261 9/6/2002 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H VOC

GOOD COMBUSTION PRACTICES. 0.42 LB/H

BACTPSD 

OH-0263 8/9/2001 AUXILIARY BOILER

NATURAL GAS 80 MMBTU/H VOC 0.44 LB/H

BACTPSD 

GA-0098 3/24/2003 AUXILIARY BOILER

NATURAL GAS 83 MMBTU/H VOC 0.004 LB/MMBTU

Other Case-byCase

OH-0251 11/29/2001 BOILER, NATURAL GAS

NATURAL GAS 91.2 MMBTU/H VOC 0.65 LB/H

BACTPSD 

OK-0072 5/6/2002 AUXILIARY BOILER

NATURAL GAS 93 MMBUT/H VOC

BOILER DESIGN AND GOOD OPERATING PRACTICES 0.0075 LB/MMBTU

BACTPSD

TX-0363 11/13/2000 BOILER NO. 2 NAT GAS VOC NONE INDICATED 0.07 LB/H

Other Case-byCase 

TX-0363 11/13/2000 BOILER NO 3 NAT GAS VOC NONE INDICATED 0.05 LB/H

Other Case-byCase 

TX-0300 10/13/1998 GLYCOL REBOILER NAT GAS VOC NONE INDICATED 0.01 LB/H

Other Case-byCase 

BACT-PSD VOC lb/MMBtu Emission Limits

MIN 0.002 lb/MMBtu MIN 

MAX 1.0 lb/MMBtu MAX 

MEDIAN 0.006 lb/MMBtu MEDIAN 

COUNT 35 CASES COUNT 

RBLC VOC BACT Limits Summary

Other (no

page 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 Re
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMIS

LIM

TN-0155

NUCOR STEEL CORPORATION 11/6/2000 ELECTRIC ARC FURNACE EAF 150 T/H SO2

LIMIT HIGH-SULFUR STEEL PRODUCTION TO 125,000 TON/YR; MAINTENANCE OF A LOG OF IRON PYRITE USAGE DURING HIGH-SULFUR STEEL PRODUCTION, PROPERLY DESIGNED EAF; SCRAP MANAGEMENT PLAN 0.16 LB/T BACT-PSD 

AR-0077 BLUEWATER PROJECT 7/22/2004 ELECTRIC ARC FURNACE (EAF) EAF 350 t/h SO2

LOW SULFUR COKE AND SCRAP MANAGEMENT 0.2 LB/T BACT-PSD

TX-0417 NUCOR CORP. 1/15/2003 ELECTRIC ARC FURNACE EAF SO2 LOW SULFUR FUEL 0.35 LB/T BACT-PSD

SC-0072

SMI STEEL - SOUTH CAROLINA 11/26/2001 EAF EAF 850000 T/YR SO2 SCRAP MANAGEMENT PLAN 0.35 LB/T BACT-PSD

AL-0129 IPSCO STEEL INC 10/16/1998 FURNACE, ELECTRIC ARC EAF 200 T/H SO2 0.7 LB/T BACT-PSD AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 ELECTRIC ARC FURNACE EAF 50 T/H SO2

DES WITH NO ADD-IN CONTROLS (EXISTING) 0.7 LB/T BACT-PSD 

MI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF 560000 T/YR SO2 1

LB/T STEEL PRODUCED BACT-PSD 

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, ELECTRIC ARC EAF 225 T/H SO2

LOW SULFUR COKE/SCRAP MANAGEMENT. 1.5 LB/T BACT-PSD

NY-0094 NUCOR AUBURN STEEL 6/22/2004 EAF EAF 110 t/h SO2 25.3 LB/H BACT-PSD 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR SO2

SULFUR CONTENT OF DIRECT REDUCED IRON, CHARGE CARBON, AND INJECTION CARBON 50 LB/H BACT-PSD 

*AR-0086

NUCOR-YAMATO STEEL COMPANY, BLYTHEVILLE MILL 6/11/2004 EAF #1 BAGHOUSE, SN-01 EAF 450 T/H STEEL SO2 LOW SULFUR COKE USAGE 90 LB/H BACT-PSD 

AL-0202 CORUS TUSCALOOSA 6/3/2003 ELECTRIC ARC FURNACE EAF 160 T/H SO2 99.2 LB/H BACT-PSD 

AL-0197

NUCOR STEEL DECATUR, LLC 7/11/2002 ELECTRIC ARC FURNACE, (2) EAF 440 T/H SO2 220 LB/H BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 ELECTRIC ARC FURNACE EAF 110 T/H MELT SO2 PRODUCTION LIMITS. SEE NOTE 22 LB/H 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS SSO2 0.2 LB/T OF STEEL BACT-PSD 

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H SO2

SCRAP MANAGEMENT PLAN. COMPLIANCE METHOD: SO2 CEM. 0.25 LB/T BACT-PSD 

IN-0109 BETA STEEL CORP. 5/30/2003 STEEL FURNACE MELTSHOP MS 1100000 T/YR SO2 0.33 LB/T BACT-PSD 

NC-0064 NUCOR STEEL 4/20/1999

STEEL PLANT, MELT SHOP (EAF,LMS,CSC) MS 250 T/H SO2

SCRAP STEEL MANAGEMENT PLAN 0.35 LB/T BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H SO2 0.7 LB/T BACT-PSD 

IL-0068

KEYSTONE STEEL & WIRE COMPANY 6/1/2000 FURNACE, EAF & LMF MS 1200000 T/Y SO2

USE OF LOW SULFUR INJECTION COKE (0.65% OR LESS). WORK PRACTICES 2

LB/T STEEL PRODUCED BACT-PSD

AR-0033

NUCOR YAMATO STEEL COMPANY 3/28/2000

2 ELECTRIC ARC FURNACES,MELTSHOP, TUNDISH MS 450 T/H SO2

LOW SULFUR COKE AND SCRAP MANAGEMENT 67.5 LB/H BACT-PSD 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS SO2 SCRAP MANAGEMENT 0.35 LB/T STEEL NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS SO2 SCRAP MANAGEMENT 0.35 LB/T STEEL 

BACT-PSD SO2 and SOx 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

MS and EAF RBLC SO2 and SOx BACT Limits Summary

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-C

BASIS 

TX-0417 NUCOR CORP. 1/15/2003 ELECTRIC ARC FURNACE EAF NOX

OXY-FUEL BURNERS AND GOOD ENGINEERING PRACTICES 0.3 LB/T BACT-PSD

AR-0077 BLUEWATER PROJECT 7/22/2004 ELECTRIC ARC FURNACE (EAF) EAF 350 t/h NOX LOW NOX BURNERS 0.35 LB/T BACT-PSD

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H NOX

LOOKED AT SCR, SNCR, AND FGR ALL INFEASIBLE 0.35 LB/T BACT-PSD 

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, ELECTRIC ARC EAF 225 T/H NOX LOW NOX BURNER. 0.38 LB/T BACT-PSD

IN-0073

QUALITECH STEEL CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H NOX 0.5 LB/T BACT-PSD 

SC-0072

SMI STEEL - SOUTH CAROLINA 11/26/2001 EAF EAF 850000 T/YR NOX

LOW NOX OXY-FUEL" BURNERS MOUNTED IN EAF" 0.51 LB/T BACT-PSD

MI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF 560000 T/YR NOX 0.53

LB/T STEEL PRODUCED BACT-PSD 

TN-0155

NUCOR STEEL CORPORATION 11/6/2000 ELECTRIC ARC FURNACE EAF 150 T/H NOX

THE PROPER OPERATION OF THE EAF AND DEC SYSTEMS, OXY-FUEL NATURAL GAS BURNERS IN THE SHAFT, ELBOW BOX AND SIDEWALLS 0.7 LB/T BACT-PSD 

AR-0030

ARKANSAS STEEL ASSOCIATES 9/24/1998 ELECTRIC ARC FURNACE EAF 50 T/H NOX

DES WITH NO ADDON CONTROL (EXISTING) 1 LB/T BACT-PSD 

TN-0122

HOEGANAES CORPORATION 2/11/2000 ELECTRIC ARC FURNACE (EAF) EAF 45 MVA/70.4 MMBNOX LOW NOX BURNERS 11.04 LB/H BACT-PSD 

NY-0094

NUCOR AUBURN STEEL 6/22/2004 EAF EAF 110 t/h NOX 27.32 LB/H BACT-PSD 

AL-0202 CORUS TUSCALOOSA 6/3/2003 ELECTRIC ARC FURNACE EAF 160 T/H NOX 56 LB/H BACT-PSD IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR NOX

LOW NOX/OXYFUEL BURNERS AND COMBUSTION CONTROLS. 70 LB/H BACT-PSD 

AL-0197

NUCOR STEEL DECATUR, LLC 7/11/2002 ELECTRIC ARC FURNACE, (2) EAF 440 T/H NOX 176 LB/H BACT-PSD 

FL-0192

AMERISTEEL CORPORATION 9/28/1999

ELECTRIC ARC FURNACE AND MELT SHOP MS 720000 T/YR NOX

COMBUSTION PRACTICES. EMISSION LIMIT UNITS: LB/T OF STEEL (PRIMARY), LB/H 24 HR AVE (ALTERNATE). ADDITIONAL EMISSION LIMIT: 118.8 T/YR 0.33 LB/T BACT-PSD 

WI-0206 SAUKVILLE PLANT 12/19/2003 MELT SHOP, P01, S01 MS 137.5 T/D NOX

DEC (DIRECT EVACUATION CONTROL) AND LOW NOX SUPPLEMENTAL BURNERS. ALSO REQUIRES CONTROL OF DEC AND EAF OPERATING PARAMETERS. 0.33 LB/T BACT-PSD

page 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 2
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-C

BASIS 

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H NOX

NATURAL GAS FIRED OXY FUEL BURNERS, COMPLIANCE METHOD: NOX CONTINUOUS EMISSIONS MONITOR. 0.35 LB/T BACT-PSD 

IN-0109 BETA STEEL CORP. 5/30/2003 STEEL FURNACE MELTSHOP MS 1100000 T/YR NOX 0.45 LB/T BACT-PSD 

NC-0064 NUCOR STEEL 4/20/1999

STEEL PLANT, MELT SHOP (EAF,LMS,CSC) MS 250 T/H NOX 0.51 LB/T BACT-PSD 

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR NOX LOW NOX BURNER 0.51 LB/T BACT-PSD

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H NO2

LOW NOX BURNERS; WORK PRACTICES 0.7 LB/T BACT-PSD 

OK-0048 GRIFFIN WHEEL CO 10/18/1999

ELECTRIC ARC FURNACE/LADLE METALLURGY FURNACE MS NOX 0.2 LB/T STEEL BACT-PSD

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS NOX 0.35 LB/T STEEL BACT-PSD 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS NOX 0.36 LB/T STEEL BACT-PSD IL-0068

KEYSTONE STEEL & WIRE COMPANY 6/1/2000 FURNACE, EAF & LMF MS 1200000 T/Y NOX

DEC, OXY/FUEL BURNERS. WORK PRACTICES 0.51

LB/T STEEL PRODUCED BACT-PSD

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS NOX 0.36 LB/T STEEL 

BACT-PSD NOx lb/t Steel Emission Limits

MIN 0.200 lb/t steel

MAX 1.000 lb/t steel

MEDIAN 0.360 lb/t steel

12th PERCENTILE 0.300 lb/t steel

COUNT 26 CASES

EAF and MS RBLC NOx BACT Limits Summa

page 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 2
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISSION LIMIT 2 UNITS

AR-0030 [a]

ARKANSAS STEEL ASSOCIATES 9/24/1998 ELECTRIC ARC FURNACE EAF 50 T/H CO

DES WITH AIR GAP FOR CO COMBUSTION (EXISTING) 0.6 LB/T BACT-PSD 300 LB/H

KY-0094

NORTH AMERICAN STAINLESS 12/1/2003 EAF EAF 154 t/batch CO 2 LB/T BACT-PSD 265.76 LB/H

AL-0129 IPSCO STEEL INC 10/16/1998 FURNACE, ELECTRIC ARC EAF 200 T/H CO

DEC WITH POSTCOMBUSTION 2 LB/T BACT-PSD 400 LB/H 

AR-0077 BLUEWATER PROJECT 7/22/2004 ELECTRIC ARC FURNACE (EAF) EAF 350 t/h CO AIR GAP 2 LB/T BACT-PSD

TX-0417 NUCOR CORP. 1/15/2003 ELECTRIC ARC FURNACE EAF CO

GOOD COMBUSTION PRACTICE 2 LB/T BACT-PSD

SC-0072

SMI STEEL - SOUTH CAROLINA 11/26/2001 EAF EAF 850000 T/YR CO

DESTRUCTION OF CO IN THE DUCT ELBOW AND WATER COOLED DUCTWORK 2 LB/T BACT-PSD

AR-0055

NUCOR YAMATO STEEL (ARMOREL) 10/10/2001 FURNACE, ELECTRIC ARC EAF 225 T/H CO

OXIDATION WITH SIDE DRAFT AIR GAP 2 LB/T BACT-PSD

TN-0155

NUCOR STEEL CORPORATION 11/6/2000 ELECTRIC ARC FURNACE EAF 150 T/H CO

PROPER OPERATION OF EAF AND DIRECT EVACUATION CONTROL SYSTEM, USE OF OXY-FUEL FOR POSTCOMBUSTION CONTROL; USE OF OXYGEN LANCING. 4 LB/T BACT-PSD 200 PPMV

IN-0073

QUALITECH STEEL CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H CO

POST COMBUSTION UNDER HOOD BY OXYGEN INJECTION AND OXY FUEL BURNERS & FOURTH HOLE WITH ADJUSTABLE GAP TO ALLOW AIR INTO WATER COOLED DUCTWORK FOR COMBUS 4.7 LB/T BACT-PSD 0 

OH-0246

THE TIMKEN COMPANY/FAIRCREST PLANT 2/20/2003 EAF EAF 200 T/H CO 4TH HOLE 4.8 LB/T BACT-PSD 960 LB/H

PA-0178

ELLWOOD QUALITY STEELS CO. 4/30/2001 ELECTRIC ARC FURNACE EAF 53 T/BATCH CO

DIRECT EVACUATION SYSTEM 5 LB/T BACT-PSD 1032.5 T/YR

MI-0376 MACSTEEL DIVISION 12/8/2003 2 ELECTRIC ARC FURNACES EAF 560000 T/YR CO 5

LB/T STEEL PRODUCED BACT-PSD 1400 T/YR

AR-0044

ARKANSAS STEEL ASSOCIATES 1/5/2001 FURNACE, ELECTIC ARC EAF 50 T/H CO

DIRECT SHELL EVACUATION CONTROL (DEC) SYSTEM WITH AIR GAP FOR CO COMBUSTION. 6 LB/T BACT-PSD 420 LB/H

NC-0065 AMERISTEEL CORP. 4/29/1999

STEEL PRODUCTION, ELECTRIC ARC FURNACE EAF 569400 T/YR CO

CONTROL: SEE PROCESS DESCRIPTION. EMISSION LIMIT IN LB/TON STEEL PRODUCED 6 LB/T BACT-PSD

WV-0018 ALLOY 12/16/2002 ELECTRIC ARC FURNACE EAF 18000 T/YR CO

DIRECT EVACUATION CANOPY USED TO INTRODUCE AMBIENT AIR MIX WITH EXHAUST TO PROMOTE CO COMBUSTION. 54 LB/H BACT-PSD 25.22 LB/T 

TN-0122

HOEGANAES CORPORATION 2/11/2000 ELECTRIC ARC FURNACE (EAF) EAF 45 MVA/70.4 MMBCO

COMBUSTION AIR GAP BETWEEN THE WATER-COOLED DUCT AND THE ELBOW OFF 152.9 LB/H BACT-PSD 2.77 LB/T

NY-0094 NUCOR AUBURN STEEL 6/22/2004 EAF EAF 110 t/h CO

DIRECT SHELL EVACUATION (DSE) CONTROLS TO LIMIT CO EMISSIONS. 202.4 LB/H BACT-PSD 2 LB/T

AL-0202 CORUS TUSCALOOSA 6/3/2003 ELECTRIC ARC FURNACE EAF 160 T/H CO

DIRECT EVACUATION CANOPY 320 LB/H BACT-PSD 2 LB/T

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR CO

DEC AIR GAP AND POST COMBUSTION CHAMBER 400 LB/H BACT-PSD 2 LB/T STEEL

AL-0197

NUCOR STEEL DECATUR, LLC 7/11/2002 ELECTRIC ARC FURNACE, (2) EAF 440 T/H CO 880 LB/H BACT-PSD 2 LB/T

IL-0068

KEYSTONE STEEL & WIRE COMPANY 6/1/2000 FURNACE, EAF & LMF MS 1200000 T/Y CO

DEC, OXY/FUEL BURNERS, COMBUSTION CHAMBER. WORK PRACTICES 1.34

LB/T STEEL PRODUCED BACT-PSD 1.34

LB/TON STEEL PRODUCE

IN-0108 NUCOR STEEL 11/21/2003

EAF, AOD VESSELS, DESULFURIZATION, & OTHER PROCESS MS 502 T/H CO

DIRECT SHELL EVACUATION (DSE). COMPLIANCE METHOD: CO CEM 2 LB/T BACT-PSD 1004 LB/H

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONS CO 2.76 LB/T OF STEEL BACT-PSD 414 LB/H

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT DATE PROCESS NAME 

Proc 

Type

THROUGH

PUT UNITS

POLLUTANT CONTROL EQUIPMENT EMISSION LIMIT 1 UNITS CASE-BY-CASE BASIS EMISSION LIMIT 2 UNITS

FL-0192

AMERISTEEL CORPORATION 9/28/1999

ELECTRIC ARC FURNACE AND MELT SHOP MS 720000 T/YR CO

DIRECT EVACUATION CONTROL/ AIR GAP OXIDATION. EMISSION LIMIT UNITS: LB/T OF STEEL (PRIMARY), LB/H 24 HR AVE (ALTERNATE)ADDITIONAL EMISSION LIMIT: 1080 T/YR 3 LB/T BACT-PSD 300 LB/H

WI-0206 SAUKVILLE PLANT 12/19/2003 MELT SHOP, P01, S01 MS 137.5 T/D CO

DEC (DIRECT EVACUATION CONTROL) WITH A SECOND HOLE" TO INTRODUCE AIR FOR SECONDARY COMBUSTION AND THE CONTROL OF OPERATING PARAMETERS AND CARBON SOURCE TO ENSURE PROPER OPERATION OF THE EMISSIONS UNITS" 3.5 LB/T BACT-PSD

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR CO

DIRECT EVACUATION CONTROL (DEC) SYSTEM 3.5 LB/T BACT-PSD

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H CO

DUCTING/EXTERNAL COMBUSTION CHAMBER AT 12 MMBTU/HR; WORK PRACTICES 4 LB/T BACT-PSD 860 LB/H 

NC-0064 NUCOR STEEL 4/20/1999

STEEL PLANT, MELT SHOP (EAF,LMS,CSC) MS 250 T/H CO

DIRECT SHELL EVACUATION (DSE) PLUS COMBUSTION CHAMBER FOLLOWING CONSTEEL CONVEYOR PREHEATING SECTION. 4 LB/T BACT-PSD 4380 T/YR

AR-0033

NUCOR YAMATO STEEL COMPANY 3/28/2000

2 ELECTRIC ARC FURNACES,MELTSHOP, TUNDISH MS 450 T/H CO AIR GAP 900 LB/H BACT-PSD 

PA-0235 KOPPEL STEEL CORP. 11/26/2003 MELT SHOP MS 598000 T/YR CO 1346 T/YR BACT-PSD 5 LB/T*OH-0285

NORTH STAR BHP STEEL, LTD 8/5/2003

ELECTRIC ARC FURNACE WITH TWO LADLE MELT FURNACES MS 315 T STEEL/H CO

DIRECT EVACUATION CONTROL SYSTEM WITH AIR GAP, AND COOLED POST COMBUSTION CHAMBER WITH BURNERS 2362.5 LB/H BACT-PSD 10347.8

T/ROLLING 12-MONTHS 

*NC-0112 NUCOR STEEL 11/23/2004 MELT SHOP MS CO

DIRECT SHELL EVACUATION (DSE) VIA THE CONSTEEL PROCESS PLUS COMBUSTION CHAMBER (AIR GAP) 2.3 LB/T STEEL 2518.5 T/YR

NC-0113 NUCOR STEEL 11/23/2004 MELT SHOP MS CO

DIRECT SHELL EVACUATION (DSE) VIA THE CONSTEEL PROCESS PLUS COMBUSTION CHAMBER (AIR GAP) 2.3 LB/T STEEL 2518.5 TONS

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

[a] Billy Ferguson of Arkansas Steel Associates, said on 6/8/06 that they were having no problems meeting the limit EAF and MS RBLC CO BACT Limits Summary0.6 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 Emis

Limit 

AZ-0047

WELLTON MOHAWK GENERATING STATION 12/1/2004 AUXILIARY BOILER

Sm Gas Blrs & Htrs 38 MMBTU/H

Visible Emissions (VE) N 10 % OPACITY BACT-PSD 

OH-0254

DUKE ENERGY WASHINGTON COUNTY LLC 8/14/2003 BOILER

Sm Gas Blrs & Htrs 30.6 MMBTU/H

Visible Emissions (VE) N 20 % OPACITY BACT-PSD 

MS-0057

SMEPA - SILVER CREEK GENERATING 5/29/2003 BOILERS, NATURAL GAS (3)

Sm Gas Blrs & Htrs 5.4 MMBTU/H

Visible Emissions (VE) N 40 % OPACITY Other Case-by-Case 

OH-0276 CHARTER STEEL 4/14/2003

BOILER FOR VACUUM OXYGEN DEGASSER VESSEL

Sm Gas Blrs & Htrs 25 MMBTU/H

Visible Emissions (VE) N 20 % OPACITY 

GA-0098 RINCON POWER PLANT 3/24/2003 AUXILIARY BOILER

Sm Gas Blrs & Htrs 83 MMBTU/H

Emissions (VE) N 10 % OPACITY Other Case-by-Case 

WA-0291

WALLULA POWER PLANT 1/3/2003 BOILER, AUXILIARY

Sm Gas Blrs & Htrs 55.3 MMBTU/H

Visible Emissions (VE) N 10 % OPACITY Other Case-by-Case 

IN-0116 ENERGY CO., INC. 12/23/2002

, ,

NATURAL GAS Blrs & Htrs 2.4 MMBTU/H Emissions N 20 % OPACITY BACT-PSD 27 % OPAC

GA-0101

MURRAY ENERGY FACILITY 10/23/2002 BOILER, AUXILIARY

Sm Gas Blrs & Htrs 31.4 MMBTU/H

Visible Emissions (VE) P GOOD COMBUSTION PRACTICE 10 % OPACITY BACT-PSD 

AL-0192

HONDA MANUFACTURING OF ALABAMA, LLC 10/18/2002 BOILERS, NATURAL GAS, (3)

Sm Gas Blrs & Htrs 30 MMBTU/H

Visible Emissions (VE) N 10 % OPACITY BACT-PSD 

WI-0195 SENA NIAGARA MILL 10/18/2002

PROCESS HEATER, PAPER MACHINE P51

Sm Gas Blrs & Htrs 34.4 MMBTU/H

Visible Emissions (VE) P

NATURAL GAS AS FUEL, GOOD COMBUSTION PRACTICE. 20 % OPACITY Other Case-by-Case 

KY-0087

QUEBECOR WORLD FRANKLIN 7/12/2002 BOILER, NATURAL GAS, #4

Sm Gas Blrs & Htrs 33.5 MMBTU/H

Visible Emissions (VE) N 20 % OPACITY BACT-PSD 

OH-0264

NORTON ENERGY STORAGE, LLC 5/23/2002

RECUPERATOR PRE-HEATERS (9)

Sm Gas Blrs & Htrs 12.84 MMBTU/H

Visible Emissions (VE) N 10 % OPACITY BACT-PSD 

OH-0264

NORTON ENERGY STORAGE, LLC 5/23/2002 FUEL SUPPLY HEATERS (9)

Sm Gas Blrs & Htrs 11.45 MMBTU/H

Visible Emissions (VE) N 10 % OPACITY BACT-PSD 

IA-0058

GREATER DES MOINES ENERGY CENTER 4/10/2002 AUXILIARY BOILER

Sm Gas Blrs & Htrs 68 MMBTU/H

Visible Emissions (VE) N 0 % OPACITY BACT-PSD 

IA-0058

GREATER DES MOINES ENERGY CENTER 4/10/2002 EFFICIENCY HEATER

Sm Gas Blrs & Htrs

Visible Emissions (VE) N 0 % OPACITY BACT-PSD 

IA-0058

GREATER DES MOINES ENERGY CENTER 4/10/2002 DEW POINT HEATER

Sm Gas Blrs & Htrs

Visible Emissions (VE) N 0 % OPACITY BACT-PSD 

OH-0257

JACKSON COUNTY POWER, LLC 12/27/2001 AUXILIARY BOILER

Sm Gas Blrs & Htrs 76 MMBTU/H

Visible Emissions (VE) N 20 % OPACITY BACT-PSD 

MS-0058

CHOCTAW GAS GENERATION, LLC 12/13/2001 HEATER, FUEL GAS

Sm Gas Blrs & Htrs 5.6 MMBTU/H

Visible Emissions (VE) N 40 % OPACITY Other Case-by-Case 

OH-0251

CENTRAL SOYA COMPANY INC. 11/29/2001 BOILER, NATURAL GAS

Sm Gas Blrs & Htrs 91.2 MMBTU/H

Visible Emissions (VE) N 20 % OPACITY BACT-PSD 

TX-0378

LA PORTE POLYPROPYLENE PLANT 11/5/2001 PACKAGE BOILER BO-4

Sm Gas Blrs & Htrs 60 MMBTU/H

Visible Emissions (VE) N NONE INDICATED 5 % OPACITY N/A 

PR-0007

COGENERATION PLANT (AES-PRCP) 10/29/2001 LIMESTONE DRYER

Sm Gas Blrs & Htrs 13 MMBTU/H

Visible Emissions (VE) A ESP AND BAGHOUSES 20 % OPACITY BACT-PSD 27 % OPAC

OH-0265 DRESDEN ENERGY LLC 10/16/2001 BOILER, NATURAL GAS

Sm Gas Blrs & Htrs 49 MMBTU/H

Visible Emissions (VE) N 20 % OPACITY BACT-PSD 

IN-0110

COGENTRIX LAWRENCE CO., LLC 10/5/2001

BOILER, AUXILIARY, NATURAL GAS

Sm Gas Blrs & Htrs 35 MMBTU/H

Visible Emissions (VE) P

CLEAN FUEL, GOOD COMBUSTION PRACTICES 20 % OPACITY BACT-PSD 

OH-0263

FREMONT ENERGY CENTER, LLC 8/9/2001 AUXILIARY BOILER

Sm Gas Blrs & Htrs 80 MMBTU/H

Visible Emissions (VE) N 10 % OPACITY BACT-PSD 

AK-0047

MILNE POINT PRODUCTION FACILITY 7/13/2001

HEATERS (2), H-5302A AND H5302B Sm Gas Blrs & Htrs 35 MMBTU/H 

Visible Emissions (VE) N 20 % OPACITY N/A 

AK-0047

MILNE POINT PRODUCTION FACILITY 7/13/2001

HEATERS (2), H-4510A AND H4510B Sm Gas Blrs & Htrs 14.4 MMBTU/H 

Visible Emissions (VE) N 20 % OPACITY N/A 

AK-0047

MILNE POINT PRODUCTION FACILITY 7/13/2001

HEATERS (2), H-5701A AND H5701B Sm Gas Blrs & Htrs 29 MMBTU/H 

Visible Emissions (VE) N 20 % OPACITY N/A 

SC-0061 COLUMBIA ENERGY LLC 4/9/2001 HOT WATER HEATERS (2)

Sm Gas Blrs & Htrs 11 MMBTU/H

Visible Emissions (VE) P CLEAN FUEL 20 % OPACITY N/A 

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 Emis

Limit 

OH-0255

PSEG WATERFORD ENERGY LLC 3/29/2001 BOILER, NATURAL GAS

Sm Gas Blrs & Htrs 85.2 MMBTU/H

Visible Emissions (VE) N 20 % OPACITY N/A 

OH-0258

PRO TEC COATING COMPANY 2/15/2001 BOILERS (4)

Sm Gas Blrs & Htrs 20.9 MMBTU/H

Visible Emissions (VE) N 20 % OPACITY N/A 

SC-0065

BROAD RIVER INVESTORS - GAFFNEY 12/21/2000

HOT WATER HEATERS, NAT. GAS (2)

Sm Gas Blrs & Htrs 11 MMBTU/H 

Visible Emissions (VE) P

GOOD COMBUSTION CONTROL, CLEAN BURNING FUELS 20 % OPACITY Other Case-by-Case 

BACT-PSD PM gr/dscf Emission Limits

MIN 10 % Opacity MIN 5 % Opa

MAX 20 % Opacity MAX 40 % Opa

MEDIAN 20 % Opacity MEDIAN 20 % Opa

COUNT 14 CASES COUNT 13 CASES

Small Natural Gas Boler RBLC Opacity BACT Limits Summary

Other (non-BACT)-case-by-case 

gr/dscf Emission Limits

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 Emis

Limit 

WI-0098

CHARTER STEEL DIVISION 6/9/2000

MELTING SHOP (ELECTRIC ARC FURNACE) MS 550000 T/YR VE P PROCESS CONTROL 20 % OPACITY N/A 

MI-0275

RAVENNA CASTING CENTER, INC. 4/14/2000 IRON MELT SHOP MS 27 T/H VE A FABRIC FILTER 5 % OPACITY Other Case-by-Case 

TN-0122

HOEGANAES CORPORATION 2/11/2000 MELT SHOP OPERATIONS MS VE A FABRIC FILTER 20 % OPACITY Other Case-by-Case 

FL-0192

AMERISTEEL CORPORATION 9/28/1999 MELT SHOP MS 720000 T/YR VE A BAGHOUSES 6 % OPACITY BACT-PSD 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

FURNACES, EAF & LRF, COMBINED MELTSHOP MS 215 T/H VE N 3 % OPACITY BACT-PSD 0 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 MELTSHOP #3 MS 150 BILLET TONSVE A CLEANING MAIN BAGHOUSE WITH 3 FANS AND 2 REVERSE AIR FANS, CASTER 10 % OPACITY BACT-PSD 20 % OPAC

TX-0332 MIDLOTHIAN STEEL 4/24/2000 HOODS A MS OPACITY N NONE INDICATED 10 % OPACITY N/A TX-0332

CHAPPARRAL STEEL MIDLOTHIAN STEEL MILL 4/24/2000

MELTSHOP OVERHEAD CANOPY HOODS B MS OPACITY N NONE INDICATED 10 % OPACITY N/A 

IN-0073

QUALITECH STEEL CORP. 10/31/1996 ELECTRIC ARC FURNACE (EAF) EAF 135 T/H VE A DIRECT SHELL EVAC; BAGHOUSE 3 % OPAC BACT-PSD 0 

*OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (STACK

EMISSIONS) EAF 70 T/H VE A BAGHOUSE AND DUST HANDLING SYSTEM 3 % OPACITY BACT-PSD 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 ELECTRIC ARC FURNACE EAF 350 t/h VE N 3 % OPACITY 0 % OPAC

CO-0054

CF & I STEEL L.P. DBA ROCKY MOUNTAIN STEEL MILLS 6/21/2004 ELECTRIC ARC FURNACE (EAF) EAF 156 T/H VE A BAG FILTERS 3 % OPACITY Other Case-by-Case 

FL-0192

AMERISTEEL CORPORATION 9/28/1999 ELECTRIC ARC FURNACE EAF 720000 T/YR VE A BAGHOUSES 3 % OPACITY BACT-PSD 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999 FURNACE, ELECTRIC ARC (EAF) EAF 200 T/YR VE A BAGHOUSE 3 % OPACITY BACT-PSD *OH-0294

NUCOR STEEL MARION, INC. 8/18/2005

ELECTRIC ARC FURNACE (FUGITIVE EMISSIONS) EAF 70 T/H VE A

USE OF SEGMENTED CANOPY HOOD, SCAVENGER DUCTING, CROSS-DRAFT PARTITIONING AND CLOSED ROOF MONITORS. 6 % OPACITY 

OH-0276 CHARTER STEEL 4/14/2003 ELECTRIC ARC FURNACE EAF 110 T/H MELT VE A BAGHOUSE 6 % OPACITY 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 7, P905 EAF 85 T/H VE A BAGHOUSE 6 % OPACITY N/A 

OH-0245

REPUBLIC TECHNOLOGIES INTERNATIONAL 1/27/1999

ELECTRIC ARC FURNACE (EAF) NO. 9, P907 EAF 165 T/H VE A BAGHOUSE 6 % OPACITY N/A 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998 ELECTRIC ARC FURNACE, ES1 EAF 215 T/H VE B MELT SHOP EVACUATION PLUS BAGHOUSE 6 % OPACITY BACT-PSD 0 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 ELECTRIC ARC FURNACE (EAF) EAF 160 TONS VE A

DIRECT SHELL EVACUATION SYSTEM, OVERHEAD CANOPY, DUCTED TO MAIN BAGHOUSE. 6 % OPACITY BACT-PSD 

UT-0061

NUCOR STEEL CORPORATION 8/29/1997

ELECTRIC ARC FURNACES (#1 & #2) EAF 65 T (EACH) OPACITY N 3 % OPACITY BACT-PSD 

BACT-PSD PM gr/dscf Emission Limits

MIN 3 % Opacity MIN 3 % Opa

MAX 6 % Opacity MAX 20 % Opa

MEDIAN 3 % Opacity MEDIAN 6 % Opa

COUNT 10 CASES COUNT 10 CASES

EAF & Melt Shop RBLC Opacity BACT Limits Summary

Other (non-BACT)-case-by-case 

gr/dscf Emission Limits

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 Emis

Limit 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 LADLE METALLURGY FURNACE LMF 350 t/h VE A BAGHOUSE 3 % OPACITY 0 % OPAC

IN-0108 NUCOR STEEL 11/21/2003

LADLE METALLURGY FURNACES (2) LMF 502 T/H VE A BAGHOUSE 3 % OPACITY BACT-PSD 

OH-0276 CHARTER STEEL 4/14/2003 LADLE METALLURGY FURNACE LMF 110 T/H VE A BAGHOUSE RACT TN-0122

HOEGANAES CORPORATION 2/11/2000

LADLE METALLURGY FACILITY (LMF) LMF 110650 LB MOLTEN VE N NONE INDICATED 10 % OPACITY Other Case-by-Case 

OH-0245

TECHNOLOGIES INTERNATIONAL 1/27/1999

LADLE METALLURGY FACILITY (LMF), P123 LMF VE A BAGHOUSE 5 % OPACITY N/A 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 LADLE METALLURGICAL FURNACE (LMF) LMF VE A BAGHOUSE 20 % OPACITY BACT-PSD 

BACT-PSD PM gr/dscf Emission Limits

MIN 3 % Opacity MIN 3 % Opa

MAX 20 % Opacity MAX 10 % Opa

MEDIAN 12 % Opacity MEDIAN 3 % Opa

COUNT 2 CASES COUNT 3 CASES

LMF RBLC Opacity BACT Limits Summary

Other (non-BACT)-case-by-case 

gr/dscf Emission Limits

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 Emis

Limit 

IN-0073

QUALITECH STEEL CORP. 10/31/1996

MATL. CRUSHING, HANDLING, & STORAGE MH & Fug 5 LB/H PM10 P

WORK PRACTICES; VE AVERAGE AS CALCULATED BY METHOD 9. 3 % OPAC BACT-PSD 

MN-0061 ERIE NUGGET 6/26/2005 COAL & FLUX UNLOADING MH & Fug 4000000 DSCF OPACITY A FF 10 % OPACITY BACT-PSD MN-0061 ERIE NUGGET 6/26/2005 RAIL LOADOUT MH & Fug 4000000 DSCF OPACITY A FF 10 % OPACITY BACT-PSD MN-0061 ERIE NUGGET 6/26/2005

MATERIAL TRANSFER OPERATIONS MH & Fug 6000000 DSCF/H OPACITY A FF 10 % OPACITY BACT-PSD 

MN-0061 ERIE NUGGET 6/26/2005

FUGITIVES FROM STORAGE PILES MH & Fug OPACITY P FUGITIVE DUST CONTROL PLAN. 5 % OPACITY BACT-PSD 

MN-0061 ERIE NUGGET 6/26/2005 FUGITIVES FROM PAVED ROADS MH & Fug OPACITY P FUGITIVE DUST CONTROL PLAN. 5 % OPACITY BACT-PSD 

SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 DUST HANDLING SYSTEM MH & Fug OPACITY A BAGHOUSE 10 % OPACITY BACT-PSD 

SC-0075 DARLINGTON COUNTY 1/8/1998 EAF FLUX/ALLOY SYSTEM MH & Fug OPACITY A BAGHOUSE, BIN VENT FILTER 20 % OPACITY BACT-PSD SC-0075

NUCOR STEELDARLINGTON COUNTY 1/8/1998 LMF FLUX/ALLOY SYSTEM MH & Fug OPACITY A BIN VENT FILTERS 20 % OPACITY BACT-PSD 

UT-0061

NUCOR STEEL CORPORATION 8/29/1997 ROADS (PAVED) MH & Fug OPACITY P SWEPT OR WATER FLUSHED 10 % OPACITY BACT-PSD 

UT-0061

NUCOR STEEL CORPORATION 8/29/1997 ROADS (UNPAVED) MH & Fug OPACITY P

WATER SPRAYED OR CHEMICALLY TREATED 20 % OPACITY Other Case-by-Case 

UT-0061

NUCOR STEEL CORPORATION 8/29/1997

FUGITIVES / STOCK PILES / TRANSFER POINTS MH & Fug OPACITY A FABRIC FILTERS 10 % OPACITY BACT-PSD 

IN-0119 AUBURN NUGGET 5/31/2005 COAL CAR UNLOADING MH & Fug 165 T/H VE N 3 % OPACITY BACT-PSD IN-0119 AUBURN NUGGET 5/31/2005 ROADS MH & Fug VE P FOLLOW FUGITIVE DUST PLAN 10 % OPACITY BACT-PSD OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR BOF MH & Fug VE A THREE BAGHOUSES 0 % OPACITY 

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR EAF MH & Fug 2.5 MM t/yr VE A BAGHOUSE AND VENT FILTERS 10 % OPACITY 0 % OPAC

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005 MATERIAL HANDLING FOR LMF MH & Fug 2.5 mm t/yr VE A BIN VENT FILTERS 0 % OPACITY 0 % OPAC

OH-0292

WHEELING PITTSBURGH STEEL CORPORATION 1/6/2005

BASIC OXYGEN FURNACES (2 VESSELS), FUGITIVE EMISSIONS MH & Fug 375 t/h VE N 20 % OPACITY BACT-PSD 

IN-0108 NUCOR STEEL 11/21/2003 EAF DUST TREATMENT MH & Fug 100000 LB/H VE A

SCRUBBER, COMPLIANCE BY SCRUBBER MONITORING 10 % OPACITY BACT-PSD 

IN-0108 NUCOR STEEL 11/21/2003 EAF DUST HANDLING MH & Fug 100000 LB/H VE P BIN VENTS 10 % OPACITY BACT-PSD OH-0276 CHARTER STEEL 4/14/2003 SILOS CARBON, LIME, AND DUST MH & Fug 50 T/H VE A BIN VENT 10 % OPACITY OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

LOAD IN AND LOAD OUT OF COKE/COAL STORAGE PILES MH & Fug VE A

LOAD-IN COAL, COKE, AND COKE BREEZE W/ STACKING TUBE; LOAD-IN COAL W/WATER SPRAYS/DUST SUPPRESSANT; LOAD-OUT COAL UNDER PILE GRAVITY FEED AND WATER SPRAY; LOAD-OUT COKE W/ UNDER PILE GRAVITY FEED. 0 % OPACITY BACT-PSD 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

COAL HANDLING, CONVEYING, AND TRANSFER MH & Fug 6602850 T/YR VE P

RAIL CAR BOTTOM DUMPING AND ENCLOSED; BELT CONVEYORS ENCLOSED; WET AND/OR CHEMICAL SUPPRESSION 20 % OPACITY BACT-PSD 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001

COKE AND BREEZE CRUSHING/SCREENING/CONVEYING MH & Fug VE A BAGHOUSE WITH 0.008 GR/DSCF 20 % OPACITY BACT-PSD 

OH-0272

HAVERHILL NORTH COKE COMPANY 2/27/2001 ROADWAYS AND PARKING MH & Fug VE P

WATERING AS SUFFICIENT FREQUENCY TO ENSURE COMPLIANCE 0 % OPACITY BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 LMS BAGHOUSE SILO MH & Fug VE P BIN VENT FILTER 3 % OPACITY BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001

DUMPING STORAGE & TRANSFER MH & Fug VE P WATERING STORAGE PILES 5 % OPACITY BACT-PSD 

IN-0090 NUCOR STEEL 1/19/2001 TRANSPORTATION ON ROADS MH & Fug VE A 10 % OPACITY BACT-PSD IN-0090 NUCOR STEEL 1/19/2001

STORAGE SILO FOR BLASTING MEDIA MH & Fug 1000 DSCFM VE A BIN VENT 3 % OPACITY BACT-PSD 

IN-0079 STEEL DYNAMICS, INC. 7/7/1999

SLAG, HANDLING AND PROCESSING MH & Fug 262800 T/YR VE B

WATER SUPPRESSION AND MINIMIZING DROP HEIGHTS OPACITY REQUIREMENTS, SIX MINUTE AVERAGING 10 % OPAC BACT-PSD 0 

IN-0080 STEEL DYNAMICS, INC. 7/7/1999

HANDLING AND PROCESSING, SLAG MH & Fug 150 T/YR VE B

WATER SUPPRESSION AND MINIMIZING DROP HEIGHTS OPACITY, 3-10%, SIXMINUTE AVERAGE 3 % OPAC BACT-PSD 0 

VA-0240

CHAPARRAL STEEL COMPANY 4/24/1998

DUST HANDLING SYSTEM, BAGHOUSE MH & Fug 0 VE N 10 % OPACITY BACT-PSD 0 

IN-0073

QUALITECH STEEL CORP. 10/31/1996

MATL. RECEIVING, HANDLING, & STORAGE MH & Fug 8000 T CAPACITY VE A

RECEIVED IN SHED, SEALED HOPPERS AT RAIL CAR, ENCLOSED CONVEYORS AND FILTERS ON STORAGE BIN EXHAUST. VE AVERAGE AS CALCULATED BY METHOD 9. 3 % OPAC BACT-PSD 0 

MH & Fug RBLC Opacity BACT Limits Summary

page 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 Revision
Minnesota Steel Industries Air Quality Permit Application

BACT 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 feasible

RBLC ID FACILITY NAME PERMIT 

DATE 

PROCESS NAME Proc 

Type

THROUGHPU

T 

UNITS POLLUTANT CONTROL CODE CONTROL EQUIPMENT EMISSION LIMIT 1 Emission Limit 1 Unit CASE-BY- CASE BASIS EMISSION LIMIT 2 Emis

Limit 

BACT-PSD PM gr/dscf Emission Limits

MIN 3 % Opacity MIN 10 % Opa

MAX 20 % Opacity MAX 20 % Opa

MEDIAN 10 % Opacity MEDIAN 10 % Opa

COUNT 25 CASES COUNT 4 CASES

Other (non-BACT)-case-by-case 

gr/dscf Emission Limits

page 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 
P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 

2007)\Volume II\Attachments\Attach M - Startup Shutdown BACT Updated May 3.doc Page 1 of 5 

1.1 Compliance with BACT during Startup, Shutdown and 

Malfunction 

For periods of startup, shutdown and malfunction, 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 per 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 fixed while the unit 

is operating or shutdowns due to unplanned equipment failures (malfunctions). Actions taken 

during annual maintenance inspections are designed to minimize the number of shutdowns 

due to malfunctions and maintenance during the remainder 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 emission control equipment operating at 

optimum control efficiency due to changing conditions. In addition, some emissions control 

equipment must reach proper operating temperatures before 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 

operating practices for minimizing emissions, Minnesota Steel Industries will operate its 

facility so that emissions will not exceed the emissions to the rates listed in Attachment N, 

Table 2 at the emission units which cannot meet BACT limitations during startup and 

shutdown. The BACT report identifies those conditions where applicable BACT limitations 

for normal operations cannot be met at all times during startup, shutdown and malfunction. 

Specific measures, which Minnesota Steel will follow to minimize emissions as good air 

pollution control practices, include: 
P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 

2007)\Volume II\Attachments\Attach M - Startup Shutdown BACT Updated May 3.doc Page 2 of 5 

• 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 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 equipment 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 shutdowns of process units within the facility will 

be phased. This will minimize the number of sources, which at any given time; have 

excess emissions due to startup and shutdown activities. 

• During periods of malfunction, Minnesota Steel will identify and correct the cause of the 

malfunctions as soon as practicable, and/or will consider taking the malfunctioning 

equipment out of service until it can be operated in a manner consistent with the 

applicable environmental requirements. 

Minnesota Steel will prepare a startup, shutdown and malfunction plan specifying the actions 

to be taken during startup, shutdown and malfunctions, and when the requirements of the 

startup, shutdown and malfunction plan are applicable. 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 malfunction plan will be prepared prior to the 

initial startup of the facility. As noted above, plans for startup, shutdown and malfunction 

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 Table 1 that follows. 

Table 2 lists the proposed startup and shutdown emission limits the pelletizer waste gas 

stream with LoTOx controls are installed. If the LoTOx trial is successful these limits would 

apply after LoTOx controls are installed and operational. 
P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 

2007)\Volume II\Attachments\Attach M - Startup Shutdown BACT Updated May 3.doc Page 3 of 5 

Table 1 Emission Limits for Startup and Shutdown 

Source Pollutant 

Emission 

Control 

Equipment 

Performance 

Standard 

Mass Emission 

Limit 

Pelletizer 

Waste Gas 

NOx Best Practices for 

Minimizing 

Emissions 

NA 928 lb/hr NOx 

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 

NOx Good Combustion 

Practices 

Clean Fuels 

Best Practices for 

Minimizing 

Emissions 

NA 330 lb/hr NOx 

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 
P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 

2007)\Volume II\Attachments\Attach M - Startup Shutdown BACT Updated May 3.doc Page 4 of 5 

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 NOx

Ultra Low NOx

Burners/Low NOx

Burners with Flue 

Gas Recirculation 

Best Practices for 

Minimizing 

Emissions 

NA 

10 lb/hr NOx

3-hour Average 

S/U & S/D periods 

not to exceed 24 

hours 

DRI Process Heater NOx Ultra Low NOx

Burners 

Best Practices for 

Minimizing 

Emissions 

NA 

60.6 lb/hr NOx

3-hour Average 

S/U & S/D periods 

not to exceed 24 

hours 

PTS Gas Heater NOx

Ultra Low NOx

Burners/Low NOx

Burners with Flue 

Gas Recirculation 

Best Practices for 

Minimizing 

Emissions 

NA 

1.2 lb/hr NOx

3-hour Average 

S/U & S/D periods 

not to exceed 24 

hours 

Vacuum Degasser 

Boiler NOx

Low NOx Burners 

with Flue Gas 

Recirculation 

Best Practices for 

Minimizing 

Emissions 

NA 

10 lb/hr NOx

3-hour Average 

S/U & S/D periods 

not to exceed 24 

hours 

Melt Shop NOx Oxyfuel Burners 

and Direct –Shell 

Evacuation Control 

System no add-on 

controls 

Best Practices for 

Minimizing 

Emissions 

NA 110 lb/hr NOx

3-hour Average 

S/U periods not to 

exceed 36 hours 

S/D periods not to 

exceed 28 hours 
P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\Final Application (May 

2007)\Volume II\Attachments\Attach M - Startup Shutdown BACT Updated May 3.doc Page 5 of 5 

Table 2 Pelletizer Waste Gas Emission Limits for Startup and Shutdown with LoTOx 

Source Pollutant 

Emission 

Control 

Equipment 

Performance 

Standard 

Mass Emission 

Limit 

Pelletizer 

Waste Gas 

NOx LoTOx 

 Best Practices for 

Minimizing 

Emissions 

NA 92 lb/hr NOx 

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 Application

BACT Report -Attachment N - BACT Mass Emission Limits 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 Application

BACT Report -Attachment N - BACT Mass Emission Limits 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 Application

BACT Report -Attachment N - BACT Mass Emission Limits 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

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 3 of 7
Minnesota Steel Industries Air Quality Permit Application

BACT Report -Attachment N - BACT Mass Emission Limits 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 Application

BACT Report -Attachment N - BACT Mass Emission Limits 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 Application

BACT Report -Attachment N - BACT Mass Emission Limits 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 Application

BACT Report -Attachment N - BACT Mass Emission Limits 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 
Fugitive Dust Control Plan

Prepared for

Minnesota Steel Industries

April 2007

4700 West 77

th

Street

Minneapolis, MN 55435-4803

Phone: (952) 832-2600

Fax: (952) 832-2601
i

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 O - Fugitive Control Plan - Revised 04_30_07.doc

Attachment O

Minnesota Steel Industries, LLC

Fugitive Dust Control Plan

Table of Contents

1.0 Introduction.............................................................................................................................................1

2.0 Plan Objectives .......................................................................................................................................2

3.0 Fugitive Emissions Sources....................................................................................................................3

3.1 Unpaved Roads...........................................................................................................................3

3.2 Paved Roads................................................................................................................................3

3.3 Stockpiles....................................................................................................................................3

3.4 Materials Transfer Points............................................................................................................4

3.5 Tailings Basin .............................................................................................................................6

4.0 Operating Practices and Control Measures.............................................................................................7

4.1 Haul Roads and Service Roads (FS 007, FS 008).......................................................................7

4.2 Paved Roads (FS 070).................................................................................................................8

4.3 Stockpiles (FS 009, FS 012, FS 020, FS 023, FS 026, FS 029, FS 042, FS 052, FS 076)..........9

4.4 Material Transfer Points (FS 002, FS 003, FS 004, FS 005, FS 006, FS 011, FS 013, FS 014,

FS 019, FS 021, FS 022, FS 024, FS 025, FS 027, FS 028, FS 030, FS 031, FS 032, FS 033,

FS 034, FS 035, FS 037, FS 038, FS 040, FS 041, FS 043, FS 044, FS 045, FS 046, FS 047,

FS 048, FS 049, FS 050, FS 051, FS 053, FS 054, FS 055, FS 056, FS 057, FS 058, FS 059,

FS 060, FS 061, FS 062, FS 063, FS 064, FS 065, FS 066, FS 067, FS 068, FS 069, FS 070,

FS 075)........................................................................................................................................9

4.5 Tailings Basin (FS 008, FS 016, FS 017, FS 018)....................................................................10

5.0 Recordkeeping .....................................................................................................................................12

6.0 Training.................................................................................................................................................13

Tables

Table 1: List of Fugitive Sources
Page 1 of 1

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 O - Fugitive Control Plan - Revised 04_30_07.doc

1.0 Introduction

Minnesota Steel Industries, LLC (Minnesota Steel) is applying for a total facility permit, including

the authorization to construction a new facility and a Part 70 operating permit, which will authorize

Minnesota Steel Industries to mine iron ore and to produce finished steel near Nashwauk, Minnesota.

As part of the permitting process Minnesota Steel Industries is required to perform a Best Available

Control Technology (BACT) analysis. The BACT analysis cites the implementation of a Best

Management Practices (BMP) plan for controlling fugitive emissions.

Minnesota Steel Industries is submitting this BMP in conjunction with the air permit application for

the facility. The plan is based on dust control plan practices used by the mining industry on the

Mesabi Iron Range of northern Minnesota.
Page 2 of 2

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 O - Fugitive Control Plan - Revised 04_30_07.doc

2.0 Plan Objectives

The Fugitive Control Plan identifies Minnesota Steel Industries control measures and practices to

minimize and control fugitive dust as required by the Title V permit. The plan defines the following:

• Procedures that Minnesota Steel Industries personnel will follow to control emissions

• Fugitive dust levels requiring corrective actions

• Steps that will be followed to bring emissions within appropriate ranges

• Steps that Minnesota Steel Industries will take to demonstrate that corrective procedures are

followed and to verify the facility is controlling avoidable fugitive emissions

To meet these objectives, the Fugitive Control Plan:

• Identifies all fugitive emission sources listed in the Title V permit application

• Identifies the primary and contingent control measures and practices to control and minimize

fugitive emissions.

• Identifies visible emissions observation and corrective action requirements.

• Identifies fugitive dust control recordkeeping requirements.

• Identifies fugitive dust control notification requirements.

• Describes fugitive dust control training elements.
Page 3 of 3

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 O - Fugitive Control Plan - Revised 04_30_07.doc

3.0 Fugitive Emissions Sources

Table 1 lists the fugitive emission sources identified in the Title V permit, briefly describes the

measures and practices employed to control fugitive emissions at each source and identifies the

fugitive emission sources that require visible emission observation. These sources are further

described below.

3.1 Unpaved Roads

Haul road sources subject to the plan include:

• Haul Road Emissions (FS 007). This source involves 205-ton trucks hauling materials on

unpaved roads. The materials being hauled include surface overburden and waste rock/lean

taconite (hauled between the pit and their respective discharge areas), taconite ore (hauled

between the pit and the primary crusher) and cobber reject (hauled from the crushers to its

designated stockpile). The haul roads on the site will be approximately 10 miles long and

fifty feet wide lanes.

• Service Road Emissions (FS 008). This source involves light vehicles traveling on unpaved

roads between the main plant area and the crusher, mining and tailings basin facilities. The

service road will be approximately 13 miles long and fifty feet wide.

• Controlling haul road fugitive dust is important for employee safety, equipment maintenance,

as well as protecting the air quality of the area. Minnesota Steel Industries is committed to

minimizing haul road emissions. Haul road dust suppression activities are described in

section 4.

3.2 Paved Roads

Paved road emissions (FS 070) occur on the access road to the concentrator plant parking lot and on

the east and west entrances to the main plant area. 2.5 miles of paved road are included in the

emission inventory and are assumed to be traveled by cars and light trucks and by freight trucks,

3.3 Stockpiles

Stockpile sources covered by the dust plan include:

• Overburden/Waste Rock Area Wind Erosion (FS 009)

• Cobber Rejects Pile Wind Erosion (FS 012)

• Cobber Rejects Stockpile Wind Erosion (FS 015)

• 120K ton Concentrate Stockpile (FS 020)

• Oxide Product Stockpile Wind Erosion (FS 026)

• DRI Stockpile Wind Erosion (FS 023)

• DRI Remet Bunker Wind Erosion (FS 031)

• Oversize CDRI Bunker Wind Erosion (FS 034)
Page 4 of 4

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 O - Fugitive Control Plan - Revised 04_30_07.doc

• Grizzly Stockpile Wind Erosion (FS 045)

• Processed Slag Piles Wind Erosion (FS 067)

• Non-metallic Slag Stockpile Wind Erosion (FS 069)

3.4 Materials Transfer Points

Several fugitive dust sources are related to the transfer of materials in the mining and crushing,

concentrator, pelletizer, direct reduced iron, steel mill, and slag processing areas. These sources

include:

• Overburden Loadout (FS 002) – transfer of blasted waste rock by shovel to trucks

• Overburden Unloading (Truck) (FS 003) – transfer of blasted overburden by shovel to ore trucks

• Waste Rock Loadout (FS 004) – transfer of blasted waste rock by shovel to ore trucks

• Waste Rock Unloading (Truck) (FS 005) – ore truck unloading of waste rock at the stockpiles

• Crude Ore Loadout (FS 006) – transfer of blasted ore by shovel to ore trucks

• Drop onto Cobber Rejects Pile (FS 011) – transferring of taconite ore from a conveyor onto the

Cobber rejects pile.

• Cobber Rejects Pile Loadout (FS 013) – use of a loader and truck to haul the cobber rejects to the

cobber rejects stockpile.

• Cobber Rejects Unloading (Truck) (FS 014) – unloading of cobber rejects from a truck to the

stockpile.

• Drop onto 120K ton Concentrate Pile (FS 019) – conveyor transfer onto the 120K ton concentrate

pile.

• 120K ton Concentrate Stockpile Loadout (FS 021) – transfer of concentrate to a conveyor by use

of a loader.

• Oxide Product Stockpile Stacking Conveyor (FS 025) – conveyor transfer of oxide product onto

the oxide product stockpile.

• Oxide Product Loadout to Railcars (FS 027) – transfer of oxide product to either the oxide feed

system or railcars by use of a loader.

• Oxide Fines Bin Discharge (FS 028) – conveyor transfer of oxide fines into the oxide fines

bunker.

• Oxide Fines Return to Regrind Mill (FS 029) – transfer of oxide fines to the regrind mill by use

of a loader.

• DRI Reclaim to Meltshop/Railcar (FS 024) – DRI product pickup from stockpile by front end

loader.

• Railcar Loading (FS036) –FEL railcar loading of DRI product for periodic sale to off-site

customers.

• DRI Drop into Remet Bunker (FS 030) – conveyor transfer of off-spec DRI from a conveyor into

the Remet Bunker.
Page 5 of 5

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 O - Fugitive Control Plan - Revised 04_30_07.doc

• DRI Remet Return to DRI Reclaim Hopper (FS 032) - transfer of off-spec DRI from the remet

bunker to the oxide feed system by use of a loader.

• Oversize CDRI Drop into Bunker (FS 033) – conveyor transfer of cold DRI from a conveyor into

a bunker.

• Oversize CDRI to EAF by Scrap Bucket (FS 035) – transfer of oversize cold DRI to the EAF by

use of a loader/scrap bucket.

• DRI Stockpile Stacking Conveyor (FS 022) – conveyor transfer of DRI from a conveyor onto the

periodic DRI stockpile.

• CDRI Drop into Line I EAF Feed Collection Chute (FS 037) – conveyor transfer of CDRI into

the EAF feed collection chute.

• CDRI Drop into Line II EAF Feed Collection Chute (FS 038) - conveyor transfer of CDRI into

the EAF feed collection chute.

• Lump Lime/Carbon Unloading (FS 039) - unloading of meltshop additives from a truck onto a

conveyor.

• Lime/Carbon Bucket Elevator (FS 040) – transfer of material from the bucket elevator to a

conveyor.

• Lime/Carbon Tripper Conveyor Drop (FS 041) – conveyor transfer of melt shop additives from a

conveyor into day bins.

• Slag Dumping (FS 042) – molten slag transfer from slag pots to the slag pits.

• Digging Pits/Breaking Slag (FS 043) – retrieval and breaking of solidified slag prior to

processing.

• Loading Grizzly Stockpile (FS 044) – loader activity to move slag material from the slag

dumping station to the grizzly stockpile.

• Grizzly Stockpile Loadout (FS 046) and Grizzly Loading (FS 047) – loading slag material from

the grizzly stockpile into the grizzly.

• Grizzly Oversize to Slag Dumping (FS 048) – transfer of material from the grizzly back to the

slag dumping area for additional size reduction.

• Grizzly/Feeder (FS 049) – transfer of broken slag material from the grizzly onto a conveyor.

• Slag Transfer Conveyor (FS 050) – transfer of slag material from a conveyor to the slag screen.

• Slag Screen (FS 051) – transfer of slag material from the slag screen to either a conveyor or the

slag crusher.

• Screened Slag Conveyor (FS 052) – conveyor to conveyor transfer of screened slag.

• Screened Slag Cobber (FS 053) – separation of screened slag into metallic and non-metallic

fractions.

• Non-metallics Stacker No.1 (FS 054) and Non-metallics Stacker No. 2 (FS 055) – conveyor

transfer of non-metallic slag materials to a stockpile.

• Metallics Stacker No.1 (FS 056) and Metallics Stacker No. 2 (FS 057) – conveyor transfer of

metallic slag materials from two conveyors to a stockpile.

• Slag Crusher (FS 058) – transfer of crushed slag from the slag crusher to a conveyor.
Page 6 of 6

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 O - Fugitive Control Plan - Revised 04_30_07.doc

• Crusher By-pass Conveyor (FS 059) – conveyor to conveyor transfer of slag material.

• Crushed Slag Cobber (FS 060) – separation of crushed slag into metallic and non-metallic

fractions.

• Crushed Metallics Stacker (FS 061) – transfer of metallic material from a conveyor to a

stockpile.

• Crushed Non-metallics Screen (FS 062) - transfer of non-metallic slag material from the screen

to a conveyor.

• Crushed Non-metallics Stacker No.1 (FS 63) and Crushed Non-metallics Stacker No. 2 (FS 064)

– transfer of crushed non-metallic materials from two conveyors to a stockpile.

• Metallics Return to EAF (FS 065) – transfer by loader of crushed metallic slag from a stockpile

to the EAF feed collection chutes.

• Non-metallics Loadout (FS 066) – transfer by loader of crushed non-metallic slag material from a

stockpile to trucks.

• Non-metallics Unloading to Off-site Sale or On-site Stockpile (FS 068) - the unloading of nonmetallic material from a truck to an on-site stockpile.

3.5 Tailings Basin

There are four fugitive sources associated with the tailings basin:

• Tailings Basin Wind Erosion (FS 016) – tailings basin beach area that is exposed to wind erosion

prior to dust control measures.

• Dozer activity at Tailings Basin (FS 017) – dike building and maintenance.

• Grading at Tailings Basin (FS 018) – dike building and maintenance.

• Service and access roads at the tailings basin (FS 008) – light vehicle traffic for personnel and

maintenance
Page 7 of 7

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 O - Fugitive Control Plan - Revised 04_30_07.doc

4.0 Operating Practices and Control Measures

The operating practices and control measures that will be implemented and recorded for the fugitive

dust sources identified in Section 3 are described below. Minnesota Steel will train and assign

appropriate personnel the responsibility to control fugitive emissions in their areas of responsibility.

4.1 Haul Roads and Service Roads (FS 007, FS 008)

Primary Controls: Watering and other dust suppressant application, road maintenance including

crushed rock surfacing, grading, and scarifying.

Contingent Controls: Increased application of primary controls.

Practices: The operating practices Minnesota Steel Industries will use include, but are not limited to

the following:

• Minnesota Steel Industries will perform daily visible emissions checks on all active haul

roads at the beginning shifts that start during daylight hours. Haul truck drivers will also

observe for visible emissions during the shift and report by radio as needed. If visible

emissions are observed during the visible emissions check or are reported by an equipment

operator, Minnesota Steel Industries will investigate the condition and take appropriate

corrective action to address the visible emissions. The observation of visible emissions does

not, in and of itself, demonstrate noncompliance with any applicable requirement but is a

signal to trigger investigation and, if necessary, reasonable and appropriate corrective action.

• Minnesota Steel Industries will maintain daily visible emission check reports based on the

visible emissions checks. An exception report will be filed if visible emissions cannot be

controlled by usual control strategies. Examples of such exceptions may be water wagon

breakdown, extraordinary weather events (extremely hot, dry) etc. Employees will inform

their supervisor of an exception condition at the end of their shift so that the report can be

filled out.

• In non-freezing conditions, dust will be controlled by the following strategies:

o Water will be applied to the active haul roads during the day and afternoon shifts, as

required by weather, traffic, and road conditions. Water trucks will be dispatched

and unpaved roads will be watered if excessive dusting is encountered. Some

weather conditions during the summer months, such as low humidity and high winds,

require a higher water frequency. The frequency and amount of water application is

adjusted depending on weather conditions.

o Haul roads will be graded as required.

o Crushed and screened rock will be added to the road surface to minimize fugitive dust

generation.

o Liquid chemical dust suppressant may also be applied to some high traffic areas for

dust control as needed.

• In freezing conditions, dust will be controlled by the following strategies:

o Solid or liquid chemical dust suppressant will be applied to the haul road in late fall

prior to freeze up.
Page 8 of 8

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 O - Fugitive Control Plan - Revised 04_30_07.doc

o Haul roads will be scarified as necessary.

o New haul road material will be applied as needed

• Minnesota Steel Industries will maintain adequate watering capacity, including backup in the

event of breakdown, to control dust during typical summer conditions.

• Minnesota Steel Industries will maintain daily watering records and chemical application

records. The records will include the watering truck identification number, the number of

water loads applied per shift and the operator name. Minnesota Steel Industries will equip

each watering truck with the same GPS monitoring system used by the other haul trucks.

• Minnesota Steel Industries will rely on National Weather Service (NWS) reports from the

Hibbing Airport to provide a record of daily precipitation and humidity, high and low

temperature, wind speed and direction readings, and dew point.

• Vehicle miles traveled (VMT) will be calculated periodically based on mine production and a

record will be kept on site. This information will be sent to the MPCA annually for

incorporating into the annual emissions inventory.

• Minnesota Steel Industries will evaluate new technologies or methods in dust suppression for

their technical and economic feasibility as they become commercially available.

Recordkeeping: Minnesota Steel Industries will maintain the following records on site:

• Haul Road Fugitive Emissions Exception Report (FS 007 and FS 008)

• Daily Watering Reports

• Daily weather information as reported by the National Weather Service at the Hibbing

Airport.

• The application of chemical dust suppressants will be recorded and reported from Minnesota

Steel Industries’ purchase records.

• Tracking and calculation of annual vehicle miles traveled (VMT) will be based on mine

production.

4.2 Paved Roads (FS 070)

Primary Controls: Street sweeping as needed.

Contingent Controls: Increased application of primary controls.

Practices: The operating practices Minnesota Steel Industries will use include, but are not limited to

sweeping or washing of the paved roads as needed to prevent fugitive emissions.

Recordkeeping: Minnesota Steel Industries will maintain the following records on site:

• Tracking and calculation of annual vehicle miles traveled (VMT) will be based on employee

counts and estimated periodically.
Page 9 of 9

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 O - Fugitive Control Plan - Revised 04_30_07.doc

4.3 Stockpiles (FS 009, FS 012, FS 020, FS 023, FS 026, FS 029, FS 042, FS

052, FS 076)

Primary Controls: Natural moisture content of stockpiled materials

Contingent Controls: Water spray as needed during non-freezing conditions.

Practices: The operating practices Minnesota Steel Industries will use include, but are not limited to

the following:

• Minnesota Steel Industries will perform visible emissions checks on all stockpiles listed

above once per day during daylight hours.

• Minnesota Steel Industries will minimize the drop distances onto each stockpile as far as

practicable.

Recordkeeping: Minnesota Steel Industries will maintain the following records on site:

• Daily Visible Emissions Checklists (FS 012, FS 020, FS 023, FS 026, FS 029, FS 042, FS

052, FS 074 and FS 076)

• Material Handler Report (FS 012, FS 020, FS 023, FS 026, FS 029, FS 042, FS 052, FS 074

and FS 076)

4.4 Material Transfer Points (FS 002, FS 003, FS 004, FS 005, FS 006, FS 011,

FS 013, FS 014, FS 019, FS 021, FS 022, FS 024, FS 025, FS 027, FS 028,

FS 030, FS 031, FS 032, FS 033, FS 034, FS 035, FS 037, FS 038, FS 040,

FS 041, FS 043, FS 044, FS 045, FS 046, FS 047, FS 048, FS 049, FS 050,

FS 051, FS 053, FS 054, FS 055, FS 056, FS 057, FS 058, FS 059, FS 060,

FS 061, FS 062, FS 063, FS 064, FS 065, FS 066, FS 067, FS 068, FS 069,

FS 070, FS 075)

Primary Controls: Natural moisture content of materials, minimized drop distances when possible.

Contingent Controls: None.

Practices: The operating practices Minnesota Steel Industries will use include, but are not limited to

the following:

• Minnesota Steel Industries will perform visible emissions checks on all material transfer

points listed above once per day during daylight hours.

Recordkeeping: Minnesota Steel Industries will maintain the following records on site:

• Daily Visible Emissions Checklists (FS001, FS 011, FS 014, FS 016, FS 017, FS 019, FS

020, FS 022, FS 025, FS 042, and FS 070.)

• Material Handler Report (FS 002, FS 003, FS 004, FS 005, FS 006, FS 010, FS 013, FS014,

FS 021, FS 027, FS 042, FS 046, FS066, and FS068)
Page 10 of 10

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 O - Fugitive Control Plan - Revised 04_30_07.doc

4.5 Tailings Basin (FS 008, FS 016, FS 017, FS 018)

Primary Controls: Beach area minimization, mulching, vegetation, systematic dumping.

Contingent Controls: Change tailings discharge points.

Practices: The operating practices Minnesota Steel Industries will use include, but are not limited to

the following:

• During freezing months (typically late November through early April), freshly deposited

tailings freeze and are covered with snowfall which minimizes dust emissions. Mulching

during the winter, especially when snow is present, will be done to reduce fugitive dust liftoff. When the snow melts the mulch forms a mat on the tailings thereby minimizing

emissions.

• Tailings deposited during winter will be vegetated in early spring before the tailings

completely thaw.

• Beach areas developed during non-freezing months (typically early April through late

November) will be treated (i.e. mulched applied, vegetated, or application of dust

suppressants) as soon as practical to prevent large areas of exposed beach from drying out,

especially during freeze drying conditions or hot, windy conditions. Dike construction

techniques and water level management will help minimize exposed beach areas, which will

be treated in a timely manner to limit the risk of dry conditions on the beaches. Ideally fresh

beach will be treated within two weeks, but these activities are dependent on weather

conditions and basin configurations. Mulch will be staged on-site to minimize the time

necessary for it to be applied once conditions are suitable.

• .

• During construction and, to the extent possible during operations, berms and benches will be

graded to gentle slopes to reduce wind resistance, which will limit the potential for fugitive

dust emissions.

• Minnesota Steel will maintain a systematic discharge schedule. The tailings basin will be

designed with multiple cells. Tailings will typically be discharged to only one cell at a time.

The idle cells will be vegetated and will remain undisturbed for long periods of time (up to 2

years) thereby minimizing dust emissions from those portions of the tailings basin. The idle

cells will be revegetated, if necessary, to maintain adequate vegetation for dust control

purposes.

• In addition, the dust suppressing objectives for the active cell include:

o Maintenance of adequate freeboard around the dike perimeter

o High interior water levels by maintaining unobstructed gravity flow of slurry toward

the decant pool (interior)

o Adequate pumping capacity allowing for discharge to completely encircle the dike

perimeter creating a strong dike and adequate beach to protect the dike.

o If high winds are forecast during the non-freezing months, either the tailings

discharge will be moved or clear water will be pumped onto beach areas that are

exposed and are determined to be dry.
Page 11 of 11

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 O - Fugitive Control Plan - Revised 04_30_07.doc

• As needed, Minnesota Steel Industries will apply water or chemical dust suppression

materials to the tailings basin service roads.
Page 12 of 12

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 O - Fugitive Control Plan - Revised 04_30_07.doc

5.0 Recordkeeping

The following records will be maintained at Minnesota Steel Industries for the period specified by

the Title V permit:

• Daily Visible Emissions Checks. Due to the large number of these reports that are generated

on a daily basis (one copy of each report per day), Minnesota Steel Industries commits to

retaining these records for a period of no less than one year.

• Primary Crusher Attendant Report (FS 065)*

• Crushing Control Room Report (FS 065 – 069)*

• Concentrator Material Handler Report (FS 011 – 018)*

• Pelletizer Material Handler Report (FS 019 – 027)*

• Direct Reduced Iron Material Handler Report (FS 028 – 045)*

• Steel Mill Material Handler Report (FS 046 – 048)*

• Slag Processing Material Handler Report (FSs 049 – 076)*

• Daily Watering Reports Haul Road Fugitive Emissions Exception Reports *

• Daily Weather Information Reports (from National Weather Service at Hibbing Airport)*

• Employee Training Records*

• MPCA Letter of Approval of this Fugitive Control Plan

•

• * These records are anticipated to be electronic reports generated from the plant process

control systems.
Page 13 of 13

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 O - Fugitive Control Plan - Revised 04_30_07.doc

6.0 Training

An integral part of the implementation of the Fugitive Control Plan is appropriate training for the

personnel involved. Training will be provided for all levels of personnel at the facility and will cover

a subset of the following subjects as needed for individual levels of responsibility:

• Employee Responsibilities

• Forms and Record Keeping

• Reporting

• Corrective Actions

• Maintenance

• Work Orders

• Dust Observation and Visibility Training

• Weather Observations

• Location of Information

Minnesota Steel Industries will provide training in the areas listed above to new employees as their

job function demands. Refresher training will be provided to existing employees on an annual basis.
Tables
P:\Mpls\23 MN\31\2331286 MSI\WorkFiles\WO E003 Air Permit Application\103 BACT Response to Comment\Updated BACT Report (Mar 2007)\Attachme

Plan - Revised 04

_

30

_

07.doc

Table 1

List of Fugitive Sources

Fugitive

Source

ID

Fugitive Source

Description Area Operating/Control Practice

FS 001 Drilling Mining and

Crushing

None 

FS 002 Overburden Loadout Mining and

Crushing

None 

FS 003 Overburden Unloading

(Truck)

Mining and

Crushing

None 

FS 004 Waste Rock Loadout Mining and

Crushing

None 

FS 005 Waste Rock Unloading

(Truck)

Mining and

Crushing

None 

FS 006 Crude Ore Loadout Mining and

Crushing

None 

FS 007 Haul Road Emissions Mining and

Crushing

Watering and other dust suppressant application; road

maintenance

FS 008 Service Road Emissions Mining and

Crushing

Watering and other dust suppressant application; road

maintenance

FS 070 Paved Road Emissions Mining and

Crushing

Watering and other dust suppressant application; road

maintenance

FS 009 Overburden/Waste Rock

Area Wind Erosion

Mining and

Crushing

None 

FS 010 Overburden/Waste Rock

Bulldozer

Mining and

Crushing

natural moisture; water spray as needed during non-freez

conditions

FS 011 Drop onto Cobber

Rejects Pile

Concentrator natural moisture; water spray as needed during non-freez

conditions

FS 012 Cobber Rejects Pile

Wind Erosion

Concentrator Limited pile size; natural moisture; water spray as needed

during non-freezing conditions

FS 013 Cobber Rejects Pile

Loadout

Concentrator natural moisture; water spray as needed during non-freez

conditions
Table 1

List of Fugitive Sources

Fugitive

Source

ID

Fugitive Source

Description Area Operating/Control Practice

FS 014 Cobber Rejects

Unloading (Truck)

Concentrator natural moisture; water spray as needed during non-freez

conditions

FS 015 Cobber Rejects Pile

Wind Erosion

Concentrator Limited pile size; natural moisture; water spray as needed

during non-freezing conditions

FS 016 Tailing Basin Wind

Erosion

Concentrator Natural moisture of tailings; revegetation 

FS 017 Dozer Activity at

Tailings Basin

Concentrator Natural moisture of tailings 

FS 018 Grading at Tailings

Basin

Concentrator Natural moisture of tailings 

FS 019 Drop onto 120K ton

Concentrate Stockpile

Pelletizer natural moisture; water spray as needed during non-freez

conditions

FS 020 120K ton Concentrate

Stockpile Wind Erosion

Pelletizer natural moisture; water spray as needed during non-freez

conditions

FS 021 120K ton Concentrate

Stockpile Loadout

Pelletizer natural moisture; water spray as needed during non-freez

conditions

FS 025 Oxide Product Stockpile

Stacking Conveyor

Pelletizer natural moisture; water spray as needed during non-freez

conditions

FS 026 Oxide Product Stockpile

Wind Erosion

Pelletizer natural moisture; water spray as needed during non-freez

conditions

FS 074 Pelletizer Building,

Natural Draft

Pelletizer Partial enclosure (Pelletizer building) 

FS 027 Oxide Product Loadout

to Railcars

Pelletizer natural moisture; water spray as needed during non-freez

conditions

FS 028 Oxide Fines Bin

Discharge

Direct ReducedIron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 029 Oxide Fines Return to Direct Reduced natural moisture; water spray as needed during non-freez
Table 1

List of Fugitive Sources

Fugitive

Source

ID

Fugitive Source

Description Area Operating/Control Practice

Regrind Mill Iron (DRI) conditions

FS 030 DRI Drop into Remet

Bunker

Direct Reduced

Iron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 031 DRI Remet Bunker Wind

Erosion

Direct ReducedIron (DRI)

Limited pile size; natural moisture; water spray as needed

during non-freezing conditions

FS 032 DRI Remet Return to

DRI Reclaim Hopper

Direct ReducedIron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 033 Oversize CDRI Drop

into Bunker

Direct Reduced

Iron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 034 Oversize CDRI Bunker

Wind Erosion

Direct ReducedIron (DRI)

Limited pile size; natural moisture; water spray as needed

during non-freezing conditions

FS 035 Oversize CDRI to EAF

by scrap bucket

Direct ReducedIron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 022 DRI Stockpile Stacking

Conveyor

Direct ReducedIron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 023 DRI Stockpile Wind

Erosion

Direct Reduced

Iron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 024 DRI Reclaim to

Meltshop/Railcar

Direct ReducedIron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 036 Railcar Loading Direct Reduced

Iron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 037 CDRI Drop into Line I

EAF Feed CollectionChute

Direct ReducedIron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 038 CDRI Drop into Line II

EAF Feed CollectionChute

Direct Reduced

Iron (DRI)

natural moisture; water spray as needed during non-freez

conditions

FS 039 Lump Lime/Carbon Steel Mill natural moisture; water spray as needed during non-freez
Table 1

List of Fugitive Sources

Fugitive

Source

ID

Fugitive Source

Description Area Operating/Control Practice

Unloading conditions

FS 040 Lime/Carbon Bucket

Elevator

Steel Mill natural moisture; water spray as needed during non-freez

conditions

FS 041 Lime/Carbon Tripper

Conveyor Drop

Steel Mill natural moisture; water spray as needed during non-freez

conditions

FS 042 Slag Dumping Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 043 Digging Pits/Breaking

Slag

Slag Processing Watering 

FS 044 Loading Grizzly

Stockpile

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 045 Grizzly Stockpile Wind

Erosion

Slag Processing Limited pile size; natural moisture; water spray as needed

during non-freezing conditions

FS 046 Grizzly Stockpile

Loadout

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 047 Grizzly Loading Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 048 Grizzly Oversize to Slag

Dumping

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 049 Grizzly/Feeder Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 050 Slag Transfer Conveyor Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 051 Slag Screen Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 052 Screened Slag Conveyor Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 053 Screened Slag Cobber Slag Processing natural moisture; water spray as needed during non-freez
Table 1

List of Fugitive Sources

Fugitive

Source

ID

Fugitive Source

Description Area Operating/Control Practice

conditions

FS 054 Non-metallics Stacker

No.1

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 055 Non-metallics Stacker

No.2

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 056 Metallics Stacker No.1 Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 057 Metallics Stacker No.2 Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 058 Slag Crusher Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 059 Crusher By-pass

Conveyor

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 060 Crushed Slag Cobber Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 061 Crushed Metallics

Stacker

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 062 Crushed Non-metallics

Screen

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 063 Crushed Non-metallics

Stacker No. 1

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 064 Crushed Non-metallics

Stacker No. 2

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 065 Metallics Return to EAF Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 066 Non-metallics Loadout Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 067 Processed Slag Piles Slag Processing Limited pile size; natural moisture; water spray as needed 
Table 1

List of Fugitive Sources

Fugitive

Source

ID

Fugitive Source

Description Area Operating/Control Practice

Wind Erosion during non-freezing conditions

FS 068 Non-metallics Unloading

to Off-site Sale or OnSite Stockpile

Slag Processing natural moisture; water spray as needed during non-freez

conditions

FS 069 Non-metallic Slag

Stockpile Wind Erosion

(in permit area)

Slag Processing Limited pile size; natural moisture; water spray as needed

during non-freezing conditions