Air Emissions Permit Application for the 

Furnace 5 Reactivation Project

VOLUME I – Permit Application Forms, Regulatory 

Applicability Summary and BACT Analysis 

Prepared for 

Northshore Mining Company 

Silver Bay, Minnesota 

May 2, 2005 

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Volume I – Permit Application Forms, Regulatory Applicability Summary and BACT 

Analysis 

Contents

1 Introduction ........................................................................................................................................................ 1-1

2 Permit Application Forms .................................................................................................................................. 2-3

3 Project Description ............................................................................................................................................. 3-1

3.1 Introduction ................................................................................................................................................. 3-1

3.2 Existing Operations ..................................................................................................................................... 3-1

3.2.1 Concentrate Production .................................................................................................................... 3-2

3.2.2 Pellet Production .............................................................................................................................. 3-2

3.2.3 Product Storage and Loadout............................................................................................................ 3-3

3.2.4 Power Plant....................................................................................................................................... 3-3

3.2.5 Raw Materials Management............................................................................................................. 3-4

3.2.6 Process Water and Tailing Disposal System. ................................................................................... 3-4

3.3 The Furnace 5 Reactivation Project ............................................................................................................ 3-4

3.3.1 Other Changes to Existing Facilities ................................................................................................ 3-6

4 Regulatory Applicability Summary.................................................................................................................... 4-1

4.1 Introduction ................................................................................................................................................. 4-1

4.2 Ambient Air Quality Standards................................................................................................................... 4-1

4.3 Emission Standards ..................................................................................................................................... 4-3

4.3.1 Federal New Source Performance Standards (NSPS)....................................................................... 4-4

4.3.2 National Emission Standards for Hazardous Air Pollutants (NESHAP) .......................................... 4-4

4.3.2.1 40 CFR 61 NESHAP.......................................................................................................... 4-4

4.3.2.2 40 CFR 63 NESHAP.......................................................................................................... 4-4

4.3.3 State Standards of Performance........................................................................................................ 4-4

4.4 New Source Review (NSR)......................................................................................................................... 4-5

4.4.1 Best Available Control Technology (BACT) Analysis .................................................................... 4-6

4.4.2 Air Quality Analysis......................................................................................................................... 4-6

4.4.3 Additional Impacts Analysis............................................................................................................. 4-7

4.4.3.1 Growth Analysis................................................................................................................. 4-7

4.4.3.2 Ambient Air Quality Analysis............................................................................................ 4-8

4.4.3.3 Soils and Vegetation Analysis............................................................................................ 4-8

4.4.3.4 Visibility Impairment Analysis .......................................................................................... 4-8

4.4.4 Class I Area Impact Analysis ........................................................................................................... 4-8

4.5 References ................................................................................................................................................... 4-9

5 BACT Analysis .................................................................................................................................................. 5-1

List of Tables

Table 4-1: National Ambient Air Quality Standards (NAAQS) 

Table 4-2: State Ambient Air Quality Standards (SAAQS) for Minnesota 

Table 4-3: New Source Review - Significant Net Emissions Increases 

Table 4-4: New Source Review - PSD Increments 

Table 5 1: Results of the BACT Analysis 

Appendix

Section 5 

 Appendix A “Best Available Control Technology Review”, April 2005 
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5 BACT Analysis 

Please refer to the separate report (“Best Available Control Technology Review” in Appendix A) that presents the 

findings of the BACT Analysis. 

Table 5-1 summarizes the results for the completed BACT analysis for NSM’s Furnace 5 Reactivation Project. 

Table 5-1: Results of the BACT Analysis 

Emission Source BACT Pollutant(s) Controlled 

Indurating Furnace Exhaust Wet ESP SO2, Particulate Matter 

Indurating Furnace Exhaust No Controls NOx

Indurating Furnace Pellet Discharge Wet Scrubber Particulate Matter 

Concentrator Silos Fabric Filter Particulate Matter 

Ore Crushing Fabric Filter Particulate Matter 

Appendix A 

 

 

Northshore Mining Company 

Silver Bay, Minnesota 

Appendix A 

Best Available Control Technology Review 

for the 

Furnace 5 Reactivation Project 

April 2005 
 
 

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Table of Contents 

Table of Contents..........................................................................................................................................3

I. Executive Summary ....................................................................................................................5

A.Project Description............................................................................................................................5

B.Proposed BACT ................................................................................................................................7

II. Introduction.................................................................................................................................8

A.Project Description............................................................................................................................8

B.BACT Methodology and Results....................................................................................................13

III. Indurating Furnace Exhaust ......................................................................................................14

A.Sulfur Dioxide (SO2) Emission Controls ........................................................................................16

1. Step 1 – Identify all Control Technologies .................................................................. 16

2. Step 2 – Eliminate Technically Infeasible Options...................................................... 19

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness ................ 20

4. Step 4 – Evaluate Most Effective Control Technologies and Document Results........ 21

5. Step 5 – Select BACT .................................................................................................. 23

B.Nitrogen Oxide (NOx) Emission Controls ......................................................................................23

1. Step 1 – Identify all Control Technologies .................................................................. 23

2. Step 2 – Eliminate Technically Infeasible Options...................................................... 30

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness ................ 34

4. Step 4 – Evaluate Most Effective Control Technologies and Document Results........ 34

5. Step 5 – Select BACT .................................................................................................. 35

C.Particulate Matter (PM / PM10) Emission Controls ........................................................................36

1. Step 1 – Identify all Control Technologies .................................................................. 36

2. Step 2 – Eliminate Technically Infeasible Options...................................................... 39

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness ................ 42

4. Step 4 – Evaluate Most Effective Control Technologies and Document Results........ 43

5. Step 5 – Select BACT .................................................................................................. 45

IV. Fine Crushing............................................................................................................................47

A.Particulate Matter (PM / PM10 ) Emission Controls .......................................................................47

1. Step 1 – Identify all Control Technologies .................................................................. 47

2. Step 2 – Eliminate Technically Infeasible Options...................................................... 48

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness ................ 50

4. Step 4 – Evaluate Most Effective Control Technologies and Document Results........ 50

5. Step 5 – Select BACT .................................................................................................. 51

V. Concentrator Silos.....................................................................................................................53

A.Particulate Matter (PM / PM10 ) Emission Controls .......................................................................53

1. Step 1 – Identify all Control Technologies .................................................................. 53

2. Step 2 – Eliminate Technically Infeasible Options...................................................... 54

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness ................ 56

4. Step 4 – Evaluate Most Effective Control Technologies and Document Results........ 56

5. Step 5 – Select BACT .................................................................................................. 57
 

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VI. Indurating Furnace Pellet Discharge.........................................................................................59

A.Particulate Matter (PM / PM10 ) Emission Controls .......................................................................59

1. Step 1 – Identify all Control Technologies .................................................................. 59

2. Step 2 – Eliminate Technically Infeasible Options...................................................... 60

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness ................ 62

4. Step 4 – Evaluate Most Effective Control Technologies and Document Results........ 62

5. Step 5 – Select BACT .................................................................................................. 63

BACT ATTACHMENT 1 ..........................................................................................................................65

BACT ATTACHMENT 2 ..........................................................................................................................83

BACT ATTACHMENT 3 ........................................................................................................................111
 

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I. Executive Summary 

A. Project Description 

Northshore Mining Co. (NSM) is proposing to reactivate its Furnace 5 taconite production facilities. 

These facilities have been idle for some time due to a weak demand for taconite pellets. Recent 

increases in market demand have prompted Northshore to re-active these production facilities in 

order to increase iron concentrate and taconite pellet production. 

Northshore Mining Co. is a major source of PSD pollutants (Prevention of Significant Deterioration). 

Because the project will be a major modification under PSD rules, Best Available Control 

Technology (BACT) must be installed. The purpose of this BACT study report is to submit 

information needed for the MPCA to establish BACT limits in the air quality permit for the project. 

The following is a description of the equipment which Northshore proposes to reactivate and 

construct as part of the Furnace 5 Reactivation project: 

• Reactivate Fine Ore Crushing Facilities (2 lines) 

• Reactivate Concentrator Sections (9 lines) 

• Construct New Concentrate Storage Silos (2 silos) 

• Reactivate Indurating Furnace 5 (1 furnace) 

Fine Ore Crushing

Fine ore crushing is the process of crushing taconite ore that is received from the mine down to the 

size needed for ore concentration. Fine ore crushing is a dry process which generates dust. Dust 

emissions from the fine ore crushing equipment involved in the Furnace 5 Reactivation Project are to 

be routed to collection points currently equipped with baghouse emission controls. 

Concentrator 

Ore concentration is the process of concentrating the iron ore by separating the ore from the waste 

rock. Crushed ore entering the concentration process is dry. Particulate matter is emitted as the dry 

ore is transferred into the process. The ore transfer points will be equipped with fabric filters to 
 

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control particulate emissions. In the remainder of the ore concentration processing steps, the ore is 

wet, and there are no particulate matter emissions from these operations. 

Concentrate Storage Silos (2) 

Concentrate for off site shipment used by NSM will be put in new storage silos. Use of the silos will 

not generate particulate emissions as the result of material transfers into and out of the silos due to its 

9 to 10 percent moisture content. NSM is also proposing to equip the new storage silos with fabric 

filter bin vents to control air flows in the silos. 

Indurating Furnace Pellet Discharge 

When the finished taconite pellets leave the induration furnace, particulate matter is emitted at the 

transfer point. The furnace discharge pellet transfer point is currently equipped with a rotoclone for 

particulate control. NSM is proposing to install a wet scrubber as BACT for control of particulate 

emissions from this source as part of the Furnace 5 Reactivation Project. 

Indurating Furnace Exhaust 

NSM is proposing to re-activate Furnace #5 as part of the Furnace 5 Reactivation Project. Based on 

the estimated project emissions increase, the project will be a PSD major modification for SO2, NOx, 

and particulate matter. All of these pollutants are emitted from this source. Furnace #5 is equipped 

with a wet ESP which is used for Particulate and SO2 emission controls. NSM proposes to use the 

existing wet ESP as BACT for these pollutants. None of the NOx emission control devices reviewed 

can be utilized due to technical or economic infeasibility. 
 

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B. Proposed BACT 

The Best Available Control Technologies for emissions from Northshore Mining Co.’s proposed 

Furnace 5 Reactivation Project are: 

Best Available Control Technology 

Northshore Mining Co. Furnace 5 Reactivation Project 

Emission Source BACT Pollutant(s) Controlled 

Indurating Furnace Exhaust Wet ESP SO2, Particulate Matter 

Indurating Furnace Exhaust No Controls NOx

Indurating Furnace Pellet 

Discharge 

Wet Scrubber Particulate Matter 

Concentrator Silos Fabric Filter Particulate Matter 

Ore Crushing Fabric Filter Particulate Matter 

 

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II. Introduction 

A. Project Description 

Overview

Northshore Mining Company (NSM) plans to utilize its currently permitted, but idle, taconite 

processing and pellet production capacity to meet the growing domestic and international demand for 

iron ore concentrate and pellets in the production of finished iron and steel commodities. NSM 

expects the State of Minnesota and, in particular, Northeastern Minnesota to benefit through an 

increased tax base and employment increases directly at NSM and in support infrastructure and 

industry throughout the state. 

NSM plans to reactivate, over the next 6 months to 2 years, permitted operating equipment at its 

Silver Bay taconite processing plant. The reactivations in the proposed project include two permitted 

crushing lines, nine permitted concentrating lines and one permitted pelletizing furnace. The project 

will also involve the reactivation and/or upgrading of certain pollution control equipment consistent 

with current USEPA and MPCA rules regarding emission control requirements and standards. The 

project, although the equipment is currently permitted, may have the potential to trigger Prevention 

of Significant Deterioration (PSD) and New Source Review (NSR) to assure compliance with 

BACT/MACT Technologies under current USEPA policy. 

Proposed Reactivation

The reactivation of permitted but currently idle equipment at the Silver Bay facility includes the 

following equipment: 

• Currently permitted fine crushing lines 4 and 104 including existing permitted baghouse 

emission control equipment. Lines 4 and 104 have the following MPCA equipment numbers: 
 

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Crushing Line # Emission Unit (EU) # Stack Vent (SV) # Control Equipment (CE) # 

Line 4 Crusher EU 011 SV 011 CE 011 

Line 104 Crusher EU 020 SV 020 CE 020 

• Currently permitted concentrating lines 2 through 10. Existing multiclone emission control 

equipment will be upgraded with baghouse collectors to assure compliance with 

BACT/MACT and New Source Review requirements. The MPCA equipment numbers for 

the concentrator silos associated with lines 2 through 10 are as follows: 

Concentrator Line # Emission Unit (EU) # Stack Vent (SV) # Control Equipment (CE) #

Line 2 Concentrator Silo EU 033 SV 033 CE 033 

Line 3 Concentrator Silo EU 034 SV 034 CE 034 

Line 4 Concentrator Silo EU 035 SV 035 CE 035 

Line 5 Concentrator Silo EU 036 SV 036 CE 036 

Line 6 Concentrator Silo EU 037 SV 037 CE 037 

Line 7 Concentrator Silo EU 038 SV 038 CE 038 

Line 8 Concentrator Silo EU 039 SV 039 CE 039 

Line 9 Concentrator Silo EU 040 SV 040 CE 040 

Line 10 Concentrator Silo EU 041 SV 041 CE 041 

• Currently permitted Furnace #5 is equipped with Wet Wall Electrostatic Precipitators 

(WWESP's). The MPCA equipment numbers for Furnace #5 are as follows 
 

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Source Emission Unit (EU) # Stack Vent (SV) # Control Equipment (CE) # 

SV 266 CE 271 

Furnace #5 EU 634 SV 267 CE 272 

SV 268 CE 273 

• A new wet scrubber will be installed at the discharge end of Furnace #5 to assure compliance 

with the proposed BACT and Taconite MACT standards for finished pellet handling emission 

sources. Furnace #5 pellet discharge has the following MPCA equipment numbers: 

Source Emission Unit (EU) # Stack Vent (SV) # Control Equipment (CE) # 

Furnace #5 Pellet 

Discharge 

EU 635 SV 269 CE 274 

New Equipment 

In addition to reactivating existing equipment, NSM proposes to install two (2) new concentrate 

storage silos. These silos will be used to store concentrate which is shipped off site. Concentrate 

shipped off site will be loaded directly out of the silos into trucks and rail cars. MPCA equipment 

numbers have not been assigned to the storage silos. The silos will be equipped with fabric filter bin 

vents to control air flows as the silos are being loaded. The concentrate has a moisture content of 9 

to 10 percent, and no emissions are expected. 

Equipment Descriptions 

Concentrate Production 

Concentrate production involves the following steps. The ore is received at Silver Bay by 

rail from the Babbitt mine and unloaded at the car dump station. The ore proceeds to fine 

crushing where it is reduced to a minus three fourths-inch size. Following fine crushing, the 
 

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ore is directed to dry cobbing, a dry magnetic separation process, to reject the portion of the 

ore that does not contain sufficient magnetic iron. 

The ore not rejected during dry cobbing is sent to a series of wet grinding and concentrating 

processes to liberate, concentrate, and recover the iron. These processes include rod and ball 

mill grinding, particle sizing, magnetic separation, hydraulic cleaning, froth flotation, and 

fine screening to produce a finely ground concentrate containing approximately 65 percent 

iron contained in a slurry. The iron concentrate slurry is thickened and vacuum filtered to 

reduce moisture to approximately 10 percent. After vacuum filtering, the concentrate is 

conveyed as a solid to pelletizing operations. 

Concentrate production includes two types of emission sources which are included in the 

Furnace 5 Reactivation Project: 

• Fine Crushing 

Ore receipt, conveyance, crushing and dry cobbing produce dust. This equipment is 

currently equipped with baghouses for dust control. This BACT report will address 

emission controls for dust emissions from ore crushing at the two ore crushers associated 

with the Furnace 5 Reactivation Project. 

• Concentrator Silos 

Dust emissions are generated at the feed conveyors prior to the wet processing operations 

and associated transfer points. The concentrators are currently equipped with cyclones 

(multiclones) to control dust at the feed conveyors. This BACT report will address 

emission controls for dust emissions from the nine ore concentrators associated with the 

Furnace 5 Reactivation Project. 

• Concentrate Storage Silos 

Ore concentrate that will not be immediately used by NSM will be put in new storage 

silos prior to use or shipment offsite. Use of the silos will not generate particulate 

emissions as the result of material transfers into and out of the silos. NSM is proposing 

to equip the new storage silos with fabric filter bin vents to control the air flows in the 

silos. This BAC T report will not address the concentrate storage silos because they are 

not sources of emissions 
 

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Pellet Production 

NSM produces standard and fluxed (lime-containing) pellets from the concentrate using a 

number of processing steps as described below. 

Following vacuum filtering, the concentrate is agglomerated. Agglomeration involves adding 

a small amount of binding agent (e.g., bentonite clay, starch) to the iron concentrate and 

passing the mixture through inclined rotating drums where it is rolled into one-fourth to onehalf inch green balls suitable for the pelletizing furnaces. The green balls are placed onto a 

traveling grate that passes through the furnace. NSM has four permitted furnaces (#5 and #6 

at 160 long tons per hour (LTPH) each and #11 and #12 at 300 LTPH each). In the furnaces, 

the green balls are dried and heated to start an exothermic reaction that converts the 

magnetite (Fe3O4) concentrate to hematite (Fe2O3). During this process, the pellets are 

hardened. Pellets are then cooled and discharged from the furnace for subsequent handling. 

Fuels used at the furnaces include primarily natural gas, with fuel oil as a back-up fuel during 

periods of natural gas curtailment. 

After leaving the furnaces, the pellets are directed to a series of screening and additional 

cooling steps. Undersized material is either sold as sinter or recycled. The final products are 

then transported to the storage yard for stockpiling or bin storage. 

Pellet production includes two emission sources which are included in the Furnace 5 

Reactivation Project: 

• Induration Furnace #5 Exhaust Gas 

Particulate Matter, SO2 and NOx emissions are generated in the indurating furnace from 

fuel combustion, oxidation of sulfur compounds in the iron ore and attrition of pellets 

during material handling within the furnace. NSM’s Indurating furnaces are currently 

equipped with Wet Wall Electrostatic Precipitators (WWESPs) to control SO2 and 

particulate matter emissions. This BACT report will address emission controls for 

particulate matter, SO2 and NOx emissions in the exhaust gases from Furnace #5. 

• Induration Furnace #5 Pellet Discharge 
 

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Dust emissions from pellet handling processes following the furnaces currently are 

controlled by rotoclones. This BACT report will address emission controls for dust 

emissions from the pellet handling at the discharge of Furnace #5. 

B. BACT Methodology and Results 

This BACT analysis was prepared in accordance with the “top-down” approach specified in EPA’s 

New Source Review Workshop Manual, (October 1990). 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. 

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 overall 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. 
 

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III. Indurating Furnace Exhaust 

Taconite pellets are oxidized and heat-hardened in the induration furnace. Discharged pellets are 

cooled, screened, and transferred on conveyor belts to bins or stockpiles for storage. The stored 

pellets are loaded to ships or trains for shipment to the steel mill. 

The NSM Furnace #5 is a straight grate furnace. It is fueled by natural gas, with fuel oil as a back-up 

fuel. Figure 1 is a generic diagram of a typical straight grate induration furnace. A description of the 

induration process follows Figure 1. 

Figure 1 General Diagram of a Straight Grate Induration Furnace. 

Drawing from MPCA Taconite BART Report, September, 2003
 

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The induration process involves pellet pre-heating, drying, hardening, oxidation and cooling. In a 

straight grate furnace, pellets are carried through the furnace on a continuous grate. Pellets are dried, 

and then heated to the proper temperatures for hardening and oxidation. The pellet hardening and 

oxidation section of the induration furnace is designed to operate at 2,400 oF. This temperature is 

required to meet taconite pellet product specifications. Exhaust gas from the pelletizing process has 

a high moisture content. 

NSM will use natural gas as the primary fuel in Furnace #5. The fuel is primarily combusted in the 

pellet hardening and oxidation section of the furnace. 

The pelletizing process occurs at 300% to 400% excess air. The excess air is used for combustion, 

pellet cooling, and as a source of oxygen for pellet oxidation. 

Due to the high-energy demands of the induration process, induration furnaces have been designed to 

recover as much heat as possible. Pellet preheat zones are heated with the hot gases generated in the 

pellet hardening/oxidation section. Each of these sections is designed to maximize heat recovery 

within process constraints. 

PSD pollutants emitted from Furnace #5 operation include, sulfur dioxide, nitrogen oxides and. 

particulate matter. 

• Sulfur dioxide (SO2) emissions originate from both fuel combustion (depending on the sulfur 

content in the fuel used) and the oxidation of sulfur present in the green balls. SO2 emissions 

are released to the atmosphere in the induration furnace flue gas. 

• 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. Furnace #5 uses 

natural gas and fuel oil as fuel sources. The majority of NOx emissions from a pellet plant are 

from thermal oxidation due to the high oxygen levels and high operating temperatures present 

in the induration furnaces. A small amount of fuel bound NOx is generated when fuel oil is 

used to fire the furnace. NOx emissions are released to the atmosphere in the induration 

furnace flue gas. 

• Particulate matter emissions emanate from both fuel combustion, and the attrition of particles 

(dust) in the taconite pellets. Particulate emissions from the pellets are caused by the abrasion 

of pellets rubbing against each other and against the equipment as the pellets move through 
 

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the induration furnace. Particulates are released to the atmosphere in the induration furnace 

flue gas. 

A. Sulfur Dioxide (SO2) Emission Controls 

1. Step 1 – Identify all Control Technologies 

Four control technologies were evaluated for SO2 emissions control from the indurating furnace. 

Two of the control technologies are technically infeasible. 

EPA’s RACT, BACT, LAER Clearinghouse (RBLC) database was checked for recent BACT 

determinations in the mineral and metallic processing industries. The results of this evaluation are in 

BACT Attachment 1, Tables 1 and 2. While most of the BACT determinations were for sources that 

are not directly applicable to this project, the control technologies evaluated in this study are 

consistent with those found in the RBLC. The proposed BACT limits are consistent with the level of 

emission control found in RBLC for similar industries, after taking process limitations and NSM’s 

site specific conditions into account. The control technologies evaluated for SO2 emissions control 

from Furnace #5 as follows. 

Table III A-1 

SO2 Emission Control Technologies Considered for BACT Analysis 

Technology Description 

Wet Scrubber 

A wet scrubber is a vessel which is used to contact the flue gas 

with a liquid sorbent. The scrubber is designed so that the liquid 

sorbent flows down through the scrubber while the flue gases flow 

both upwards and downwards. Liquid sorbent can be applied by 

spraying, and / or a packed tower may be used. The sorbent 

chemically reacts with SO2 and removes it. Spent sorbent is a 

liquid waste. Sludge may also be a byproduct of wet scrubbing. 

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. Solid 

waste is a byproduct of this control device. 

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. 

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 
 

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Wet Scrubbing / Flue-Gas Desulfurization 

Wet scrubbing processes used to control SO2 are generally termed flue-gas desulfurization (FGD) 

processes. FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a 

contacting liquid, to remove SO2 in the waste gas. Lime, crushed limestone, or caustic may be used 

as scrubbing agents. 

Limestone scrubbing introduces limestone slurry with the flue gas in a spray tower. The sulfur 

dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The 

overall reactions are shown in the following equations: 

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

When lime (or limestone) is used as the reagent for SO2 removal, additional equipment is needed for 

preparing the lime/limestone slurry and collecting and concentrating the resultant sludge. Calcium 

sulfite sludge is watery; it is typically stabilized with fly ash for land filling. The calcium sulfate 

sludge is stable and easy to dewater. To produce calcium sulfate, an air injection blower is needed to 

supply the oxygen for the second reaction to occur. 

The normal SO2 control efficiency range for SO2 scrubbers is 80% to 90% for low efficiency 

scrubbers and 90% to 95% for high efficiency scrubbers 

Spray Dryer Absorption 

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is 

absorbed by the slurry, forming CaSO3/CaSO4 per the reactions described in wet scrubbing. The 

liquid-to-gas ratio is such that the water evaporates before the droplets reach the bottom of the tower. 

The dry solids are carried out with the gas and collected with a fabric filter. Further SO2 removal 

occurs as the flue gas flows through the lime powder adhered filter cake on the bags. 

The normal SO2 control efficiency range for dry SO2 scrubbers is 70% to 90%. 
 

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Wet Walled Electrostatic Precipitator (WWESP) 

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. The SO2 removal reactions are as follows: 

Na+ + OH- + SO2 + → Na2SO3 

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

A caustic scrubbing solution produces a liquid waste. 

The SO2 control efficiency for a WWESP is approximately 80%. 

Dry Sorbent Injection 

Dry sorbent injection is a post-combustion SO2 control technology in which pulverized lime or 

limestone is directly injected into the duct upstream of the fabric filter. Dry sorption of SO2 onto the 

lime or limestone particle occurs and the solid particles are collected with a fabric filter. This 

process was developed as a lower cost option to conventional SDA technology. Since the sorbent is 

injected directly into the exhaust gas stream, the mixing offered by the dry scrubber tower is not 

realized. 

The maximum efficiency for this SO2 control technology is estimated to be 50 percent. 
 

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2. Step 2 – Eliminate Technically Infeasible Options 

Two of the proposed technologies discussed in Step 1 are infeasible. The feasibility analysis is 

summarized as follows: 

Table III A-2 

SO2 Emission Control Technology Feasibility Analysis

Technology Description Feasible? 

Yes or No 

Typical 

% Efficiency 

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 70% - 95% 

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 70% - 90% 

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 80% 

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 50% 

Wet Scrubbing / Flue-Gas Desulfurization 

A wet scrubber is technically feasible in this application. 
 

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Spray Dryer Absorption 

A spray dryer absorption system is technically infeasible in this application. 

Spray dryer absorption requires use of a filter baghouse to collect the spent sorbent. Use of a fabric 

filter is technically infeasible for collection of spent spray dryer sorbent in this application due to 

potential filter blinding associated with water condensation. Exhaust gases from the pelletizing 

process have a 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 were 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 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. 

Wet Electrostatic Precipitator 

A Wet ESP is feasible in this application. The NSM taconite plants currently employ this technology. 

Dry Sorbent Injection 

Dry Sorbent Injection (SDI) is infeasible in this application. 

Since this technology is similar to SDA, it is also technically infeasible. 

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

The SO2 emission control rankings are summarized as follows: 

Table III A-3 

SO2 Control Technology Ranking 

Rank Technology Typical 

% Efficiency 

Estimated Furnace #5 % 

Control Efficiency

1 Wet Scrubber 70% - 95% 80% 

Vendor Information 

2 Wet Electrostatic 

Precipitator 80% 

80% 

NSM Wet ESP 

performance 
 

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Wet Scrubbing / Flue-Gas Desulfurization

The normal control efficiency range for SO2 scrubbers is 70% to 95%. Given the relatively low SO2

concentrations in the Furnace #5 exhaust gas, a control efficiency of 80% is expected. The scrubber 

vendor verified that 80% control was feasible for this application. Since the SO2 emission rate is 

relatively low, a higher control efficiency will not make a significant change in the pollution control 

cost ($/ton removed). 

Wet Walled Electrostatic Precipitator 

The SO2 control efficiency for a WWESP is approximately 80%. This efficiency is based on NSM’s 

operating experience with wet ESP technology. 

4. Step 4 – Evaluate Most Effective Control Technologies and Document 

Results 

Emissions control effectiveness was evaluated for the top two control technologies, wet scrubbing 

and wet ESP’s. The control equipment effectiveness analysis can be summarized as follows: 

Table III A-4 

SO2 Control Technology Emission Control Cost Analysis 

Rank Technology Control Cost $/ton 

1 Wet Scrubber $9,073/ton 

2 Wet ESP $13,385/ton 

A summary of the control cost analysis is located in BACT Attachment 2, Table 1. The control cost 

analyses for each control system are located in BACT Attachment 2 Tables 2 and 3. Please note that 

both evaluations have not accounted for the additional expense of demolition and site specific 

installation costs associated with construction at an existing facility which will increase the $/ton 

control cost. 
 

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A. Economic impacts 

The control cost analysis suggests that installation of new control equipment for both 

technologies is economically infeasible at this time. Therefore the existing controls should be 

considered BACT for SO2. 

Wet scrubber and wet ESP control cost calculations were prepared using caustic as the base in 

the scrubbing liquor. Lime and limestone are potential alternatives, but additional equipment will 

be needed for slurry preparation and for solids separation from the sludge generated in the 

scrubber. Construction materials must also be suitable for caustic, lime, or limestone. This could 

add to the cost of wet scrubbing of SO2. 

Both wet scrubbing and the Wet ESP’s also have the option of being used to control PM. 

B. Environmental impacts 

The primary environmental impact of wet scrubbers and wet ESP’s is the generation of 

wastewater and sludge. Waste from the scrubber will increase the sulfate and solids loading in 

the facility’s wastewater. This places additional burdens on a facility’s wastewater treatment and 

solid waste management capabilities. 

Scrubber and Wet ESP exhaust gases are saturated with water, thus creating a visible plume. 

Plume visibility may be a local/community concern. Once the exhaust mixes with sufficient air, 

the moisture droplets evaporate, and the plume is no longer visible. 

Given that NSM currently uses wet ESP’s these impacts are not significant and restarting Furnace 

5 is not likely to cause an adverse environmental impact. 

C. Energy impacts 

A scrubber operates with a high pressure drop, resulting in a significant amount of electricity 

required to operate the blower and pump. In comparison, the Wet ESP has a lower pressure drop 

requirement than the scrubber and the cost to operate the electrical field is not as significant as 

the electrical costs for the wet scrubber. 
 

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5. Step 5 – Select BACT 

A wet ESP is selected as BACT for control of SO2 from Furnace #5. A wet ESP was selected 

because it is one of top control technologies for SO2 control in this application, and Furnace #5 is 

currently equipped with a wet ESP. Performance test data for similar equipment at NSM show 

that wet ESP’s control SO2 concentrations to very low levels (1 ppm to 3 ppm), and a wet 

scrubber will not perform any better in this application. In addition, the control cost analysis 

shows that installation of new control equipment is economically infeasible (SO2 control costs 

are close to or above $10,000/ton). Therefore, NSM proposes continued use of the existing wet 

ESP control system as BACT. 

 The proposed BACT limits are 12.7 lb/hr SO2 on a 24 hour average basis and a performance 

standard of 8 ppm SO2. Test for SO2 using EPA Method 6 or 6C. The proposed emission limits 

represent SO2 concentrations of 8 ppm in the control equipment exhaust. This concentration is 

at the limit of concentrations which any type of SO2 control technology can attain. 

The proposed BACT limit is based on the highest level of emission control that can be achieved 

with existing equipment. Performance test data from NSM induration furnaces 6, 11 and 12 

show emission rates of 0.6 lb/hr to 2.4 lb/hr per stack while combusting natural gas. Since 

Furnaces 11 and 12 are of a different design than Furnace 5, the mass emission rates are not 

equivalent. SO2 stack concentrations were in the 1 ppm to 3 ppm range. The proposed BACT 

limits are based on the tested emission rate plus 7.97 lb/hr of SO2 from fuel oil firing. 

The historical performance test data used as the basis for the proposed BACT are summarized in 

Attachment 3, Table 1. 

B. Nitrogen Oxide (NOx) Emission Controls 

1. Step 1 – Identify all Control Technologies 

Seven different control technologies were evaluated for NOx emissions from Furnace #5. All of 

these technologies have been determined technically infeasible for Furnace #5, because operating 

conditions are not consistent with the process requirements of the control equipment. 
 

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EPA’s RACT, BACT, LAER Clearinghouse (RBLC) database was checked for recent BACT 

determinations in the mineral and metallic processing industries. The results of this evaluation are in 

BACT Attachment 1, Tables 1 and 2. While most of the BACT determinations were for sources that 

are not directly applicable to this project, the control technologies evaluated in this study are 

consistent with those found in the RBLC. The proposed BACT limits are consistent with the level of 

emission control found in RBLC for similar industries, after taking process limitations and NSM’s 

site specific conditions into account. The control technologies evaluated for NOx emissions control 

from Furnace #5 are as follows. 
 

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Table III B-1 

NOx Emission Control Technologies Considered for BACT Analysis 

Technology Description 

Selective Catalytic 

Reduction 

Selective catalytic reduction (SCR) is a post-combustion NOx 

control technology in which ammonia (NH3) is injected into the flue 

gas stream in the presence of a catalyst. NOx is removed through 

chemical reaction. SCR requires a temperature range of 500°F – 

800°F. 

Selective Non-Catalytic 

Reduction 

In the selective non-catalytic reduction (SNCR) process, urea or 

ammonia-based chemicals are injected into the flue gas stream to 

convert NO to N2 and water. Without the participation of a catalyst, 

the reaction requires a high temperature range to obtain activation 

energy. The optimum operating temperature for SNCR is 1,600°F 

to 2,000°F. 

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.

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 . 

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. Staged fuel combustion is 

typically the most effective method. 

Induced flue gas recirculation burners, also called ultra low-NOx 

burners, combine the benefits of flue gas recirculation and low-NOx 

burner control technologies. The burner is designed to draw flue 

gas to dilute the fuel in order to reduce the flame temperature. 

These burners also utilize staged fuel combustion to further reduce 

flame temperature. 

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. 

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. 
 

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Selective Catalytic Reduction 

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

(NH3) or urea is injected into the flue gas stream in the presence of a catalyst. NOx is removed 

through the following chemical reaction: 

1) (NH2)2CO + H2O 2 NH3 + CO2

2) 4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O 

3) 2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O 

A catalyst bed containing metals in the platinum family is used to lower the activation energy 

required for NOx decomposition. SCR requires a temperature range of 500°F – 800°F for a normal 

catalyst. The optimum operating temperature range is 700°F to 750°F. A high temperature zeolite 

catalyst is also available; it can operate in the 600 °F – 1000°F temperature range. However, these 

catalysts are very expensive. 

The normal NOx control efficiency range for SCR is 70% to 90%. 

Selective Non-Catalytic Reduction 

In the selective non-catalytic reduction (SNCR) process, urea or ammonia-based chemicals are 

injected into the flue gas stream to convert NO to N2 and water. 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 + 1/4 O2 → N2 + 3/2 H2O 

NH3 + 1/4 O2 → NO + 3/2 H2O 

The optimum operating temperature for SNCR is 1,600°F to 2,000°F. Under these conditions 

reaction (1) dominates, and a significant reduction in NOx occurs. At temperatures above 2,000°F 

reaction (2) begins to dominate and NOx control efficiency decreases rapidly. 

The normal NOx control efficiency range for SNCR is 50% to 70%. 

Non-Selective Catalytic Reduction 

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas 

treatment system. It is often referred to as “three-way conversion” catalyst since it reduces NOx, 
 

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unburdened hydrocarbons (UBH), and CO simultaneously. NOx and CO react in the presence of 

NSCR catalyst to form nitrogen (N2) and carbon dioxide (CO2). In order to operate properly, the 

combustion process must be near-stoichiometric conditions. SCONOxTM is a commercially available 

example of an NSCR system. SCONOxTM employs a single catalyst that simultaneously oxidizes CO 

to CO2 and NO to NO2. NO2 formed by the oxidation of NO is subsequently absorbed onto the 

catalyst surface through the use of a potassium carbonate absorber coating. CO2 produced by these 

reactions is released to the atmosphere. The potassium carbonate catalyst coating reacts with NO2 to 

form potassium nitrites and nitrates. Prior to saturation of the potassium carbonate coating, the 

catalyst must be regenerated. 

SCONOxTM is typically employed in clean gas services such as natural gas fired turbines. The 

SCONOxTM catalyst is very sensitive to contaminants in the waste gas and would not be viable in 

induration waste gas service. 

NOx control efficiency for NSCR is approximately 90% in clean combustion applications. 

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 addition of flue gas reduces the oxygen content of 

the “combustion air” (air + flue gas) in the burner. The lower oxygen level in the combustion zone 

reduces flame temperatures; which in turn reduces NOx emissions. 

The normal NOx control efficiency range for EFGR is 30% to 50%. 

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. LNB is a staged 

combustion process that is designed to split fuel combustion into two zones, primary combustion and 

secondary combustion. This analysis utilizes the staged fuel design in the cost analysis because lower 

emission rates can be achieved with staged fuel burner than with a staged air burner. 

In the primary combustion zone of a staged fuel burner, NOx formation is limited by a rich (high 

fuel) condition. Oxygen levels and flame temperatures are low; this results in less NOx formation. In 
 

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

reducing agents. In a reducing atmosphere, nitrogen compounds are preferentially converted to 

molecular nitrogen (N2) over nitric oxide (NO). 

The estimated NOx control efficiency for Low NOx burners in high temperature applications is 25%. 

Induced Flue Gas Recirculation Burners 

Induced flue gas recirculation burners, also called ultra low-NOx burners, combine the benefits of 

flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue 

gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel 

combustion to further reduce flame temperature. 

The estimated NOx control efficiency for IFGR burners in high temperature applications is 50%. 

Low Excess Air (LEA) 

Due to the oxidizing atmosphere of indurating furnaces, the low excess air option cannot be 

employed for Furnace 5. 

Combustion Controls 

Overfire Air (OFA) - The OFA option is primarily geared to fuel-bound NOx reductions, which are 

no the major source of NOx in this process. Fuel is combusted in an oxygen deficient atmosphere to 

inhibit NOx formation. Overfire air is added after the burner to complete the fuel combust process. 

Burners Out of Service (BOOS) and Load Reduction -The BOOS and load reduction options 

incorporate a reduction in the furnace load, thereby reducing the formation of NOx emissions. 

Reduced Combustion Air Temperature – Reducing combustion air temperature inhibits thermal 

NOx production. This option is limited to processes with combustion air pre-heaters that allow 

reduced process temperatures. 

Low Temperature Oxidation - Low temperature oxidation (LTO) is an emerging NOx control 

technology. There are very few applications of this technology, and there are currently no 

applications of this technology at a taconite plants in the US. LTO requires a supply of pure oxygen 

to operate. In most cases this would require construction of an air refrigeration plant to produce 

oxygen for the LTO process. So, in addition to limited application of LTO technology; LTO is 
 

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generally economically infeasible. Therefore, it was not given additional consideration as a viable 

technology for the Furnace 5 Restart Project 

LTO utilizes ozone as a medium to oxidize various pollutants including NOx. In the system, NOx in 

the flue gas is oxidized by means of ozone to form nitrogen trioxide or nitrogen pentoxide. These 

compounds react with water vapor to form nitric acid. The nitric acid vapor is then absorbed as 

dilute nitric acid and is neutralized by the sodium hydroxide in the scrubbing solution to form sodium 

nitrate. The sodium nitrate is separated and discharged to the wastewater system. LTO is typically 

employed at locations where the nitrate byproduct and be used or recycled. 

BOC Gases’ Lo-TOx is an example of a commercially available version of an LTO system that was 

evaluated by Barr in 2001 for a potential new taconite plant. Lo-TOx technology uses ozone to 

oxidize NO to NO2 and NO2 to N2O5 in reactor. The N2O5 is converted to HNO3 in a scrubber, and is 

removed with caustic. The LTO reactions are as follows: 

O3 + NO → O2 + NO2 

NO2 + O3 → 2 N2O5 

N2O5 + H2O → 2 HNO3 

NaOH + HNO3 → NaNO3 + H2O 

The normal NOx control efficiency range for Lo-TOx is 80% to 95%. 

Lo-TOx would require a minimum of two process columns, a reactor for NOx oxidation, and a 

scrubber for nitrate removal. In addition, an ozone generator with a supply of liquefied oxygen would 

be required. As a result of equipment requirements, this is a rather expensive control technology. 

Nitrates are produced as a byproduct of this control technology. At a taconite plant, there is no place 

to utilize these nitrates, so this wastewater would be routed to the tailings basin. Nitrates in the 

tailings basin would pose a threat to ground and surface water. 

 Table 13, BACT Attachment 2 contains cost estimates for application of Lo-TOx technology to 

Furnace #5. The estimated control cost is $14,500/ton. The estimate is based on a paper presented 

by BOC gases “LoTOx Process Flexibility and Multi –Pollutant Control Capability”. Supplemental 

information from a BOC bid for a 2001 BACT analysis conducted by Barr Engineering Company for 

a proposed new taconite processing facility. 

During the 2001 BACT analysis, Barr contacted Tri-Mer Corporation, the manufacturer of the TriNOx® LTO system, to determine the applicability of LTO at a potential new taconite plant in 2001. 
 

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The vendor stated that Tri-NOx® LTO system is not commercially available for use on a taconite 

pellet induration furnace. Tri-Mer stated that the magnitude of the air streams from an induration 

furnace is too large for the chemistry used in the Tri-NOx® system to reduce NOx effectively. 

LTO is not considered for further review in this BACT analysis. 

2. Step 2 – Eliminate Technically Infeasible Options 

Seven different control technologies were evaluated for NOx emissions from the Furnace #5. All of 

these have been determined technically infeasible for Furnace #5 because its operating conditions are 

not consistent with the process requirements of the control equipment. The control technology 

feasibility analysis is summarized as follows. 
 

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Table III B-2 

NOx Emission Control Technology Feasibility Analysis

Technology Description Feasible? 

Yes or No 

Typical 

% Efficiency 

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 

70% - 90%. 

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 50% - 70% 

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 90% 

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. The lower 

oxygen level in the combustion zone reduces flame 

temperatures; which in turn reduces NOx. 

No 30% - 50% 

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 25% - 50% 

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 NA 

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 NA 
 

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Selective Catalytic Reduction 

Selective catalytic reduction (SCR) is not technically feasible in this application. 

The first issue in the application of SCR is achieving the appropriate temperatures for NOx reduction 

reactions to occur. SCR requires a temperature range of 500°F – 800°F. There are no access points 

for installation of an SCR reactor in Northshore Mining Co.’s Furnace #5 where these temperatures 

exist. Process temperatures downstream of the existing wet ESP or a wet scrubber are too cold for 

SCR. 

The last concern in application of SCR is catalyst poisoning. Catalyst poisons include arsenic, lead 

alkali earth metals, SO2 and halogens. Particulate matter can block catalyst pores, and water vapor 

also adversely affects NOx conversion. All of these materials are present in the Furnace #5 exhaust 

gas SCR is technically infeasible. 

Installation of SCR in conjunction with a reheat system after a wet emission control systems is 

generally not considered practical. This is due to high energy demands for reheating exhaust gas 

up to SCR catalyst operating temperatures. Reheat costs also make this option economically 

infeasible. The estimated NOx control cost of SCR with reheat for Furnace 5 is $25,982 per ton 

NOx removed. 

Selective Non-Catalytic Reduction 

SNCR is not technically feasible in this application. 

The main issue in the application of SNCR is achieving the appropriate temperatures for NOx

reduction reactions to occur. The operating temperature range for SNCR is 1,600°F to 2,000°F. 

Temperatures at the outlet of the furnace are 2,400oF; well above SNCR temperature range. There 

are no access points for installation of an SCR reactor within NSM’s Furnace #5 pellet preheat train 

where SNCR operating temperatures occur. The furnace exhaust gas temperature as it leaves the 

furnace 140oF; so, the minimum design temperature of 1,700°F for SNCR cannot be met. 

Non-Selective Catalytic Reduction 

Non-Selective Catalytic Reduction is not feasible in this application. 
 

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Non-selective catalytic reduction (NSCR) catalysts are very sensitive to catalyst poisoning. For that 

reason, they are only used in clean combustion applications such as natural gas fired turbines. NSCR 

is not feasible in this application due the catalyst poisons present in the Furnace #5 exhaust gas. 

External Flue Gas Recirculation 

External Flue Gas Recirculation is not feasible in this application. 

Northshore Mining Co.’s Indurating Furnaces operate at temperature of 2,400° F. External Flue Gas 

Recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures in order to 

reduce NOx emissions. EFGR is not feasible in this application because the reduced flame 

temperatures associated with EFGR would adversely affect taconite pellet product quality. 

Low-NOx Burners and Induced Flue Gas Recirculation Burners 

Low-NOx Burners and Induced Flue Gas Recirculation Burners are not feasible in this application. 

Northshore Mining Co.’s Indurating Furnaces operate at temperature of 2,400° F. Low-NOx burner 

(LNB) technology and induced flue gas recirculation burners both reduce flame temperatures in order 

to reduce NOx emissions. Low NOx burners are not feasible in this application because the reduced 

flame temperatures would adversely affect taconite pellet product quality. 

Low Excess Air (LEA) 

Low Excess Air combustion controls are infeasible in this application. 

Indurating Furnaces must operate at high levels of excess air. Therefore LEA controls cannot be 

used because they are not consistent with the requirements of the induration process. 

Combustion Controls 

The following combustion controls are not technically feasible in this application. 

Overfire Air (OFA) – To control NOx emissions using OFA, fuel is combusted in an oxygen 

deficient atmosphere to inhibit NOx formation. Overfire air is added after the burner to complete the 

fuel combust process. In the induration process, high oxygen levels must be maintained to ensure 

proper oxidation of the taconite iron ore. Use of OFA would adversely affect product quality 
 

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because the use of OFA would not match the need for high oxygen content throughout the furnace to 

meet taconite pellet product quality specifications. 

Burners Out of Service (BOOS) and Load Reduction -The BOOS and load reduction options 

incorporate a reduction in the furnace load, thereby reducing the formation of NOx emissions. This 

technique is only applicable for existing sources operating well below capacity. The Furnace #5 

design does not contain sufficient excess capacity to use this method. 

Reduced Combustion Air Temperature – Reducing combustion air temperature inhibits thermal 

NOx production by reducing flame temperatures. This is not possible in an indurating furnace 

because it must operate at temperatures near 2,400° F. Reducing the level of air preheat would drop 

the combustion temperatures needed to maintain product quality due to incomplete oxidation. 

Therefore, reducing combustion air temperature is not technically feasible. 

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

The emission control effectiveness ranking of NOx control technologies are as follows: 

Table III B-3 

NOx Control Technology Ranking 

Rank Technology Typical 

% Efficiency 

Furnace #5 Estimated 

% Control Efficiency 

1 No controls NA NA 

As noted in step 2, all control technologies are technically infeasible. 

4. Step 4 – Evaluate Most Effective Control Technologies and Document 

Results 

At this time, there is no viable control technology in this application. The control effectiveness 

analysis is summarized as follows. 
 

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Table III B-4 

NOx Control Technology Emission Control Cost Analysis 

Rank Technology Control Cost $/ton 

1 No controls NA 

As noted in step 2, all control technologies are technically infeasible. 

The control cost for use of SCR in conjunction with re-heating the furnace exhaust was examined to 

ensure that the BACT analysis is complete. This analysis shows that this combination is 

economically infeasible. In addition, this option uses a significant amount of energy. 

5. Step 5 – Select BACT 

The technical feasibility analysis shows that installation of control equipment is technically 

infeasible. Therefore NSM proposes to set BACT limits based on actual emissions from a 

similar source at NSM’s Silver Bay facility. The proposed BACT limits are 45.7 lb/hr NOx on a 

24 hour average basis and a performance standard of 40 ppm NOx for Furnace 5. Test for NOx

using EPA Method 7 or 7E. 

The proposed BACT limit is based on actual emissions test data as measured in Furnace 6, an 

induration furnace of the same design as Furnace 5. Performance test data from NSM induration 

Furnace 6 show NOx emissions of 13.23 lb/hr NOx on a per stack basis, and NOx concentrations 

of 32 ppm and 36 ppm. Since test data are limited, the proposed BACT limits are based on the 

tested emission rate of 39.7 lb/hr of NOx plus a 15% safety factor and the maximum NOx

concentration plus a 15% safety factor. 

The historical performance test data used as the basis for the proposed BACT are summarized in 

Attachment 3, Table 1. 
 

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C. Particulate Matter (PM / PM10) Emission Controls 

Five different control technologies were evaluated for particulate emissions from Furnace #5. One of 

these has been determined technically infeasible for Furnace #5 due to operating conditions which 

are not consistent with the process requirements of the control equipment. 

As noted in the introduction to this section, particulate matter from Furnace #5 comes from the 

taconite pellet induration process and from combustion byproducts. This combination of sources 

yields both filterable and condensable particulate matter. 

EPA’s RACT, BACT, LAER Clearinghouse (RBLC) database was checked for recent BACT 

determinations in the mineral and metallic processing industries. The results of this evaluation are in 

BACT Attachment 1, Tables 1 and 2. While most of the BACT determinations were for sources that 

are not directly applicable to this project, the control technologies evaluated in this study are 

consistent with those found in the RBLC. The proposed BACT limits are consistent with the level of 

emission control found in RBLC for similar industries, after taking process limitations and NSM’s 

site specific conditions into account. The control technologies evaluated for particulate matter 

emissions control from Furnace #5 are as follows. 

1. Step 1 – Identify all Control Technologies 

The following control technologies were evaluated for PM emissions control from Furnace #5. 
 

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Table III C-1 

PM / PM10 Emission Control Technologies Considered for BACT Analysis 

Technology Description 

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. 

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. 

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. 

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. 

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. 

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 particulate is periodically removed from the bags and collected in hoppers located beneath 

the bags. A number of methods are employed to facilitate the removal of particulate from the bags, 

including shaking, reverse air flow, and pulse air flow. 

The normal PM control efficiency range for a fabric filter is 98% to 99+% for filterable particulate 

matter. The control of condensable particulate matter by fabric filters is limited by the operating 
 

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temperature of the filter vs. the condensation temperatures of the compounds present in the 

condensable particulate matter. 

Wet Scrubbers 

Wet scrubbers remove particles from waste gas by capturing the particles with liquid droplets 

(usually water) and separating the droplets from the gas stream. The droplets transport the particulate 

out of the gas stream. 

Scrubbers capture the particulates through the following mechanisms: 

1. Impaction of the particle directly into a target droplet 

2. Interception of the particle by a target droplet as the particle comes near the droplet 

3. 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 and venturi jet scrubbers. 

The normal PM control efficiency range for a scrubber is 90% to 95% for a low efficiency scrubber 

and 95% to 99+% for a high efficiency scrubber. A wet scrubber is relatively effective in controlling 

condensable particulate matter due to its low operating temperature and the solubility of some 

condensable materials in the scrubbing water. 

Electrostatic Precipitator 

An electrostatic precipitator (ESP) is a potential control method for particulates in the Furnace 5 

exhaust. An electrostatic precipitator applies electrical forces to separate suspended particles from 

the flue gas stream. The suspended particles are given an electrical charge by passing through a highvoltage DC corona region in which gaseous ions flow. 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. 

The normal PM control efficiency range for an ESP is 98% to 99+%. The control of condensable 

particulate matter by ESP’s is limited by the operating temperature of the filter vs. the condensation 

temperatures of the compounds present in the condensable particulate matter. 
 

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Wet Electrostatic Precipitator 

A Wet WESP operates on the same collection principles as a dry ESP, and uses a water spray to 

remove particulate matter from the collection plates. 

The normal PM control efficiency range for a WWESP is 98% to 99+%. A wet ESP may also be 

relatively effective in controlling condensable particulate matter due to its low operating temperature 

and the solubility of some condensable materials in the scrubbing water. 

Centrifugal (Cyclone) Separator 

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. 

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. 

A typical emission control rate for a multiclone is 50% to 80%. The control of condensable 

particulate matter by centrifugal separation is limited by the operating temperature of the filter vs. the 

condensation temperatures of the compounds present in the condensable particulate matter. 

The control efficiency for cyclone separators is less for small particles than larger particles. Particle 

size distribution data is necessary to properly determine the control efficiency for a specific 

application. 

2. Step 2 – Eliminate Technically Infeasible Options 

Five different control technologies were evaluated for particulate emissions from Furnace #5. One of 

these has been determined technically infeasible for Furnace #5 due to Furnace #5 operating 

conditions which are not consistent with the process requirements of the control equipment. The 

technical feasibility analysis is summarized as follows. 
 

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Table III C-2 

PM / PM10 Emission Control Technology Feasibility Analysis 

Technology Description Feasible? 

Yes or No 

Typical 

% Efficiency 

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 98 - 99% 

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 95%-99+% 

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 98% - 99+% 

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 98% - 99+% 

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 50% - 80% 
 

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Fabric Filter 

A fabric filter (baghouse) is infeasible in this application. 

Fabric filters are infeasible in this application due to filter blinding associated with water 

condensation. The exhaust gas from Furnace 5 has a 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 were 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 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 be removed from the filters. 

Wet Scrubbers 

A wet scrubber is feasible in this application 

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 and venturi jet scrubbers. 

 The normal PM control efficiency range for a scrubber is 90% to 95% for a low efficiency scrubber 

and 95% to 99+% for a high efficiency scrubber. 

Electrostatic Precipitator 

An electrostatic precipitator (ESP) is feasible in this application. The two taconite plants in the 

upper Michigan peninsula currently use ESP’s for particulate matter control. 

An electrostatic precipitator applies electrical forces to separate particulate matter from flue gas. 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. For an ESP 

to work, the rapping system must be able to remove the material collected on the plates. Highly 

conductive materials tend to retain their electrical charge and are difficult to remove from the 
 

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collection plates. Given the magnetic nature of some iron ores, this might pose a problem in some 

cases. Since ESP’s are currently used on taconite plants in Michigan, this study will assume that 

they are technically feasible. 

The normal PM control efficiency range for an ESP is 98% to 99+%. 

Wet Electrostatic Precipitator 

A wet electrostatic precipitator (ESP) is feasible in this application. 

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. A water spray system is more effective than rapping 

systems in removing particulates. Therefore, a wet ESP may not have the problems that a standard 

ESP has in removing conductive material. Wet ESP’s are currently used at this facility. 

The normal PM control efficiency range for a WWESP is 98% to 99+%. 

Centrifugal (Cyclone) Separator 

Centrifugal separators are feasible in this application. 

A typical emission control rate for a multiclone is 50% to 80%. The control efficiency for cyclone 

separators is less for small particles than larger particles. 

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

Emissions control effectiveness was evaluated for the top four control technologies. Due to the 

configuration of NSM’s induration furnaces, control equipment inlet concentrations cannot be 

measured. So, actual control efficiencies cannot be determined. Therefore this analysis is based on 

typical control efficiencies found in literature data. The control equipment effectiveness analysis can 

be summarized as follows: 
 

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Table III C-3 

PM / PM10 Control Technology Ranking

Rank Technology Typical 

% Efficiency 

1 

Wet Electrostatic 

Precipitator 

98% - 99+% 

2 Wet Scrubber 95% - 99+% 

3 Dry Electrostatic 

Precipitator 

98% - 99+% 

4 Centrifugal Separation 

(e.g. Cyclones) 

50% - 80% 

4. Step 4 – Evaluate Most Effective Control Technologies and Document 

Results 

Emissions control effectiveness was evaluated for the top three control technologies, wet scrubbing 

and Wet ESP controls. Control cost estimates are based on meeting the MACT standard; the control 

device was sized to meet this standard. The control equipment effectiveness analysis can be 

summarized as follows: 

Table III C-4 

PM / PM10 Control Technology Emission Control Cost Analysis 

Rank Technology Control Cost $/ton 

1 Wet ESP $4796 

2 Dry ESP $2139 

3 Wet Scrubber $3166 

A summary of the control cost analysis is located in BACT Attachment 2, Table 1. The control cost 

analyses for individual controls are located in BACT Attachment 2 Tables 6, 7 and 8. 

Wet Walled Electrostatic Precipitator 

Performance of the wet ESP’s has been proven in practice at Northshore Mining. The particulate 

matter control cost for a new precipitator is $4,796/ton. The control cost for the existing wet ESP 
 

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will be considerably less, since no capital expenses will be required and only operational and repair 

expenses will be incurred. In addition, NSM already has the infrastructure needed to accommodate 

operation of wet walled ESP’s. See Attachment B for the control cost analysis. 

The non-air environmental impact of a wet ESP is the need to treat the wastewater discharged from 

the wet ESP. NSM currently has the wastewater treatment capacity to treat water from the #5 

Furnace 

A wet walled ESP has a moderate energy use rate. ESP’s have a low pressure drop, so, a modest 

electricity use rate is needed to operate the air blower. Operation of the electric grids does not add 

significantly to the overall electrical consumption. 

Dry Electrostatic Precipitator 

A dry ESP has a moderate energy use rate. ESP’s have a low pressure drop, so, a modest electricity 

use rate is needed to operate the air blower. Operation of the electric grids in the EPS does not add 

significantly to the overall electrical consumption. 

Performance of the ESP’s has been proven in practice at the Michigan taconite plants. The 

particulate matter control cost for a new precipitator is $2139/ton. See Attachment B for the control 

cost analysis. 

The non-air environmental impact of a ESP is the need to dispose of the solid waste collected in the 

ESP. 

A dry ESP has a moderate energy use rate. ESP’s have a low pressure drop, so, a modest electricity 

use rate is needed to operate the air blower. Operation of the electric grids does not add significantly 

to the overall electrical consumption. 

Wet Scrubbing 

The particulate matter control cost for a wet scrubber is $3,166/ton. See Attachment B for the 

control cost analysis. 

The non-air environmental impact of a wet scrubber is the need to treat the wastewater discharged 

from the scrubber. 
 

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A wet scrubber has the highest energy use rate of the control technologies studied. A high efficiency 

wet scrubber operates with a high pressure drop in order to achieve high collection efficiency. This 

results in a higher electricity use rate than the other controls to operate the air blower. 

5. Step 5 – Select BACT 

The proposed BACT limit for Furnace 5 is a performance limit of 0.01 gr PM/dscf on a 24 hour 

average basis. To establish compliance limits, NSM will test for filterable + organic condensable 

PM using EPA Method 5 and MN 7011.0725 using three (3) one-hour test runs. During the 

performance test, the facility will measure emission control equipment process parameters. 

Process parameter limits for operating the Furnace 5 emission control equipment will be set 

using the data collected during the performance test. The facility will demonstrate ongoing 

compliance based on the 24 hour average(s) of the process parameters established during the 

performance test. 

NSM is proposing a concentration of 0.01gr/dscf for Furnace 5 because it is essentially the limit 

of particulate emission control technology removal capability in this service as demonstrated by 

stack test data for similar sources at NSM. Furnace 5 is equipped with a fixed speed fan for 

moving exhaust gas through the control equipment. Since Furnace 5 has a constant exhaust flow 

rate, setting a PM concentration limit for BACT also limits the maximum mass emission rate 

from this source. So, additional emission limits are not needed. 

The proposed BACT limit is based on the highest level of emission control that can be achieved 

with Wet ESP’s in this application. Performance test data from NSM induration furnaces 6, 11 

and 12 show post control stack concentrations of 0.006 gr/dscf to 0.01 gr/dscf. while combusting 

natural gas. Stack testing included methods used to measure filterable PM and condensable 

organic PM. The tests also include operation of the wet EPS’s with and without electric power. 

The proposed BACT limits are based on the highest tested concentration of 0.01 gr/dscf. 

The proposed BACT limit is consistent with recent RBLC determinations for sources in the 

mineral processing industries (metallic and non-metallic). The RBLC database shows BACT 

determinations for mineral processing sources in the 0.003 – 0.01 gr/dscf range. Since these 

determinations are for several different types of processing equipment, they are indicative of the 

level of emission control that is possible in the industries covered by this source category. 
 

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However, differences in conditions at individual sources affect the level of emission controls 

possible at a particular source 

NSM cannot propose a control efficiency based BACT limit for this source. No test data are 

available for the uncontrolled emission rate from this source due to the duct configuration on the 

inlet to the wet ESP’s. Therefore, control efficiency cannot be determined for this source. 

The “typical” control efficiencies listed in the previous section are literature values which are 

consistent with control efficiencies found in a wide variety of applications. They may represent 

conditions which include higher uncontrolled emission rates, and in some cased higher 

controlled emission rates. 

The historical performance test data used as the basis for the proposed BACT are summarized in 

Attachment 3, Table 1. 

 

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IV. Fine Crushing 

Fine crushing of the iron ore is a dry process. Both the crushing operations and material movement 

within the crushing section produce dust. This BACT report will address emission controls for dust 

emissions from ore crushing associated with the Furnace 5 Reactivation Project. 

A. Particulate Matter (PM / PM10 ) Emission Controls 

1. Step 1 – Identify all Control Technologies 

EPA’s RACT, BACT, LAER Clearinghouse (RBLC) database was checked for recent BACT 

determinations in the mineral and metallic processing industries. The results of this evaluation are in 

BACT Attachment 1, Tables 1 and 2. While most of the BACT determinations were for sources that 

are not directly applicable to this project, the control technologies evaluated in this study are 

consistent with those found in the RBLC. The proposed BACT limits are consistent with the level of 

emission control found in RBLC for similar industries, after taking process limitations and NSM’s 

site specific conditions into account. The control technologies evaluated for PM emissions control 

from dryers are as follows. 

The following control technologies were evaluated for PM emissions control from fine crushing: 
 

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Table IV A-1 

PM / PM10 Emission Control Technologies Considered for BACT Analysis

Technology Description 

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. 

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. 

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. 

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. 

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. 

2. Step 2 – Eliminate Technically Infeasible Options 

The particulate matter control technologies evaluated for the dryer exhaust streams are technically 

feasible. The technical feasibility is summarized as follows: 
 

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Table IV A-2 

PM / PM10 Emission Control Technology Feasibility Analysis

Technology Description Feasible? 

Yes or No 

Typical 

% Efficiency

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 98% - 99+% 

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 

95%-99+% 

(high 

efficiency 

scrubbers) 

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 98% - 99+% 

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 98% - 99+% 

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 50% - 80% 

All listed control technologies are technically feasible for particulate emission control for fine 

grinding/crushing. 
 

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3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

Fabric filters are the most effective control technology in this application. The control technology 

rankings are as follows: 

Table IV A-3 

PM / PM10 Control Technology Ranking 

Rank Technology Typical 

% Efficiency 

1 

Fabric Filter 

(Baghouse) 

98% - 99+% 

2 Wet Scrubber 95% - 99+% 

3 Wet Electrostatic 

Precipitator 98% - 99+% 

4 Centrifugal Separation 

(e.g. Cyclones) 

50% - 80% 

The fine crushing exhaust streams contains only dry particulate matter. Under these conditions, 

fabric filters have the highest particulate matter control efficiency. 

4. Step 4 – Evaluate Most Effective Control Technologies and Document 

Results 

The fine crushing equipment associated with the Furnace 5 Restart project at Northshore Mining Co. 

currently has fabric filters (baghouses) for control equipment. Since fabric filters have the highest 

particulate matter control efficiency in this application, additional analysis is not required. 
 

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Table IV A-4 

PM / PM10 Control Technology Emission Control Cost Analysis 

Rank Technology Control Cost $/ton 

1 

Fabric Filter 

(Baghouse) Top Emission Controls Selected 

2 Wet Scrubber 

NA 

3 Wet Electrostatic Precipitator 

NA 

4 Centrifugal Separation 

(e.g. Cyclones) 

NA 

5. Step 5 – Select BACT 

Fabric filters are selected as BACT for control of particulate emissions from crushing. Fabric filters 

were selected because they are the top control technology in this application. 

The only non-air environmental impact of this technology is the generation of solid waste. Wet 

scrubbing or Wet ESP’s would also generate waste water. 

The use fabric filters has minimal energy use impacts. The only particulate matter control device 

with significant energy impacts, in this circumstance, is wet scrubbing. 

The proposed BACT limit for fine crushing is a performance limit of 0.003 gr PM/dscf on a 24 

hour average basis. To establish compliance limits, NSM will test for filterable + organic 

condensable PM using EPA Method 5 and MN 7011.0725 using three (3) one-hour test runs. 

During the performance test, the facility will measure emission control equipment process 

parameters. Process parameter limits for operating fine crushing emission control equipment 

will be set using the data collected during the performance test. The facility will demonstrate 

ongoing compliance based on the 24 hour average(s) of the process parameters established 

during the performance test. 

Fine crushing is equipped with a fixed speed fans for moving exhaust gas through the control 

equipment. Since fine crushing has a constant exhaust flow rate, setting a PM concentration 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-52 

limit for BACT also limits the maximum mass emission rate from this source. So, additional 

emission limits are not needed. 

The proposed BACT limit is consistent with recent RBLC determinations for sources in the 

mineral processing industries (metallic and non-metallic). The RBLC database shows BACT 

determinations for mineral processing sources in the 0.003 – 0.01 gr/dscf range. Since these 

determinations are for several different types of processing equipment, they are indicative of the 

level of emission control that is possible in the industries covered by this source category. 

However, differences in conditions at individual sources affect the level of emission controls 

possible at a particular source. 

The proposed BACT limits are more stringent than the new source MACT limit (40 CFR 63 

Subpart RRRRR) of 0.005 gr/dscf filterable particulate for ore handling equipment at taconite 

facilities. The new source MACT standard represents the highest level of emission controls 

which can be expected for these sources; not the average of the top 12% of existing sources. The 

evaluation criteria for new source MACT is similar to the criteria for BACT determinations. The 

taconite MACT standard was promulgated October 30, 2003, so the analysis is current; 

consistent with the requirements of BACT. 

The proposed BACT limit is based on the highest level of emission control that can be achieved 

with fabric filters in this application. The proposed BACT limits are based on a particulate 

matter concentration of 0.003 gr/dscf after controls. Performance test data from NSM fine 

crushing sources equipped with fabric filters show particulate concentrations of 0.0010 gr/dscf to 

0.0031 gr/dscf. 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-53 

V. Concentrator Silos 

The Concentrator Silos receive the upgraded crude ore the dry cobbing process and stores the 

upgraded ore for direct transfer to the rod mills, which are a wet process. Crushed ore entering the 

concentration process is dry. Particulate matter is emitted as the dry ore is transferred into the 

process. The ore transfer point will be equipped with a fabric filter to control particulate emissions. 

In the remaining balance of the concentration processing steps, the ore is wet, and there are no 

particulate matter emissions from these operations. 

Ore concentration equipment associated with the Furnace 5 Restart project is currently equipped with 

multiclones. NSM proposes to install baghouses for improved PM emissions control on these 

sources as part of the project 

A. Particulate Matter (PM / PM10 ) Emission Controls 

1. Step 1 – Identify all Control Technologies 

EPA’s RACT, BACT, LAER Clearinghouse (RBLC) database was checked for recent BACT 

determinations in the mineral and metallic processing industries. The results of this evaluation are in 

BACT Attachment 1, Tables 1 and 2. While most of the BACT determinations were for sources that 

are not directly applicable to this project, the control technologies evaluated in this study are 

consistent with those found in the RBLC. The proposed BACT limits are consistent with the level of 

emission control found in RBLC for similar industries, after taking process limitations and NSM’s 

site specific conditions into account. 

The following control technologies were evaluated for PM emissions control from ore concentration 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-54 

Table V A-1 

PM / PM10 Emission Control Technologies Considered for BACT Analysis 

Technology Description 

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. 

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. 

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. 

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. 

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. 

2. Step 2 – Eliminate Technically Infeasible Options 

All of the particulate matter control technologies examined for concentration are technically feasible. 

The technical feasibility is summarized as follows. 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-55 

Table V A-2 

PM / PM10 Emission Control Technology Feasibility Analysis

Technology Description Feasible? 

Yes or No 

Typical 

% Efficiency

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 98% - 99+% 

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 

95%-99+% 

(high 

efficiency 

scrubbers) 

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 98% - 99+% 

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 98% - 99+% 

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 50% - 80% 

All listed control technologies are technically feasible for particulate emission control for ore 

concentration. 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-56 

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

Fabric filters are the most effective control technology in this application. The control technology 

rankings are as follows: 

Table V A-3 

PM / PM10 Control Technology Ranking 

Rank Technology Typical 

% Efficiency 

1 

Fabric Filter 

(Baghouse) 

98% - 99+% 

2 Wet Scrubber 95% - 99+% 

3 Wet Electrostatic 

Precipitator 98% - 99+% 

4 Centrifugal Separation 

(e.g. Cyclones) 

50% - 80% 

The exhaust streams from this source contain only dry particulate matter. Under these conditions, 

fabric filters have the highest particulate matter control efficiency. 

4. Step 4 – Evaluate Most Effective Control Technologies and Document 

Results 

Northshore Mining Co. has elected to install fabric filters on the concentrator silo exhaust streams. 

Fabric filters have the highest particulate matter control efficiency in this application. Since the top 

control option was chosen, additional analysis is not required. 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-57 

Table V A-4 

PM / PM10 Control Technology Emission Control Cost Analysis 

Rank Technology Control Cost $/ton 

1 

Fabric Filter 

(Baghouse) Top Emission Controls Selected 

2 Wet Scrubber 

NA 

3 Wet Electrostatic Precipitator 

NA 

4 Centrifugal Separation 

(e.g. Cyclones) 

NA 

5. Step 5 – Select BACT 

The proposed BACT limit for the concentrator silos is a performance limit of 0.003 gr PM/dscf 

on a 24 hour average basis. To establish compliance limits, NSM will test for filterable + 

organic condensable PM using EPA Method 5 and MN 7011.0725 using three (3) one-hour test 

runs. During the performance test, the facility will measure emission control equipment process 

parameters. Process parameter limits for operating the concentrator silo emission control 

equipment will be set using the data collected during the performance test. The facility will 

demonstrate ongoing compliance based on the 24 hour average(s) of the process parameters 

established during the performance test. 

The concentrator silos are equipped with a fixed speed fans for moving exhaust gas through the 

control equipment. Since each concentrator has a constant exhaust flow rate, setting a PM 

concentration limit for BACT also limits the maximum mass emission rate from this source. So, 

additional emission limits are not needed. 

The proposed BACT limit is consistent with recent RBLC determinations for sources in the 

mineral processing industries (metallic and non-metallic). The RBLC database shows BACT 

determinations for mineral processing sources in the 0.003 – 0.01 gr/dscf range. Since these 

determinations are for several different types of processing equipment, they are indicative of the 

level of emission control that is possible in the industries covered by this source category. 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-58 

However, differences in conditions at individual sources affect the level of emission controls 

possible at a particular source. 

The proposed BACT limits are more stringent than the new source MACT limit (40 CFR 63 

Subpart RRRRR) of 0.005 gr/dscf filterable particulate for ore handling equipment at taconite 

facilities. The new source MACT standard represents the highest level of emission controls 

which can be expected for these sources; not the average of the top 12% of existing sources. The 

evaluation criteria for new source MACT is similar to the criteria for BACT determinations. The 

taconite MACT standard was promulgated October 30, 2003, so the analysis is current; 

consistent with the requirements of BACT. 

The proposed BACT limit is based on the highest level of emission control that can be achieved 

with fabric filters in this application. The proposed BACT limits are based on a particulate 

matter concentration of 0.003 gr/dscf after controls. Performance test data from NSM fine 

crushing sources equipped with fabric filters show particulate concentrations of 0.0010 gr/dscf to 

0.0031 gr/dscf. 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-59 

VI. Indurating Furnace Pellet Discharge 

This emission source is the material handling and screening point for finished taconite pellets as they 

leave the taconite furnace. When the finished taconite pellets leave the induration furnace, 

particulate matter is emitted from the transfer to the screens and the screening process. Water is 

added at the pellet discharge to cool the pellets to levels acceptable for subsequent pellet handling 

equipment, and to control dust from pellet screening. The exhaust stream is saturated with water. 

The furnace discharge pellet transfer point is currently equipped with a rotoclone for particulate 

control. NSM is proposing to install a wet scrubber as BACT for control of particulate emissions 

from this source as part of the Furnace 5 Restart Project. 

A. Particulate Matter (PM / PM10 ) Emission Controls 

1. Step 1 – Identify all Control Technologies 

EPA’s RACT, BACT, LAER Clearinghouse (RBLC) database was checked for recent BACT 

determinations in the mineral and metallic processing industries. The results of this evaluation are in 

BACT Attachment 1, Tables 1 and 2. While most of the BACT determinations were for sources that 

are not directly applicable to this project, the control technologies evaluated in this study are 

consistent with those found in the RBLC. The proposed BACT limits are consistent with the level of 

emission control found in RBLC for similar industries, after taking process limitations and NSM’s 

site specific conditions into account. The control technologies evaluated for PM emissions control 

from Furnace #5 pellet discharge are as follows. 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-60 

Table VII A-1 

PM / PM10 Emission Control Technologies Considered for BACT Analysis

Technology Description 

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. 

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. 

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. 

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. 

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. 

2. Step 2 – Eliminate Technically Infeasible Options 

Two of the particulate matter control technologies for the pellet discharge exhaust are technically 

infeasible. The technical feasibility is summarized as follows: 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-61 

Table VII A-2 

PM / PM10 Emission Control Technology Feasibility Analysis

Technology Description Feasible? 

Yes or No 

Typical 

% Efficiency

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 98% - 99+% 

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 

95%-99+% 

(high 

efficiency 

scrubbers) 

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 98% - 99+% 

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 98% - 99+% 

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 50% - 80% 

As noted in the process description, the exhaust from this source is saturated with water due to the 

water sprays used for cooling and dust control. Due to the high moisture content of this stream, 

fabric filters and dry ESP’s are infeasible. Wet particulate matter would clog the particulate matter 
 

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(BACT).doc A-5-62 

collection and removal systems in each of these technologies. The remaining control technologies 

are technically feasible for particulate emission control of the pellet discharge exhaust. 

3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

This study assumes that the top 3 technically feasible technologies can meet the Taconite MACT 

particulate standards. Control cost estimates are based on meeting the MACT standard; the control 

device was sized to meet this standard. 

Table VII A-3 

 PM / PM10 Control Technology Ranking

Rank Technology Typical 

% Efficiency 

1 

Wet Electrostatic 

Precipitator 

98% - 99+% 

2 Wet Scrubber 95% - 99+% 

3 Dry Electrostatic 

Precipitator 

98% - 99+% 

4 Centrifugal Separation 

(e.g. Cyclones) 

50% - 80% 

4. Step 4 – Evaluate Most Effective Control Technologies and Document 

Results 

Emissions control effectiveness was evaluated for the top two control technologies, wet scrubbing, 

baghouses, ESP’s and Wet ESP controls. The control equipment effectiveness analysis can be 

summarized as follows: 

Table VII A-4 

PM / PM10 Control Technology Emission Control Cost Analysis 

Rank Technology Control Cost $/ton 

1 Wet Scrubber $3,390 

2 Wet Electrostatic Precipitator $19,792 
 

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(BACT).doc A-5-63 

A summary of the control cost analysis is located in BACT Attachment 2, Table 9. The control cost 

analyses for individual controls are located in BACT Attachment 2 Tables 10 and 11. 

Wet Scrubbing 

The particulate matter control cost for a wet scrubber is $3,390/ton. This cost makes it economically 

feasible. NSM has the infrastructure to handle the liquid waste from the wet scrubber. So, it may be 

advantageous for the facility to use a wet scrubber instead of a baghouse. See Attachment B for the 

control cost analysis. 

The non-air environmental impact of a wet scrubber is the need to treat the wastewater discharged 

from the scrubber. 

A wet scrubber has the highest energy use rate of the control technologies studied. A high efficiency 

wet scrubber operates with a high pressure drop in order to achieve high collection efficiency. This 

results in a higher electricity use rate than the other controls to operate the air blower. 

Wet Walled Electrostatic Precipitator 

Application of a wet ESP’s is economically infeasible. The particulate matter control cost for a new 

precipitator is $19,792/ton. 

The non-air environmental impact of a wet ESP is the need to treat the wastewater discharged from 

the wet ESP. 

A wet ESP has a moderate energy use rate. ESP’s have a low pressure drop, so, a modest electricity 

use rate is needed to operate the air blower. Operation of the electric grids in the EPS does not add 

significantly to the overall electrical consumption. 

5. Step 5 – Select BACT 

A wet scrubber is selected as BACT for control of particulate emissions from Furnace #5 pellet 

discharge. The other control technologies are economically infeasible. 

The proposed BACT limit for the Furnace 5 pellet discharge is a performance limit of 0.005 gr 

PM/dscf on a 24 hour average basis. To establish compliance limits, NSM will test for filterable 

+ organic condensable PM using EPA Method 5 and MN 7011.0725 using three (3) one-hour 

test runs. During the performance test, the facility will measure emission control equipment 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-64 

process parameters. Process parameter limits for operating the Furnace 5 pellet discharge 

emission control equipment will be set using the data collected during the performance test. The 

facility will demonstrate ongoing compliance based on the 24 hour average(s) of the process 

parameters established during the performance test. 

The Furnace 5 pellet discharge is equipped with a fixed speed fans for moving exhaust gas 

through the control equipment. Since the pellet discharge has a constant exhaust flow rate, 

setting a PM concentration limit for BACT also limits the maximum mass emission rate from 

this source. So, additional emission limits are not needed. 

The proposed BACT limit is consistent with recent RBLC determinations for sources in the 

mineral processing industries (metallic and non-metallic). The RBLC database shows BACT 

determinations for mineral processing sources in the 0.003 – 0.01 gr/dscf range. Since these 

determinations are for several different types of processing equipment, they are indicative of the 

level of emission control that is possible in the industries covered by this source category. 

However, differences in conditions at individual sources affect the level of emission controls 

possible at a particular source. 

The proposed BACT limits are equal to the 0.005 gr/dscf new source MACT limit (40 CFR 63 

Subpart RRRRR) for finished pellet handling equipment at taconite facilities. NSM is planning 

to install new control equipment for the pellet discharge to meet Taconite MACT. Although this 

source is subject to the existing source MACT, NSM is proposing to meet the new source 

standard since new control equipment is being installed. The new source MACT standard is 

more stringent that the existing source standard and represents the highest level of emission 

controls which can be expected for new sources. The evaluation criteria for new source MACT 

is similar to the criteria for BACT determinations. The taconite MACT standard was 

promulgated October 30, 2003, so the analysis is current; consistent with the requirements of 

BACT. 
 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A 

(BACT).doc A-5-65 

BACT ATTACHMENT 1 

RBLC BACT Data 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 1 RBLC Search Metallic Mineral Processing 

RBLC ID # Facility Name 

Permit Number 

Permit Date 

Process Name Pollutant Control Equipment 

Description 

EmissionLimit U

MO-0011 

PEA RIDGE IRON ORE CO. 

0895-012 8/9/1995 

ADDITION OF DIRECT REDUCTION FURNACE&COALHANDLING 

SO2 

USES A #6 RESIDUAL FUEL OIL SPRAY DRYER\ FABRIC FILTER 

104 L

MO-0011 

PEA RIDGE IRON ORE CO. 

0895-012 8/9/1995 

ADDITION OF DIRECT REDUCTION FURNACE&COALHANDLING 

NO2 #6 RESIDUAL FUEL OIL, 

SNCR 

52 L

MO-0011 

PEA RIDGE IRON ORE CO. 

0895-012 8/9/1995 

ADDITION OF DIRECT REDUCTION FURNACE&COALHANDLING 

PM10 

USES A #6 RESIDUAL FUEL OIL. SPRAY DRYER \ FABRIC FILTER 

0.01 G

AK-0033 

COMINCO RED DOG MINE 

9932-AC005 

12/10/1999 

ROCK CRUSHER, READ SCREENALL, PORTABLE PM10 

MEET REQUIREMENTS OF 40 CFR 60.673(B), (C), & (E). 

0.05 G

AK-0033 

COMINCO RED DOG MINE 

9932-AC005 

12/10/1999 CRUSHER, 

GYRATORY 

PM10 BAGHOUSE 0.01 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 1 RBLC Search Metallic Mineral Processing 

RBLC ID # Facility Name 

Permit Number 

Permit Date 

Process Name Pollutant Control Equipment 

Description 

EmissionLimit U

AK-0033 

COMINCO RED DOG MINE 

9932-AC005 

12/10/1999 

METALLIC MINERAL PROCESSING EQUIPMENT,VARIOUS 

PM10 

MEETS REQUIREMENTS OF 40 CFR 60.382(A) & (B). BAGHOUSE, WATERING AND CHEMICAL CONTROLS. 

0.05 G

AK-0033 

COMINCO RED DOG MINE 

9932-AC005 

12/10/1999 

METALLIC MINERAL PROCESSING EQUIPMENT,VARIOUS 

VE 

MEET REQUIREMENTS OF 40 CFR 60.382 (A) AND (B). BAGHOUSE 

7 % 

AK-0033 

COMINCO RED DOG MINE 

9932-AC005 

12/10/1999 HEATERS, ABCO, 

3 UNITS 

NOX LOW NOX BURNERS 0.084 L

AK-0033 

COMINCO RED DOG MINE 

9932-AC005 

12/10/1999 HEATERS, ABCO, 

3 UNITS 

VE LOW NOX BURNERS 20 % 

MN-0036 

ISPAT INLAND MINING CO. 

13700062-001 

1/14/2000 

METAL ORE MINING, TACONITE, INDURATING FURNACE 

NO2 

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 L
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 1 RBLC Search Metallic Mineral Processing 

RBLC ID # Facility Name 

Permit Number 

Permit Date 

Process Name Pollutant Control Equipment 

Description 

EmissionLimit U

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

MIKROPUL 55W825 BAGHOUSE, #31 

VE 

BAGHOUSE IS THE CONTROL DEVICE 

20 % 

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

MIKROPUL 55W825 BAGHOUSE, #31 

PM 

BAGHOUSE IS THE CONTROL DEVICE 

0.01 G

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

MIKROPUL 55W825 BAGHOUSE, #31 

PB 

BAGHOUSE IS THE CONTROL DEVICE 

0.0006 G

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

EMTROL 66W40 #1 SCRUBBER 

VE 

BAGHOUSE IS THE CONTROL DEVICE 

20 % 

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

EMTROL 66W40 #1 SCRUBBER 

PM 

BAGHOUSE IS THE CONTROL DEVICE 

0.01 G

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

EMTROL 66W40 #1 SCRUBBER 

PB 

BAGHOUSE IS THE CONTROL DEVICE 

0.0006 G

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

EMTROL 66W40 #2 SCRUBBER 

VE 

SCRUBBER IS CONTROL DEVICE 

20 % 

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

EMTROL 66W40 #2 SCRUBBER 

PM 

SCRUBBER IS THE CONTROL DEVICE 

0.01 G

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

EMTROL 66W40 #2 SCRUBBER 

PB 

SCRUBBER IS THE CONTROL DEVICE 

0.0006 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 1 RBLC Search Metallic Mineral Processing 

RBLC ID # Facility Name 

Permit Number 

Permit Date 

Process Name Pollutant Control Equipment 

Description 

EmissionLimit U

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

MIKROPUL 49S8-20 BAGHOUSE, #34 

VE 

BAGHOUSE IS A CONTROL DEVICE 

20 % 

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

MIKROPUL 49S8-20 BAGHOUSE, #34 

PM 

BAGHOUSE IS A CONTROL DEVICE 

0.01 G

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

MIKROPUL 49S8-20 BAGHOUSE, #34 

PB 

BAGHOUSE IS A CONTROL DEVICE 

0.0006 G

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

MIKROPUL 48N4-B BAGHOUSE 

VE 

THE BAGHOUSE IS A CONTROL DEVICE 

20 % 

*AK-0040 

RED DOG MINE 

9332-AA003 

7/27/1994 

MIKROPUL 48N4-B BAGHOUSE 

PM 

THE BAGHOUSE IS A CONTROL DEVICE 

0.01 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UOR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 1/CALCINER 1 PM 

BAUMCO MODEL 2-5116-4.510P PULSE-JET BAGHOUSE, AIR TO CLOTH RATIO IS 1.7:1 

0.1 G

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 1/CALCINER 1 SO2 

OXIDIZED, LOW SULFUR ORES CAN BE OBTAINED BY SELECTIVE MINING OF THE UPPER STRATA OF THE DEPOSITS. SULFUR IS PRESENT IN RAW DE ORES AT VARYING LEVELS DEPENDING ON THE PARTICULAR GEOLOGIC FORMATION. 

60 % R

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 1/CALCINER 1 NOX GOOD COMBUSTION CONTROL 6.6 L

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 1/CALCINER 1 CO GOOD COMBUSTION CONTROL 19.7 L

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 1/CALCINER 1 VE 

BAUMCO MODEL 2-5116-4.510P PULSE-JET BAGHOUSE, AIR TO CLOTH RATIO IS 1.7:1 

20 % 

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 2/CALCINER 2 PM 

FABRIC FILTER MODEL 289-10 PULSE-JET BAGHOUSE WITH AIR TO CLOTH RATIO OF 2.0:1 

0.1 G

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 2/CALCINER 2 PM FILTERABL E BAGHOUSE 0.04 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UOR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 2/CALCINER 2 SO2 

OXIDIZED, LOW SULFUR ORES CAN BE OBTAINED BY SELECTIVE MINING THE UPPER STRATA OF THE DEPOSITS. SULFUR IS PRESENT IN RAW DE ORES AT VARYING LEVELS DEPENDING ON THE PARTICULAR GEOLOGIC FORMATION PROCESS 

60 %

R

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 2/CALCINER 2 NOX GOOD COMBUSTION PRACTICES 7.1 L

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 2/CALCINER 2 CO GOOD COMBUSTION PRACTICES 21.4 L

OR-0042 

EAGLEPICHER VALE, OREGON PLANT 

23-0007 5/23/2003 DRYER 2/CALCINER 2 VE 

FABRIC FILTER MODEL 289-10 PULSE-JET BAGHOUSE WITH AIR TO CLOTH RATIO OF 2:1 

10 % 

IL-0084 VULCAN MATERIALS 96020014 10/28/2002 LIME KILN SO2 BAGHOUSE AND SCRUBBER 2.76 LIL-0084 VULCAN MATERIALS 96020014 10/28/2002 LIME KILN NOX BEST COMBUSTION PRACTICES 4.5 LIL-0084 VULCAN MATERIALS 96020014 10/28/2002 LIME KILN PM BAGHOUSE 0.134 LIL-0084 VULCAN MATERIALS 96020014 10/28/2002 LIME KILN CO BEST COMBUSTION PRACTICE 43.2 LNC-0099 PCS PHOSPHATE 04176R15 7/14/2000 SULFURIC ACID PLANT, NO. 3 SO2 

FIBERGLASS PACKED MIST ELIMINATORS AND A MESH PAD INSTALLED ON THE FINAL ABSORBING TOWER 

4 L
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UNC-0099 PCS PHOSPHATE 04176R15 7/14/2000 SULFURIC ACID PLANT, NO. 3 H2SO4 MIST 

FIBERGLASS PACKED MIST ELIMINATORS AND A MESH PAD INSTALLED ON THE FINAL ABSORBING TOWER 

0.15 L

WY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 MINE VENT (E1) CO 0.26 LWY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 MINE VENT (E1) NMHC 130 LWY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 MINE VENT (E1) NOX 1.7 LWY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 ROM ORE HANDLING DUST COLLECTOR (E2) PM10 ELECTROSTATIC PRECIPITATOR. ADDITIONAL ALT.EMISSION 8.2 T/YR. 0.005 GWY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 ROM ORE STORAGE DUST COLLECTOR (E3) NOX LOW NOX BURNER 8.1 L

(P

WY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 ROM ORE STORAGE DUST COLLECTOR (E3) PM10 ELECTROSTATIC PRECIPITATOR. ADDITIONAL ALT. EMISSION 9.2 T/YR 0.005 GWY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 

BENETRON ORE UPGRADE FACILITY STACK (E4) 

PM10 ELECTROSTATIC PRECIPITATOR. 0.0025 G

WY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 

BENETRON ORE UPGRADE FACILITY STACK (E4) 

NOX LOW NOX BURNER 8.1 L

(P

WY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 TRONA ORE CALCINER STACK (E5) (E15) NOX LOW NOX BURNER. ALT. EMISSION LIMIT: PHASE 2 - 16.1 LB/H. 0.038 LWY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 TRONA ORE CALCINER STACK (E5) (E15) PM10 WET SCRUBBER. 0.003 GWY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 

SODA ASH PRODUCT HANDLING DUST COLLECTOR (E6) 

PM10 ELESTROSTATIC PRECIPITATOR. 0.005 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UWY-0055 WOLD TRONA COMPANY, INC. MD-455 4/27/2000 ROM ORE STORAGE DUST COLLECTOR PM10 ESP 2.1 LVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 SPRAY DRYER #2 PM10 CYCLONE PRECOLLECTORS & ESP 0.07 LVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 DEAGGLOMERAT OR C PM10 CYCLONE, FABRIC FILTER 0.01 GVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 CONVEYING SYSTEM, PRODUCT SILO PM10 FABRIC FILTER 0.01 GVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 FLASH DRYER SYSTEM #1, #2 AND #3 PM10 FABRIC FILTERS 0.01 GVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 FLASH DRYER SYSTEM #1, #2 AND #3 SO2 LIMIT ON DISTILLATE FUEL SULFUR CONTENT: < .3% S BY WT 0.7 LVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 

CONVEYING SYSTEM, FLASH DRYER PROD 1, 2 & 3 

PM10 FABRIC FILTER 0.01 G

VT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 SURFACE TREATER, A & C PM10 FABRIC FILTER 0.01 GVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 

CONVEYING SYSTEM, SURFACE TREATER A, B & C PROD 

PM10 FABRIC FILTER 0.01 G

VT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 SURFACE TREATER B PM10 FABRIC FILTER 0.01 GVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 

PRODUCT CONVEYING SYSTEM, DEAGGLOMERATOR C 

PM10 FABRIC FILTER 0.01 G

VT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 TRANSFER HOPPER, BULK BAGGING PM10 FABRIC FILTER 0.01 GVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 BULK BAGGER STATIONS/SILOS PM10 FABRIC FILTER 0.01 GVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 HOUSE VACUUM SYSTEM PM10 FABRIC FILTER 0.01 GVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 ROTOPACKERS PM10 FABRIC FILTERS 0.01 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UVT-0016 OMYA / VERPOL AOP-98- 015A 10/26/1999 BOILER, FIRE TUBE PM10 LOW SULFUR FUEL, GOOD OPERATING PRACTICE. 0.35 LAR-0028 

ARKANSAS LIME COMPANY 

45-AOP-R1 9/14/1999 KILN, LIME SO2 

RESTRICTION ON THE SULFUR CONTENT OF THE FUEL USED TO FIRE THE LIME KILN (MAX 4% ON A DAILY BASIS AND 3% ON A ROLLING 30 DAY AVERAGE). 

65.2 L

AR-0028 

ARKANSAS LIME COMPANY 

45-AOP-R1 9/14/1999 KILN, LIME NOX PROPER DESIGN AND OPERATION OF LIME KILN 91.2 L

CO-0040 

AMERICAN SODA, LLP, PARACHUTE FACILITY 

98-GA0858 5/6/1999 INDUSTRIAL BOILER, NATURAL GAS NOX 

LOW NOX COMBUSTION SYSTEM. CAPITAL COSTS ARE INCLUDED IN EQUIPMENT COSTS; ANNUALIZED COSTS ARE INCLUDED IN OPERATION AND MAINTENANCE 

0.05 L

CO-0040 

AMERICAN SODA, LLP, PARACHUTE FACILITY 

98-GA0858 5/6/1999 INDUSTRIAL BOILER, NATURAL GAS CO 

GOOD COMBUSTION MANAGEMENT. CAPITAL AND ANNUALIZED COSTS ARE INCLUDED IN OPERATION AND MAINTENANCE 

0.09 L

CO-0040 

AMERICAN SODA, LLP, PARACHUTE FACILITY 

98-GA0858 5/6/1999 

SODIUM CARBONATE PROD., SODA ASH DRYER, NAT GAS 

PM10 

ELECTROSTATIC PRECIPITATOR (ESP) AND GOOD COMBUSTION PRACTICES. 

0.01 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UCO-0040 

AMERICAN SODA, LLP, PARACHUTE FACILITY 

98-GA0858 5/6/1999 

SODIUM CARBONATE PROD., SODA ASH DRYER, NAT GAS 

CO 

GOOD COMBUSTION MANAGEMENT. CONTAMINATION OF THE PRODUCT IS OF PRIMARY CONCERN. REFRACTORIES CANNOT BE USED IN THE COMBUSTION SYSTEM. CAPITAL AND ANNUALIZED COSTS ARE INCLUDED IN OPERATION AND MAINTENANCE 

2.02 L

CO-0040 

AMERICAN SODA, LLP, PARACHUTE FACILITY 

98-GA0858 5/6/1999 

SODIUM CARBONATE PROD., SODA ASH DRYER, NAT GAS 

NOX 

GOOD COMBUSTION MANAGEMENT. CONTAMINATION OF THE PRODUCT IS OF PRIMARY CONCERN. REFRACTORIES CANNOT BE USED IN THE COMBUSTION SYSTEM. CAPITAL AND ANNUALIZED COSTS ARE INCLUDED IN OPERATION AND MAINTENANCE 

0.15 L

CO-0041 

AMERICAN SODA, LLP, PINEANCE FACILITY 

98-RB-0831 5/6/1999 

BOILER NO.2, TEST MINE HOT WATER (1) 

NOX 

LOW NOX COMBUSTION SYSTEM. NO ADD-ON COSTS. COSTS PART OF OPERATION. 

0.05 L

CO-0041 

AMERICAN SODA, LLP, PINEANCE FACILITY 

98-RB-0831 5/6/1999 

BOILER NO.2, TEST MINE HOT WATER (1) 

CO GOOD COMBUSTION 0.09 L

CO-0041 

AMERICAN SODA, LLP, PINEANCE FACILITY 

98-RB-0831 5/6/1999 

BOILER NO.2, TEST MINE HOT WATER (1) 

PM10 COMBUSTION CONTROL 0.009 L
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UCO-0041 

AMERICAN SODA, LLP, PINEANCE FACILITY 

98-RB-0831 5/6/1999 

BOILER NO.1, MAIN HOT WATER, (2) 

PM10 

USE OF PIPELINE QUALITY NATURAL GAS, AND APPLICATION OF GOOD COMBUSTION MANAGEMENT PRACTICES 

0.0075 L

CO-0041 

AMERICAN SODA, LLP, PINEANCE FACILITY 

98-RB-0831 5/6/1999 

BOILER NO.1, MAIN HOT WATER, (2) 

VOC GOOD COMBUSTION 0.0054 L

CO-0041 

AMERICAN SODA, LLP, PINEANCE FACILITY 

98-RB-0831 5/6/1999 

BOILER NO.1, MAIN HOT WATER, (2) 

NOX 

LOW NOX COMBUSTION SYSTEMS TO MINIMIZE FORMATION AND EMISSIONS OF OXIDES OF NITROGEN 

0.038 L

CO-0041 

AMERICAN SODA, LLP, PINEANCE FACILITY 

98-RB-0831 5/6/1999 

BOILER NO.1, MAIN HOT WATER, (2) 

CO 

GOOD COMBUSTION MANAGEMENT PRACTICES TO MINIMIZE FORMATION AND EMISSION OF CARBON MONOXIDE 

0.09 L

CA-0851 

CELITE CORPORATION (LOMPOC PLANT) 

10023 1/21/1999 

BAGHOUSE, GENERAL WASTE MATERIAL 

PM10 

GENERAL WASTE BAGHOUSE. MFGR/MODEL: MIKOPUL/611R-10-30-TRC"" 

0.0045 G

CA-0851 

CELITE CORPORATION (LOMPOC PLANT) 

10023 1/21/1999 

BAGHOUSE, GENERAL WASTE MATERIAL 

VE 

GENERAL WASTE BAGHOUSE. MFGR/MODEL IS MIKOPUL/ 611R-10-30-TRC"" 

10 % 

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

CALCINER, NATURAL GAS FIRED TRONA 

PM ELECTROSTATIC PRECIPITATOR 264,000ACFM 0.015 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UWY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

CALCINER, NATURAL GAS FIRED TRONA 

NOX BURNER DESIGNED FOR LOW NOX" PERFORMANCE" 0.05 L

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

CALCINER, NATURAL GAS FIRED TRONA 

VOC 533.5 L

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

SODA ASH NATURAL GAS, DRYER 

NOX 

BURNER DESIGNED FOR LOW NOX" PERFORMANCE "NORTH AMERICAN FLAME GRID" UNIT" 

0.15 L

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

SODA ASH NATURAL GAS, DRYER 

PM ELECTROSTATIC PRECIPITATOR 130,000 ACFM 0.01 G

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 BOILER, NATURAL GAS PM MINIMAL PARTICULATE EMISSIONS AND LOW EMITTING FUEL 5 L

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 BOILER, NATURAL GAS NOX LOW NOX" BURNER SYSTEM" 0.038 L

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

PRIMARY SCREENS, TRONA ORE 

PM BAGHOUSE AND INDUSTRIAL VENTILATION SYSTEM 0.01 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UWY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

PRIMARY SCREENS, TRONA ORE 

VE 7 % 

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

CONVEYOR DISCHARGE, RECLAIM TRONA ORE 

PM BAGHOUSE AND INDUSTIRAL VENTILATION SYSTEM 0.01 G

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

CONVEYOR DISCHARGE, RECLAIM TRONA ORE 

VE 7 % 

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

PRODUCT HANDLING AREA, SODA ASH DRYER PRODUCT 

PM BAGHOUSE & INDUSTRIAL VENTILATION SYSTEM 0.01 G

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

PRODUCT HANDLING AREA, SODA ASH DRYER PRODUCT 

VE 7 % 

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

DIN VENTS & PRODUCT TRANSFER POINTS, (2) SODA ASH 

PM BAGHOUSE AND INDUSTRIAL VENTILATION SYSTEM 0.01 G

WY-0034 

SOLVAY SODA ASH JOINT VENTURE TRONA MINE/SODA ASH 

CT-1347 2/6/1998 

DIN VENTS & PRODUCT TRANSFER POINTS, (2) SODA ASH 

VE 7 % 
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UCA-0808 CELITE CORPORATION 9757 12/5/1997 DIATOMACEOUS EARTH CALCINER SOX 

GAS ABSORPTION TOWER (AKA. SCRUBBER). PACKEDBED COUNTER-CURRENT DESIGN USING CAUSTIC AS THE SOLVENT. 

98 % 

R

WY-0031 

GENERAL CHEM SODA ASH PARTNERS - GEN CHEM SODA 

MD-340 11/21/1997 CALCINER, TRONA, 5 EACH VOC 0 

WY-0031 

GENERAL CHEM SODA ASH PARTNERS - GEN CHEM SODA 

MD-340 11/21/1997 CALCINER, TRONA, 2 EACH VOC 0 

WY-0031 

GENERAL CHEM SODA ASH PARTNERS - GEN CHEM SODA 

MD-340 11/21/1997 DRYER, TRONA, 6 EACH VOC 0 

WY-0031 

GENERAL CHEM SODA ASH PARTNERS - GEN CHEM SODA 

MD-340 11/21/1997 DRYER, TRONA, 6 EACH VOC 0 

WY-0035 

TEXASGULF SODA ASH PLANT 

CT-1321 10/13/1997 ROTARY DRYER, SODA ASH PM ELECTROSTATIC PRECIPITATOR 124,000 ACFM 0.01 G

WY-0035 

TEXASGULF SODA ASH PLANT 

CT-1321 10/13/1997 ROTARY DRYER, SODA ASH VE 0.07 O

WY-0035 

TEXASGULF SODA ASH PLANT 

CT-1321 10/13/1997 ROTARY DRYER, SODA ASH NOX LOW NOX BURNERS - NORTH AMERICAN BURNER 0.15 L

WY-0035 

TEXASGULF SODA ASH PLANT 

CT-1321 10/13/1997 

SCREENING/SIZING AREA, SODA ASH 

PM 

VENTURI SCRUBBER AND INDUSTRIAL VENTILATION SYSTEM 

0.01 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UWY-0035 

TEXASGULF SODA ASH PLANT 

CT-1321 10/13/1997 BOILER, NATURAL GAS NOX LOW NOX" BURNERS WITH 16% FLUE GAS RECIRCULATION" 0.05 L

WY-0035 

TEXASGULF SODA ASH PLANT 

CT-1321 10/13/1997 BOILER, NATURAL GAS PM NATURAL GAS FUEL 0 N

WY-0035 

TEXASGULF SODA ASH PLANT 

CT-1321 10/13/1997 BOILER, NATURAL GAS SO2 NATURAL GAS FUEL 0 N

GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 CALCINER NO. 4 VE ESP, BAGHOUSE. 10 % GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 CALCINER NO. 4 PM ESP 0.04 GGA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 CALCINER NO. 4 SOX SULFUR CONTENT OF FUEL OIL LIMITED TO 0.5 WT % 40 T

CM

GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 CALCINER NO. 4 NOX LIMITED FUEL CONSUMPTION 40 T

CM

GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 CALCINER COOLER OPACITY BAGHOUSE. 7 % GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 CALCINER COOLER PM BAGHOUSE 0.03 GGA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 SILOS (5) VE BAGHOUSE. 7 %GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 SILOS (5) PM BAGHOUSE 0.03 GGA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 PULVERIZERS (8) VE BAGHOUSE 7 % GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 PULVERIZERS (8) PM BAGHOUSE 0.03 GGA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 TRUCK LOADING VE BAGHOUSE 7 % GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 TRUCK LOADING PM BAGHOUSE 0.03 GGA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 RAILCAR LOADING VE BAGHOUSE 7 % GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 RAILCAR LOADING PM BAGHOUSE 0.03 G
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UGA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 BIN VENTS (3) VE BAGHOUSE. 7 % GA-0074 DRY BRANCH KAOLIN CO. 3295-143- 11081 11/6/1995 BIN VENTS (3) PM BAGHOUSE 0.03 GCA-0670 U.S. BORAX A/C NO. 1004207A 9/28/1995 

BORATE TAILINGS PONDS (FUGITIVE DUST CONTROL) 

PM10 

APPLICATION OF DLR-MS-40 ACRYLIC COPOLYMER AND RECLAMATION OF DRY PONDS 

68.49 L

CA-0672 U.S. BORAX, INC. 1004207A 9/28/1995 BORATES TAILING PONDS PM10 APPLICATION OF DUST RETARDANT 68.5699 LWY-0038 WOLD TRONA CO. CT-1148 5/2/1995 MATERIAL HANDLING, ORE PM ELECTROSTATIC PRECIPITATOR 0.005 GWY-0038 WOLD TRONA CO. CT-1148 5/2/1995 MATERIAL HANDLING, ORE VE 7 % WY-0038 WOLD TRONA CO. CT-1148 5/2/1995 MATERIAL STORAGE, ORE, (2) PM ELECTROSTATIC PRECIPITATOR 0.005 GWY-0038 WOLD TRONA CO. CT-1148 5/2/1995 MATERIAL STORAGE, ORE, (2) VE 7 % WY-0038 WOLD TRONA CO. CT-1148 5/2/1995 BENETRON ORE UPGRADE FACILITY 2 EA PM ELECTROSTATIC PRECIPITATOR, 4 IN PARALLEL 0.0025 GWY-0038 WOLD TRONA CO. CT-1148 5/2/1995 BENETRON ORE UPGRADE FACILITY 2 EA VE 7 % WY-0038 WOLD TRONA CO. CT-1148 5/2/1995 MATERIAL HANDLING, SODA ASH PRODUCT PM ELECTROSTATIC PRECIPITATOR 0.005 GWY-0038 WOLD TRONA CO. CT-1148 5/2/1995 MATERIAL HANDLING, SODA ASH PRODUCT VE 7 % WY-0038 WOLD TRONA CO. CT-1148 5/2/1995 CALCINER & CALCINER BOILER, (2) PM WET SCRUBBER (VENTURI) AND PACKED TOWER CONDENSER ON CALCINER 0.005 GWY-0038 WOLD TRONA CO. CT-1148 5/2/1995 CALCINER & CALCINER BOILER, (2) VE 20 % 
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BACT Attachment 1 Table 2 RBLC Search Non-Metallic Mineral Processing

RBLC ID # Facility Name Permit Number Permit Date Process Name Pollutant Control Equipment Description Emission Limit UWY-0038 WOLD TRONA CO. CT-1148 5/2/1995 CALCINER & CALCINER BOILER, (2) NOX 

MONOWALL FURNACE CONSTRUCTION LOW NOX BURNERS WITH FUEL STAGING, 15% EXCESS AIR FLUE GAS RECIRCULATION(FGRS 15%) ON CALCINER BOILER 

0.048 L

WY-0038 WOLD TRONA CO. CT-1148 5/2/1995 CALCINER & CALCINER BOILER, (2) CO 15.12 LTN-0097 

TENN LUTTRELL COMPANY 

938511P 9/23/1994 VERTICAL SHAFT LIME KILN NOX INHERENT DESIGN OF THE VERTICAL SHAFT KILN 31.14 L

TN-0097 

TENN LUTTRELL COMPANY 

938511P 9/23/1994 VERTICAL SHAFT LIME KILN PM10 BAGHOUSE 1.85 L

TN-0097 

TENN LUTTRELL COMPANY 

938511P 9/23/1994 VERTICAL SHAFT LIME KILN SO2 3 PERCENT SULFUR LIMIT IN FUEL 7.71 L

TN-0097 

TENN LUTTRELL COMPANY 

938511P 9/23/1994 VERTICAL SHAFT LIME KILN TSP BAGHOUSE 3.24 L

TN-0097 

TENN LUTTRELL COMPANY 

938511P 9/23/1994 VERTICAL SHAFT LIME KILN VE BAGHOUSE 10 % 

TN-0097 

TENN LUTTRELL COMPANY 

938511P 9/23/1994 VERTICAL SHAFT LIME KILN VOC NONE LISTED IN PERMIT 6.3 L

TN-0097 

TENN LUTTRELL COMPANY 

938511P 9/23/1994 VERTICAL SHAFT LIME KILN CO NONE LISTED IN PERMIT 41.63 L

TN-0098 

TENN LUTTRELL COMPANY 

938513P 9/23/1994 

MATERIAL HANDLING OPERATIONS 

TSP 

BAGHOUSE ON LIME CRUSHING/SCREENING OPERATION 

0.05 G

TN-0098 

TENN LUTTRELL COMPANY 

938513P 9/23/1994 

MATERIAL HANDLING OPERATIONS 

VE BAGHOUSE 7 % 

 

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A-5-83 

BACT ATTACHMENT 2 

Emission Control Cost Analysis 

 

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A-5-84 

BACT Attachment 2 Table 1: Furnace 5 Control Cost Summary

NSM Line 5 Restart BACT Emission Control Cost Analysis

SO2 Control Cost Summary 

Control Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic's 

& AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

Wet Wall ElectroStatic 

Precipitator (WWESP) 80% 63 253 8,372,201 3,380,395 13,385 None Low Waste-water

Wet Scrubber 80% 63 253 7,970,886 2,291,431 9,073 None High Waste-water

NOx Control Cost Summary 

Control Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic's 

& AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

SCR with Re-heat of 

furnace exhaust gas 90% 25.5 229 10,868,371 5,957,963 25,982 NH3 Slip High

Catalyst 

Waste

PM Control Cost Summary 

Control Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic's 

& AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

Wet Wall ElectroStatic 

Precipitator (WWESP) 94% 43 668 8,372,201 3,203,603 4,796 None Low Waste-water

Dry ElectroStatic 

Precipitator (ESP) 94% 43 668 8,128,350 1,428,618 2,139 None Low Solid Waste

Wet Scrubbers High 

Efficiency 94% 43 668 7,970,886 2,114,639 3,166 None High Waste-water
 

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A-5-85 

BACT Attachment 2 Table 2: Furnace 5 SO2 Control - Wet Wall ESP 

NSM Line 5 Restart BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1)

ESP + auxillary equipment 3,090,000

Instrumentation 10% of control device cost (A) 309,000

MN Sales Taxes 6.5% of control device cost (A) 200,850

Freight 5% of control device cost (A) 154,500

Purchased Equipment Total (B) 22% 3,754,350

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 150,174

Handling & erection 50% of purchased equip cost (B) 1,877,175

Electrical 8% of purchased equip cost (B) 300,348

Piping 1% of purchased equip cost (B) 37,544

Insulation for ductwork 2% of purchased equip cost (B) 75,087

Painting 2% of purchased equip cost (B) 75,087

Direct Installation Costs 2,515,415

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 6,269,765

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 750,870

Construction & field expenses 20% of purchased equip cost (B) 750,870

Constractor fees 10% of purchased equip cost (B) 375,435

Start-up 1% of purchased equip cost (B) 37,544

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 75,087

Contingencies 3% of purchased equip cost (B) 112,631

Total Indirect Capital Costs 57% 2,102,436

Total Capital Investment (TCI) = DC + IC 8,372,201

OPERATING COSTS

Direct Operating Costs

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr 32,000

Supervisor 15% of operator costs 4,800

Coordinator 33% of operator costs 10,560

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 39,149

Maintenance Materials 1% of purchased equipment costs 37,544

Utilities

Electricity 0.05 $/kW-hr, 387.2 kW-hr, 8000 hr/yr 141,622

Water 0.22 $/Mgal, 2,115.0 gpm, 8000 hr/yr 221,867

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 2,115.0 gpm, 8000 hr/yr 1,522,800

Reagent (Caustic) 280.00 $/Ton, 157.9 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 w 176,792

Total Annual Direct Operating Costs, DC 2,187,135

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 68,096

Administration (2% total capital costs) 2% of total capital costs (TCI) 167,444

Property tax (1% total capital costs) 1% of total capital costs (TCI) 83,722

Insurance (1% total capital costs) 1% of total capital costs (TCI) 83,722

Captial Recovery 9% for a 20- year equipment life and a 7% interest rat 790,277

Total Indirect Operating Costs, IC 1,193,260

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,380,395

Pollutant Removed (tons/yr)B 252.6

Cost per ton of PM Removed 13,385

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 Capital cost estimated from 2001 Wheelabrator costs for ESP on proposed taconite processing facility

3 EPA Cost Manual 6th Ed. 2002
 

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BACT Attachment 2 Table 2: Furnace 5 SO2 Control - Wet Wall ESP (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 0 $/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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 0 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 207,240 scfm

 acf 235,000 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32 Hr 1 hr/8 hr shift 1,000 32,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collecto 71,423 ft2 collector area 8,249 $/ft2 collector area; $5775 if < 50,000 ft2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 387 kW-hr 3,097,549 141,622 $/kW-hr, 387.2 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

Water 0.22 Mgal 2115 gpm 1,015,200 221,867 $/Mgal, 2,115.0 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Cau 280 Ton 157.9 lb/hr 631 176,792 $/Ton, 157.9 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25.00 Ton 0.000 ton/hr 0 0 $/Ton, NA, 8000 hr/yr 

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/Ton, NA, 8000 hr/yr 

WW Treat 1.50 Mgal 2115 gpm 1,015,200 1,522,800 $/Mgal, 2,115.0 gpm, 8000 hr/yr

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr

Rep Parts 0 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

NA NA NA NA NA 315.70 Unit P to E from Title V Permit Application Form GI-07

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

NA NA NA NA 80% 63.14 Calculated basis control efficiency

Emission Reduction T/yr 252.6

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 235,000 5 0.65 211.5 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 2115 60 0.8 0.9 33.1 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 71,423 138.6 2 4 142.6 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 63.14 lb/hr SO2 2.50 lb NaOH/lb SO2 157.9 lb/hr Caustic

Lime Use 0.00 lb/hr SO2 1.53 lb Lime/lb SO2 0.000 T/hr Lime
 

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A-5-87 

BACT Attachment 2 Table 3: Furnace 5 SO2 Control - Wet Scrubber

NSM Line 5 Restart BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC (2) 2,982,000

Instrumentation 10% of control device cost (A) 298,200

MN Sales Taxes 6.5% of control device cost (A) 193,830

Freight 5% of control device cost (A) 149,100

Purchased Equipment Total (B) 22% 3,623,130

Installation (3)

Foundations & supports 12% of purchased equip cost (B) 434,776

Handling & erection 40% of purchased equip cost (B) 1,449,252

Electrical 1% of purchased equip cost (B) 36,231

Piping 30% of purchased equip cost (B) 1,086,939

Insulation 1% of purchased equip cost (B) 36,231

Painting 1% of purchased equip cost (B) 36,231

Installation Total 85% 3,079,661

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 6,702,791

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 362,313

Construction & field expenses 10% of purchased equip cost (B) 362,313

Construction fee 10% of purchased equip cost (B) 362,313

Start-up 1% of purchased equip cost (B) 36,231

Performance test 1% of purchased equip cost (B) 36,231

Contingencies 3% of purchased equip cost (B) 108,694

Total Indirect Capital Costs, IC 35% 1,268,096

Total Capital Investment (TCI) = DC + IC 7,970,886

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 14,400

Supervisor 0.15 15% of Operator Costs 2,160

Operating Materials

Reagent #1 280 $/Ton, 157.9 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 176,792

Lime NA - 

Packing 0.00 ft3/5 yr - 

Wastewater Treatment 1.50 $/Mgal, 423.0 gpm, 8000 hr/yr, 274,104

Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 14,400

Maintenance Materials 100% of Maint Labor, 0.0 , 8000 hr/yr 14,400

Electricity - Fan, Pump 0.05 $/kW-hr, 955 kW-hr, 8000 hr/yr 314,249

Total Annual Direct Operating Costs 810,505

Indirect Operating Costs

Overhead 60% of total labor and material costs 27,216

Administration (2% total capital costs) 2% of total capital costs (TCI) 159,418

Property tax (1% total capital costs) 1% of total capital costs (TCI) 79,709

Insurance (1% total capital costs) 1% of total capital costs (TCI) 79,709

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 1,134,875

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,480,926

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,291,431

Pollutant Removed (tons/yr)B SO2 253

Cost per ton of Pollutant Removed SO2 9,073

Notes & Assumptions

1) Sept 2004 Cost Estimates from Ceilcote

2) Cost factors for packed bed scrubber, unit is a combined ventrui/packed bed system

3) EPA Air Pollution Control Cost Manual 6th Ed 2002
 

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A-5-88 

BACT Attachment 2 Table 3: Furnace 5 SO2 Control - Wet Scrubber (Continued)

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Stainless Steel Packing Replacement Cost

Packing Life 5 years

CRF 0.0000

Packing cost per unit 35.86956522 $/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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Packing 0

Design Flow dscf 207,240 m

 acf 235,000 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32 Hr 0.5 hr/8 hr shift 450 14,400 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 2,160 15% of Operator Costs

Maint Labor 32.00 Hr 0.5 hr/8 hr shift 450 14,400 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls 100% of Maint Labor NA 14,400 of Maint Labor, 0.0 , 8000 hr/yr

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 954.6 kW-hr 6,873,212 314,249 $/kW-hr, 955 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

Water 0.22 Mgal 423.0 gpm 182,736 39,936 $/Mgal, 423.0 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Caustic) 280 Ton 157.85 lb/hr 631 176,792 $/Ton, 157.9 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Hr 0.00 lb/hr 0 0 $/Hr, 0.0 lb/hr, 8000 hr/yr

SW Disposal 25.00 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.50 Mgal 423.0 gpm 182,736 274,104 $/Mgal, 423.0 gpm, 8000 hr/yr, 

Catalyst 0 ft3 0 ft3 0 0 $/ft3, 0.0 ft3, 0, 8000 hr/yr

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

NA NA NA NA NA 315.70 Unit P to E from Title V Permit Application Form GI-07

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

NA NA NA NA 80% 63.14 Calculated basis control efficiency

Emission Reduction T/yr 252.6

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 235,000 12 0.55 0.7 857.0 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 2,115 125 0.8 0.7 88.8 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 423.0 62.5 0.8 0.7 8.9 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 63.14 lb/hr SO2 2.50 lb NaOH/lb SO2 157.85 lb/hr Caustic

Lime Use 0.00 lb/hr SO2 1.53 lb Lime/lb SO2 0.00 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr
 

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A-5-89 

NSM Line 5 NOx Control - Duct Burner for SCR & Flue Gas Re-Heat 

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1)

Control Device (A)

Instrumentation 10% of control device cost (A) See SCR 

MN Sales Taxes 6.5% of control device cost (A)

Freight 5% of control device cost (A)

Auxiliary equipment (not included in CD cost) 0% of control device cost (A)

Purchased Equipment Total (B) 18%

Installation

Foundations & supports 8% of purchased equip cost (B)

Handling, erection 14% of purchased equip cost (B)

Electrical 4% of purchased equip cost (B)

Piping 4% of purchased equip cost (B)

Insulation 1% of purchased equip cost (B)

Painting 1% of purchased equip cost (B)

Expenses not covered by items listed above 0% of purchased equip cost (B)

Site Preparation, as required Site Specific

Buildings, as required Site Specific

Installation Total 30%

Total Direct Capital Cost 

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B)

Construction, field exp. 5% of purchased equip cost (B)

Construction fee 10% of purchased equip cost (B)

Startup 2% of purchased equip cost (B)

Tests 1% of purchased equip cost (B)

Contingencies 3% of purchased equip cost (B)

Total Indirect Capital Costs 31%

Total Capital Investment (TCI) 11,393,580

Adjust TCI for Replacement Parts 525,209 10,868,371

Total Annualized Capital Costs 1,025,897

OPERATING COSTS

Direct Operating Costs

Operating Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of oper labor costs

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maintenance Materials 100% of maint labor costs

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 1,225 kW-hr, 8000 hr/yr

 Natural Gas (Fuel) NA 

 Water NA 

 Compressed Air NA 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 27.1 lb/hr, 8000 hr/yr, Ammonia

 Reagent #2 (Urea 50% Solution) NA 

 Solid Waste Disposal 25.00 $/Ton, 36.9 ton/yr

 Hazardous Waste Disposal NA 

 Wastewater Treatment NA 

 Catalyst 64.71 $/ft3, 6,329.4 ft3, 3, 8000 hr/yr

 Replacement Parts NA

Total Annual Direct Operating Costs Fixed + Variable O&M 907,667

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs (fixed O&M) 45,119

Property tax (1% total capital costs) 1% of total capital costs (TCI) 113,936

Insurance (1% total capital costs) 1% of total capital costs (TCI) 113,936

Administration (2% total capital costs) 2% of total capital costs (TCI) 227,872

Capital Recovery 9.44% for a 20- year equipment life and a 7% interest rate 1,025,897

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,526,759

SCR Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,434,426

Re-Heat Total Annual Cost (Annualized Capital Cost + Operating Cost) See App B Table 5 3,523,537

Combined Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,957,963

Pollutant Removed (tons/yr) 229

Cost per ton of NOx Removed 25,982

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. Sept 2004. It is used for catalsyt 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 The emission rate used in the control cost analysis is based on the RHF NOx P to E of 847 t/yr (193.4 lb/hr), and is adjusted to account for 

normal hours of operation and utilization rates as allowed by EPA BACT protocol. 

 See pg B-37 and B-38 in the New Source Review Workshop Manual, October 1999 (puzzle book).

Flue Gas Reheat Control Cost

5 Capital cost of TO unit $750,000 per John Zink, Feb 2005.

6 EPA control cost guideline for catalytic oxidizers used for operating cost analysis. EPA Air Pollution Control Cost Manual 6th Ed 2002

7 The re-heat total annual cost (annualized capital cost + operating cost) is from the "RHF Flue Gas Reheat" tab total annual cost per 

Attachment 2 Table 4
 

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A-5-90 

NSM Line 5 NOx Control - Duct Burner for SCR & Flue Gas Re-Heat (Continued)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

200k - 300k

Catalyst Replacement Cost Catalyst Cost per EPA Control Cost Manaul Section 4.2

Catalyst Life 3 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 0.3811 Amount Yrs Service T/yr Waste

Catalyst cost per unit 64.71 $/ft3 110.8 3 36.9

Amount Required 6329.4 ft

3 333,086

Catalyst Cost $456,703 Cost adjusted for freight & sales tax

Installation Labor 68,505 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 525,209

Annualized Cost 200,132

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 525,209

Design Flow 207,000 scfm

 acf 454,773 m @700 Deg F

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32.00 Hr 0.5 hr/8 hr shift 500 16,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 32.0 Hr 0.5 hr/8 hr shift 500 16,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1225.4 kW-hr 9,803,251 448,212 $/kW-hr, 1,225 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Anh 405 Ton 27.1 lb/hr 198,574 40,211 $/Ton, 27.1 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Ure 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25.00 Ton 36.9 ton/yr 37 923 $/Ton, 36.9 ton/yr

Haz W Disp 273.18 Ton 0.000 ton/3-yr period 0.00 0 $/Ton, 0.0 ton/3-yr period

WW Treat 1.50 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr

Catalyst 64.7 ft

3 6329.4 ft3 3 200,132 $/ft3, 6,329.4 ft3, 3, 8000 hr/yr

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

70.8 lb/hr 8,000 90.0% NA 254.79 Hourly P to E based on 952.8 t/yr from Permit Application. Annual 

Controlled Emission Rate emissions adjusted for normal operating hours and utilization.

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

NA NA NA NA 90% 25.48 Calculated basis control efficiency

Emission Reduction T/yr 229

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 454,773 11.4 0.55 0.9 1225.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.04 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 1225.4

Ammonia 63.7 lb/hr NOx 0.370 lb NH3/lb NOx 27.1 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 63.7 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 96.4 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5000 ft3

Flow #1 359256 acfm Basis SCR Bids for proposed 2001 Taconite Plant

Flow #2 454,773 acfm

Vol #2 6329.4 ft3

Attachment 2 Table 4 Continued

BACT Emission Control Cost Analysis
 

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NSM Line 5 NOx Control - Duct Burner for SCR & Flue Gas Re-Heat - SCR Costs

BACT Emission Control Cost Analysis

EPA SCR Cost Worksheet for Coal Fired Power Plants

Determine Comparable Boiler Size Based on Flue Gas Exhast Rate

RHF exhast flow scfm 207,000

Moisture Content 10%

Ind furnace exhast flow dcfm 186,300

Coal F Factor dscf/MMBtu 10,000

Equivalent Duty MMBtu/hr 1,118

Est Power Plant Efficiency 35%

Watt per Btu/hr 0.29307

Equivalent Power Plant kW 114,658

Uncontrolled NOx t/yr 310

Annual Operating Hours 8,000

Uncontrolled NOx lb/MMBtu 0.069

Plant Capacity kW A 114,658

Uncontrolled NOx lb/MMBtu B 0.069

Nox Reduction Efficiency C 90

Capital Cost $/kW D 99.37 Total Capital Cost $11,393,580

 D= 75*(300,000*((B/1.5)^0.05*(C/100)^0.04)/A)^0.35

Plant Capacity kW A 114,658

Capital Cost $/kW D $99.37

Fixed O&M Cost, $/yr E $75,198

E = D*A*0.0066

Plant Capacity kW A 114,658

Uncontrolled NOx lb/MMBtu B 0.07

Nox Reduction Efficiency C 90

Capital Cost $/kW D $99.37

Annual Capacity Factor G 0.82

Heat Input MMBtu/hr H 6000

Variable O&M Cost $/yr F $832,469

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.

Attachment 2 Table 4 Continued
 

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A-5-92 

NSM Line 5 NOx Control - Duct Burner for SCR & Flue Gas Re-Heat - Duct Burner

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1)

Control Device (A) 864,355

Instrumentation 10% of control device cost (A) 86,436

MN Sales Taxes 6.5% of control device cost (A) 56,183

Freight 5% of control device cost (A) 43,218

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 1,050,192

Installation

Foundations & supports 8% of purchased equip cost (B) 84,015

Handling, erection 14% of purchased equip cost (B) 147,027

Electrical 4% of purchased equip cost (B) 42,008

Piping 2% of purchased equip cost (B) 21,004

Insulation 1% of purchased equip cost (B) 10,502

Painting 1% of purchased equip cost (B) 10,502

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 315,057

Total Direct Capital Cost 1,365,249

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 105,019

Construction, field exp. 5% of purchased equip cost (B) 52,510

Construction fee 10% of purchased equip cost (B) 105,019

Startup 2% of purchased equip cost (B) 21,004

Tests 1% of purchased equip cost (B) 10,502

Contingencies 3% of purchased equip cost (B) 31,506

Total Indirect Capital Costs 31% 325,559

Total Capital Investment (TCI) 1,690,808

Adjust TCI for Replacement Parts 0 1,690,808

Total Annualized Capital Costs 159,600

OPERATING COSTS

Direct Operating Costs

Operating Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 16,000

Supervisor 15% of oper labor costs 2,400

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 16,000

Maintenance Materials 100% of maint labor costs 16,000

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 360 kW-hr, 8000 hr/yr 131,637

 Natural Gas (Fuel) 5.50 $/Mft3, 1,168 scfm, 8000 hr/yr 3,084,027

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Caustic) NA - 

 Reagent #2 NA - 

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 3,266,064

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 30,240

Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,908

Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,908

Administration (2% total capital costs) 2% of total capital costs (TCI) 33,816

Capital Recovery 9.44% for a 20- year equipment life and a 7% interest rat 159,600

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 257,473

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,523,537

Pollutant Removed (tons/yr)B -

Cost per ton of PM Removed -

Notes & Assumptions

1 EPA control cost guideline for thermal oxidizers for cost analysis. 

2 EPA Air Pollution Control Cost Manual 6th Ed 2002

3 Capital cost estimate from John Zink

4 Heat capacity from Perry's 5th Edition Chemical engineers Handbook

Attachment 2 Table 4 Continued
 

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A-5-93 

NSM Line 5 NOx Control - Duct Burner for SCR & Flue Gas Re-Heat - Duct Burner (Continued)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 207,000 scfm

 acf 235,140 m

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32 Hr 0.5 hr/8 hr shift 500 16,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% NA 2400 15% of Operator Costs

Maint Labor 32 Hr 0.5 hr/8 hr shift 500 16,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 359.9 kW-hr 2,879,147 131,637 $/kW-hr, 360 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 1,168 scfm 560,732 3,084,027 $/Mft3, 1,168 scfm, 8000 hr/yr

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Cau 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, Ammonia

Reagent #2 100 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25.00 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

WW Treat 1.50 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Emis Rate

Factor Measure Rate Measure T/yr Comments/Notes

Controlled Emission Rate 

Perf Unit of Flow Unit of Emis Rate

Guarantee Measure Rate Measure T/yr Comments/Notes

Emission Reduction T/yr

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 304,525 5 0.55 0.9 359.9 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Attachment 2 Table 4 Continued

BACT Emission Control Cost Analysis
 

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NSM Line 5 NOx Control - Duct Burner for SCR & Flue Gas Re-Heat - Duct Burner (Continued)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 207,000 scfm

 acf 235,140 m

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32 Hr 0.5 hr/8 hr shift 500 16,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% NA 2400 15% of Operator Costs

Maint Labor 32 Hr 0.5 hr/8 hr shift 500 16,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 359.9 kW-hr 2,879,147 131,637 $/kW-hr, 360 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 1,168 scfm 560,732 3,084,027 $/Mft3, 1,168 scfm, 8000 hr/yr

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Cau 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, Ammonia

Reagent #2 100 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25.00 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

WW Treat 1.50 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Emis Rate

Factor Measure Rate Measure T/yr Comments/Notes

Controlled Emission Rate 

Perf Unit of Flow Unit of Emis Rate

Guarantee Measure Rate Measure T/yr Comments/Notes

Emission Reduction T/yr

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 304,525 5 0.55 0.9 359.9 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Attachment 2 Table 4 Continued

BACT Emission Control Cost Analysis
 

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Attachment 2 Table 4 Continued

NSM Line 5 NOx Control - Duct Burner for SCR & Flue Gas Re-Heat - Duct Burner (Continued)

BACT Emission Control Cost Analysis

Duct Burner Cost Estimate

Auxiliary Fuel Use Equation 3.19 

Twi 150 Deg F - Temperature of waste gas into heat recovery

Tfi 750 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 570 Deg F - Temperature of waste gas out of heat recovery 152292 scfm

359 scf/lbmole

Tfo 330 Deg F - Temperature of flue gas into of heat recovery mw flue gas (air)

Flow Calculator mw flue gas (H2O)

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane) Design Flow 207,000 scfm 28 mw CO 0 v % 0

-hwg 0 Btu/lb Heat of combustion waste gas 150 Temp Deg F 44 mw CO2 15 v % 279979.72 22.0% 0.24 0.0528

Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air) na % Moisture 18 mw H2O 10 v % 76358.106 6.0% 0.46 0.0276

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F 235,140 acfm 28 mw N2 60 v % 712675.65 56.0% 0.27 0.1512

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 32 mw O2 15 v % 203621.62 16.0% 0.23 0.0368

Qwg 207,000 scfm - Flow of waste gas 330 100 v % 1272635.1 100.0% 0.2684

 304,525

Qaf 1,168 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 208,168 scfm Flue Gas Cost in 1988 $'s $455,868

Current Cost @ 3% inflation $753,480

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)
 

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BACT Attachment 2 Table 6: Furnace 5 PM Control - Wet Wall ESP 

NSM Line 5 Restart BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1 & 2)

ESP + auxillary equipment 3,090,000

Instrumentation 10% of control device cost (A) 309,000

MN Sales Taxes 6.5% of control device cost (A) 200,850

Freight 5% of control device cost (A) 154,500

Purchased Equipment Total (B) 22% 3,754,350

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 150,174

Handling & erection 50% of purchased equip cost (B) 1,877,175

Electrical 8% of purchased equip cost (B) 300,348

Piping 1% of purchased equip cost (B) 37,544

Insulation for ductwork 2% of purchased equip cost (B) 75,087

Painting 2% of purchased equip cost (B) 75,087

Direct Installation Costs 2,515,415

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 6,269,765

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 750,870

Construction & field expenses 20% of purchased equip cost (B) 750,870

Constractor fees 10% of purchased equip cost (B) 375,435

Start-up 1% of purchased equip cost (B) 37,544

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 75,087

Contingencies 3% of purchased equip cost (B) 112,631

Total Indirect Capital Costs 57% 2,102,436

Total Capital Investment (TCI) = DC + IC 8,372,201

OPERATING COSTS

Direct Operating Costs

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr 32,000

Supervisor 15% of operator costs 4,800

Coordinator 33% of operator costs 10,560

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 39,149

Maintenance Materials 1% of purchased equipment costs 37,544

Utilities

Electricity 0.05 $/kW-hr, 387.2 kW-hr, 8000 hr/yr 141,622

Water 0.22 $/Mgal, 2,115.0 gpm, 8000 hr/yr 221,867

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 2,115.0 gpm, 8000 hr/yr 1,522,800

Reagent (Caustic) 280.00 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 5 - 

Total Annual Direct Operating Costs, DC 2,010,343

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 68,096

Administration (2% total capital costs) 2% of total capital costs (TCI) 167,444

Property tax (1% total capital costs) 1% of total capital costs (TCI) 83,722

Insurance (1% total capital costs) 1% of total capital costs (TCI) 83,722

Captial Recovery 9% for a 20- year equipment life and a 7% interest rat 790,277

Total Indirect Operating Costs, IC 1,193,260

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,203,603

Pollutant Removed (tons/yr)B 667.9

Cost per ton of PM Removed 4,796

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 Capital cost estimated from 2001 Wheelabrator costs for ESP on proposed taconite processing facility

3 EPA Cost Manual 6th Ed. 2002
 

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BACT Attachment 2 Table 6: Furnace 5 PM Control - Wet Wall ESP (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 0 $/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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 0 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 207,240 scfm

 acf 235,000 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32 Hr 1 hr/8 hr shift 1,000 32,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collecto 71,423 ft2 collector area 8,249 $/ft2 collector area; $5775 if < 50,000 ft2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 387 kW-hr 3,097,549 141,622 $/kW-hr, 387.2 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

Water 0.22 Mgal 2115 gpm 1,015,200 221,867 $/Mgal, 2,115.0 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Cau 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25.00 Ton 0.000 ton/hr 0 0 $/Ton, 0.100 gr/dscf, 8000 hr/yr 

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/Ton, 0.100 gr/dscf, 8000 hr/yr 

WW Treat 1.50 Mgal 2115 gpm 1,015,200 1,522,800 $/Mgal, 2,115.0 gpm, 8000 hr/yr

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr

Rep Parts 0 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.1 gr/dscf dscf 207,240 m NA 710.54

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

0.006 gr/dscf 207,240 dscfm 94% 42.63 Calculated basis in and out grain loadings

Emission Reduction T/yr 667.9

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 235,000 5 0.65 211.5 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 2115 60 0.8 0.9 33.1 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 71,423 138.6 2 4 142.6 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 0.00 lb/hr SO2 2.50 lb NaOH/lb SO2 0.000 T/hr Caustic

Lime Use 0.00 lb/hr SO2 1.53 lb Lime/lb SO2 0.000 T/hr Lime
 

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BACT Attachment 2 Table 7: Furnace 5 PM Control - Dry ESP 

NSM Line 5 Restart BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1)

ESP + auxillary equipment 3,000,000

Instrumentation 10% of control device cost (A) 300,000

MN Sales Taxes 6.5% of control device cost (A) 195,000

Freight 5% of control device cost (A) 150,000

Purchased Equipment Total (B) 22% 3,645,000

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 145,800

Handling & erection 50% of purchased equip cost (B) 1,822,500

Electrical 8% of purchased equip cost (B) 291,600

Piping 1% of purchased equip cost (B) 36,450

Insulation for ductwork 2% of purchased equip cost (B) 72,900

Painting 2% of purchased equip cost (B) 72,900

Direct Installation Costs 2,442,150

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 6,087,150

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 729,000

Construction & field expenses 20% of purchased equip cost (B) 729,000

Constractor fees 10% of purchased equip cost (B) 364,500

Start-up 1% of purchased equip cost (B) 36,450

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 72,900

Contingencies 3% of purchased equip cost (B) 109,350

Total Indirect Capital Costs 57% 2,041,200

Total Capital Investment (TCI) = DC + IC 8,128,350

OPERATING COSTS

Direct Operating Costs

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr 32,000

Supervisor 15% of operator costs 4,800

Coordinator 33% of operator costs 10,560

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 38,249

Maintenance Materials 1% of purchased equipment costs 36,450

Utilities

Electricity 0.05 $/kW-hr, 354.1 kW-hr, 8000 hr/yr 129,503

Water NA - 

Solid Waste Disposal 25.00 $/Ton, 0.100 gr/dscf, 8000 hr/yr 17,763

Wastewater Treatment NA - 

Reagent (Caustic) 280.00 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 5 - 

Total Annual Direct Operating Costs, DC 269,326

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 66,900

Administration (2% total capital costs) 2% of total capital costs (TCI) 162,567

Property tax (1% total capital costs) 1% of total capital costs (TCI) 81,284

Insurance (1% total capital costs) 1% of total capital costs (TCI) 81,284

Captial Recovery 9% for a 20- year equipment life and a 7% interest rat 767,259

Total Indirect Operating Costs, IC 1,159,292

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,428,618

Pollutant Removed (tons/yr)B 667.9

Cost per ton of PM Removed 2,139

Notes & Assumptions

1 Capital cost estimated from 2001 Wheelabrator costs for ESP on proposed taconite processing facility

2 EPA Cost Manual 6th Ed. 2002
 

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A-5-99 

BACT Attachment 2 Table 7: Furnace 5 PM Control - Dry ESP (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 0 $/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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 0 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 207,240 dscfm

 acf 235,000 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32 Hr 1 hr/8 hr shift 1,000 32,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collecto 71,423 ft2 collector area 8,249 $/ft2 collector area; $5775 if < 50,000 ft2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 354 kW-hr 2,832,480 129,503 $/kW-hr, 354.1 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Cau 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25.00 Ton 0.089 ton/hr 711 17,763 $/Ton, 0.100 gr/dscf, 8000 hr/yr 

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/Ton, 0.100 gr/dscf, 8000 hr/yr 

WW Treat 1.50 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr

Rep Parts 0 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.1 gr/dscf dscf 207,240 m NA 710.54

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

0.006 gr/dscf 207,240 dscfm 94% 42.63 Calculation basis in and out grain loadings

Emission Reduction T/yr 667.9

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 235,000 5 0.65 211.5 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 71,423 138.6 2 4 142.6 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 0.00 lb/hr SO2 2.50 lb NaOH/lb SO2 0.000 T/hr Caustic

Lime Use 0.00 lb/hr SO2 1.53 lb Lime/lb SO2 0.000 T/hr Lime
 

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A-5-100 

BACT Attachment 2 Table 8: Furnace 5 PM Control - Wet Scrubber

NSM Line 5 Restart BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC (2) 2,982,000

Instrumentation 10% of control device cost (A) 298,200

MN Sales Taxes 6.5% of control device cost (A) 193,830

Freight 5% of control device cost (A) 149,100

Purchased Equipment Total (B) 22% 3,623,130

Installation (3)

Foundations & supports 12% of purchased equip cost (B) 434,776

Handling & erection 40% of purchased equip cost (B) 1,449,252

Electrical 1% of purchased equip cost (B) 36,231

Piping 30% of purchased equip cost (B) 1,086,939

Insulation 1% of purchased equip cost (B) 36,231

Painting 1% of purchased equip cost (B) 36,231

Installation Total 85% 3,079,661

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 6,702,791

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 362,313

Construction & field expenses 10% of purchased equip cost (B) 362,313

Construction fee 10% of purchased equip cost (B) 362,313

Start-up 1% of purchased equip cost (B) 36,231

Performance test 1% of purchased equip cost (B) 36,231

Contingencies 3% of purchased equip cost (B) 108,694

Total Indirect Capital Costs, IC 35% 1,268,096

Total Capital Investment (TCI) = DC + IC 7,970,886

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 14,400

Supervisor 0.15 15% of Operator Costs 2,160

Operating Materials

Reagent #1 NA - 

Lime NA - 

Packing 0.00 ft3/5 yr - 

Wastewater Treatment 1.50 $/Mgal, 423.0 gpm, 8000 hr/yr, 274,104

Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 14,400

Maintenance Materials 100% of Maint Labor, 0.0 , 8000 hr/yr 14,400

Electricity - Fan, Pump 0.05 $/kW-hr, 955 kW-hr, 8000 hr/yr 314,249

Total Annual Direct Operating Costs 633,713

Indirect Operating Costs

Overhead 60% of total labor and material costs 27,216

Administration (2% total capital costs) 2% of total capital costs (TCI) 159,418

Property tax (1% total capital costs) 1% of total capital costs (TCI) 79,709

Insurance (1% total capital costs) 1% of total capital costs (TCI) 79,709

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 1,134,875

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,480,926

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,114,639

Pollutant Removed (tons/yr)B PM10 Filterable 668

Cost per ton of Pollutant Removed PM10 Total 3,166

Notes & Assumptions

1) Sept 2004 Cost Estimates from Ceilcote

2) Cost factors for packed bed scrubber, unit is a combined ventrui/packed bed system

3) EPA Air Pollution Control Cost Manual 6th Ed 2002
 

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A-5-101 

BACT Attachment 2 Table 8: Furnace 5 PM Control - Wet Scrubber (Continued)

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Stainless Steel Packing Replacement Cost

Packing Life 5 years

CRF 0.0000

Packing cost per unit 35.86956522 $/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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Packing 0

Design Flow dscf 207,240 m

 acf 235,000 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32 Hr 0.5 hr/8 hr shift 450 14,400 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 2,160 15% of Operator Costs

Maint Labor 32.00 Hr 0.5 hr/8 hr shift 450 14,400 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls 100% of Maint Labor NA 14,400 of Maint Labor, 0.0 , 8000 hr/yr

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 954.6 kW-hr 6,873,212 314,249 $/kW-hr, 955 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

Water 0.22 Mgal 423.0 gpm 182,736 39,936 $/Mgal, 423.0 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Caustic) 280 Ton 0.00 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Hr 0.00 lb/hr 0 0 $/Hr, 0.0 lb/hr, 8000 hr/yr

SW Disposal 25.00 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.50 Mgal 423.0 gpm 182,736 274,104 $/Mgal, 423.0 gpm, 8000 hr/yr, 

Catalyst 0 ft3 0 ft3 0 0 $/ft3, 0.0 ft3, 0, 8000 hr/yr

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.1 gr/dscf 207,240 dscfm NA 710.54

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

0.006 gr/dscf 207,240 dscfm 94% 42.63 Calculation basis in and out grain loadings

Emission Reduction T/yr 667.9

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 235,000 12 0.55 0.7 857.0 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 2,115 125 0.8 0.7 88.8 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 423.0 62.5 0.8 0.7 8.9 OAQPS Cost Cont Manual 6th ed - Eq 1.49

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

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr
P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

BACT Attachment 2 Table 9: Furnace 5 Pellet Discharge Control Cost Summary

NSM Line 5 Restart BACT Emission Control Cost Analysis

PM Control Cost Summary Control Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic

& AQRV's

Wet Scrubbers High 

Efficiency 92% 5 52 133,650 177,067 3,390 None 

Wet Wall ElectroStatic 

Precipitator (WWESP) 92% 5 52 4,744,247 1,033,809 19,792 None 
 

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A-5-103 

BACT Attachment 2 Table 10: Furnace 5 PM Control - Wet Wall ESP 

NSM Line 5 Restart BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1 & 2)

ESP + auxillary equipment 1,751,000

Instrumentation 10% of control device cost (A) 175,100

MN Sales Taxes 6.5% of control device cost (A) 113,815

Freight 5% of control device cost (A) 87,550

Purchased Equipment Total (B) 22% 2,127,465

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 85,099

Handling & erection 50% of purchased equip cost (B) 1,063,733

Electrical 8% of purchased equip cost (B) 170,197

Piping 1% of purchased equip cost (B) 21,275

Insulation for ductwork 2% of purchased equip cost (B) 42,549

Painting 2% of purchased equip cost (B) 42,549

Direct Installation Costs 1,425,402

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 3,552,867

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 425,493

Construction & field expenses 20% of purchased equip cost (B) 425,493

Constractor fees 10% of purchased equip cost (B) 212,747

Start-up 1% of purchased equip cost (B) 21,275

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 42,549

Contingencies 3% of purchased equip cost (B) 63,824

Total Indirect Capital Costs 57% 1,191,380

Total Capital Investment (TCI) = DC + IC 4,744,247

OPERATING COSTS

Direct Operating Costs

Operator 32.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr 32,000

Supervisor 15% of operator costs 4,800

Coordinator 33% of operator costs 10,560

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 21,635

Maintenance Materials 1% of purchased equipment costs 21,275

Utilities

Electricity 0.05 $/kW-hr, 56.2 kW-hr, 8000 hr/yr 20,549

Water 0.22 $/Mgal, 288.0 gpm, 8000 hr/yr 30,212

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 288.0 gpm, 8000 hr/yr 207,360

Reagent (Caustic) 280.00 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 5 - 

Total Annual Direct Operating Costs, DC 348,390

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 47,826

Administration (2% total capital costs) 2% of total capital costs (TCI) 94,885

Property tax (1% total capital costs) 1% of total capital costs (TCI) 47,442

Insurance (1% total capital costs) 1% of total capital costs (TCI) 47,442

Captial Recovery 9% for a 20- year equipment life and a 7% interest rat 447,823

Total Indirect Operating Costs, IC 685,419

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,033,809

Pollutant Removed (tons/yr) 52.2

Cost per ton of PM Removed 19,792

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 Capital cost estimated from 2001 Wheelabrator costs for ESP on proposed taconite processing facility

3 EPA Cost Manual 6th Ed. 2002
 

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A-5-104 

BACT Attachment 2 Table 10: Furnace 5 PM Control - Wet Wall ESP (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 0 $/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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 0 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 27,700 scfm

 acfm 32,000

t Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Cost $ Measure Rate Measure Use* Cost

32 Hr 1 hr/8 hr shift 1,000 32,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr

NA NA NA Calc'd as % of labor costs

0.1155 $/ft2

 collecto 9,726 ft2 collector area 4,125 $/ft

2 collector area; $5775 if < 50,000 ft2

NA NA 1% of purchased equipment costs

ents, Waste Management & Replacements

0.046 kW-hr 56 kW-hr 449,436 20,549 $/kW-hr, 56.2 kW-hr, 8000 hr/yr

5.50 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

0.22 Mgal 288 gpm 138,240 30,212 $/Mgal, 288.0 gpm, 8000 hr/yr

0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

25.00 Ton 0.000 ton/hr 0 0 $/Ton, 0.060 gr/dscf, 8000 hr/yr 

273.18 Ton 0.000 ton/hr 0 0 $/Ton, 0.060 gr/dscf, 8000 hr/yr 

1.50 Mgal 288 gpm 138,240 207,360 $/Mgal, 288.0 gpm, 8000 hr/yr

0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr

0 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Emission Rate 

Unit of Flow Unit of Control Eff. Emis Rate

Measure Rate Measure % T/yr Comments/Notes

gr/dscf 27,700 dscfm NA 56.98

ission Rate 

Unit of Flow Unit of Control Eff. Emis Rate

Measure Rate Measure % T/yr Comments/Notes

gr/dscf 27,700 dscfm 92% 4.75 Calculated basis in and out grain loadings

ction T/yr 52.2

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 32,000 5 0.65 28.8 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 288 60 0.8 0.9 4.5 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 9,726 18.9 2 4 22.9 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30
 

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A-5-105 

BACT Attachment 2 Table 11: Furnace 5 Pellet Discharge PM Control - Wet Scrubber

NSM Line 5 Restart BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) , (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC (2) 50,000

Instrumentation 10% of control device cost (A) 5,000

MN Sales Taxes 6.5% of control device cost (A) 3,250

Freight 5% of control device cost (A) 2,500

Purchased Equipment Total (B) 22% 60,750

Installation 

Foundations & supports 12% of purchased equip cost (B) 7,290

Handling & erection 40% of purchased equip cost (B) 24,300

Electrical 1% of purchased equip cost (B) 608

Piping 30% of purchased equip cost (B) 18,225

Insulation 1% of purchased equip cost (B) 608

Painting 1% of purchased equip cost (B) 608

Installation Total 85% 51,638

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 112,388

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 6,075

Construction & field expenses 10% of purchased equip cost (B) 6,075

Construction fee 10% of purchased equip cost (B) 6,075

Start-up 1% of purchased equip cost (B) 608

Performance test 1% of purchased equip cost (B) 608

Contingencies 3% of purchased equip cost (B) 1,823

Total Indirect Capital Costs, IC 35% 21,263

Total Capital Investment (TCI) = DC + IC 133,650

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 14,400

Supervisor 0.15 15% of Operator Costs 2,160

Operating Materials

Reagent #1 NA - 

Lime NA - 

Packing 0.00 ft3/5 yr - 

Wastewater Treatment 1.50 $/Mgal, 57.6 gpm, 8000 hr/yr, 37,325

Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 14,400

Maintenance Materials 100% of Maint Labor, 0.0 , 8000 hr/yr 14,400

Electricity - Fan, Pump 0.05 $/kW-hr, 130 kW-hr, 8000 hr/yr 42,791

Total Annual Direct Operating Costs 125,476

Indirect Operating Costs

Overhead 60% of total labor and material costs 27,216

Administration (2% total capital costs) 2% of total capital costs (TCI) 2,673

Property tax (1% total capital costs) 1% of total capital costs (TCI) 1,337

Insurance (1% total capital costs) 1% of total capital costs (TCI) 1,337

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 19,029

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 51,591

Total Annual Cost (Annualized Capital Cost + Operating Cost) 177,067

Pollutant Removed (tons/yr) PM10 Filterable 52

Cost per ton of Pollutant Removed PM10 Total 3,390

Notes & Assumptions

1) Oct 2004 Cost Estimate from Ducon

2) Cost factors for packed bed scrubber, unit is a combined ventrui/packed bed system

3) EPA Air Pollution Control Cost Manual 6th Ed 2002
 

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A-5-106 

BACT Attachment 2 Table 11: Furnace 5 Pellet Discharge PM Control - Wet Scrubber (Continued)

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Stainless Steel Packing Replacement Cost

Packing Life 5 years

CRF 0.0000

Packing cost per unit 35.86956522 $/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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Packing 0

Design Flow dscf 27,700 m

 acf 32,000 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32 Hr 0.5 hr/8 hr shift 450 14,400 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 2,160 15% of Operator Costs

Maint Labor 32.00 Hr 0.5 hr/8 hr shift 450 14,400 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls 100% of Maint Labor NA 14,400 of Maint Labor, 0.0 , 8000 hr/yr

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 130.0 kW-hr 935,927 42,791 $/kW-hr, 130 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

Water 0.22 Mgal 57.6 gpm 24,883 5,438 $/Mgal, 57.6 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1(Caustic) 280 Ton 0.00 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Hr 0.00 lb/hr 0 0 $/Hr, 0.0 lb/hr, 8000 hr/yr

SW Disposal 25.00 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.50 Mgal 57.6 gpm 24,883 37,325 $/Mgal, 57.6 gpm, 8000 hr/yr, 

Catalyst 0 ft3 0 ft3 0 0 $/ft3, 0.0 ft3, 0, 8000 hr/yr

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.06 gr/dscf 27,700 dscfm NA 56.98

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

0.005 gr/dscf 27,700 dscfm 92% 4.75 Calculation basis in and out grain loadings

Emission Reduction T/yr 52.2

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 32,000 12 0.55 0.7 116.7 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 288 125 0.8 0.7 12.1 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 57.6 62.5 0.8 0.7 1.2 OAQPS Cost Cont Manual 6th ed - Eq 1.49
 

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A-5-107 

BACT Attachment 2 Table 12: Line 5 Restart - Summary of Utility, Chemical and Supply Costs

NSM Line 5 Restart BACT Emission Control Cost Analysis

Utilities Chemicals Etc Unit Cost Units Information Source Assumptions/Comments

Electricity 0.046 $/kwh

Energy Information Administration - 

Minnesota, Average Electrical Costs for MN 

in 2002

http://www.eia.doe.gov/emeu/states/sep_prices/ind/pr_ind_mn.html#foot

notes, Conversion factor: 3412 BTU/kWh.

Natural Gas 5.50 $/mscf Northshore Mining Co. 2004 Gas pricing in NE Minnesota

Water 0.22 mgal OAQPS Manual '98 cost adjusted for 3% inflation

Compressed Air 0.27 $/mscf OAQPS Manual Dried & Filtered, Section 5.4.1.8. '98 cost adjusted for 3% inflation

Oxygen 17.45 $/mscf Air Products Web Site Budgetary Price Quote 4/8/05

Wastewater Disposal 1.50 $/mgal EPA Air Pollution Control Cost Manual, 6th ed Used Avg, Section 1.0, Chapter 2 p 2-32. '02 cost estimate

Wastewater Biotreat 5.38 $/mgal OAQPS Manual Used Avg, Section 9.6.8 p 9-55. '92 cost adjusted for 3% inflation

Solid Waste Disposal (ESP) 25.00 $/ton OAQPS Manual EPA Cost Manual 6th ed. 1/2002, Range $20-$30. Used Average

Solid Waste Disposal 

(Baghouse) $45 25.00 $/ton OAQPS Manual

Used $25/ton EPA Cost Manual 6th ed. For Fab Filters 1/2002, Range 

$35-$55. Average is $45

Haz Waste Disposal 273.18 $/ton OAQPS Manual 10 x's SW, Section 6.4.1.8 p 6-53. '98 cost adjusted for 3% inflation

Waste Transport 0.55 $/ton-mi OAQPS Manual Travel Distance 0.5 mi. '98 cost adjusted for 3% inflation

Internal Waste Recycle 1.00 $/ton Corus Study Study use$1/ton to cover cost of materials movement 

Chemicals & Supplies

Ammonia 405 $/ton Hawkins Chemical Anhydrous; includes delivery

Urea 0.085 $/lb Hawkins Chemical 50% solution of urea in water; includes delivery

Caustic 280 $/ton Hawkins Chemical 50% solution (50 Deg Be); includes delivery

Lime 100 $/ton Corus Study

SCR Catalyst

CO Catalyst

Baghouse Filter Bags 35 $/bag Engineering Estimate

Other

Annual Op. Hrs 8000 Engineering Estimate

Utilization Rate 90% Engineering Estimate

Operating Labor 32 $/hr Northshore Mining Co. Taconite Industry Labor Rates

Supervisor 15% of Op. Labor cost EPA Cost Manual 6th ed. 1/2002

Maintenance Labor 32.00 $/hr Northshore Mining Co. Taconite Industry Labor Rates

Maintenance Labor - ESP's 0.1155 $/ft2 If area <50,000 ft2

, then constant $5775

EPA Cost Manual 6th ed. 1/2002, was $12.5/h in 1987. Assumed to be 

$17.50/h in 2003. Use ratio to estimate factor. 

((17.50*0.0825/12.50)=0.1155.

Also for Area <50,000 ft2, fixed cost was $4125 in 1987. Used ratio to 

get $5775 to account for inflation ((17.5*4125)/12.50 = 5775.

Maintenance Materials 100%

Sales Tax 6.50% Mn Sales Tax Rate

Interest Rate 7.0% % Estimated prime rate plus 3%

Equipment Life (scrubbers) 10 yrs Engineering Estimate

Equipment Life (all other 

equip. except scrubbers) 20 yrs Engineering Estimate

Note: Reviewed by Northshore Mining Co for consistency with local prices. 
 

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A-5-108 

BACT Attachment 2 Table 13: Furnace 5 NOx Control - Low Temperature Oxidation (LTO)

NSM Line 5 Restart BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC (2)

Instrumentation 1% of control device cost (A)

MN Sales Taxes 6.5% of control device cost (A)

Freight 5% of control device cost (A)

Auxiliary equipment (not included in CD cost) 5.0% of control device cost (A)

Purchased Equipment Total (B) 18%

Installation (3)

Foundations & supports 12% of purchased equip cost (B)

Handling & erection 40% of purchased equip cost (B)

Electrical 1% of purchased equip cost (B)

Piping 30% of purchased equip cost (B)

Insulation 1% of purchased equip cost (B)

Painting 1% of purchased equip cost (B)

Installation Total 85%

Site Preparation, as required Site Specific

Buildings, as required Site Specific

Total Direct Capital Cost, DC 

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B)

Construction & field expenses 10% of purchased equip cost (B)

Construction fee 10% of purchased equip cost (B)

Start-up 1% of purchased equip cost (B)

Performance test 1% of purchased equip cost (B)

Contingencies 3% of purchased equip cost (B)

Total Indirect Capital Costs, IC (4) 35%

Total Capital Investment (TCI) per BOC Paper 6,932,459

Total Annualized Capital Costs (capital recovery) 654,375

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 16,000

Supervisor 0.15 15% of Operator Costs 2,400

Operating Materials

Reagent #1 (O2) 17 $/Mscf, 10.6 Mscfh, 8000 hr/yr, 1,326,487

Water 0.22 $/Mgal, 124.3 gpm, 8000 hr/yr 13,044

Packing 0.00 ft3/5 yr - 

Wastewater Treatment 5.38 $/Mgal, 124.3 gpm, 8000 hr/yr, 320,847

Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 16,000

Maintenance Materials 100% of Maint Labor, 0.0 , 8000 hr/yr 16,000

Electricity ozone gen, pumps & fan 0.05 $/kW-hr, 1,852 kW-hr, 8000 hr/yr 677,527

Total Annual Direct Operating Costs 2,388,305

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,240

Administration (2% total capital costs) 2% of total capital costs (TCI) 138,649

Property tax (1% total capital costs) 1% of total capital costs (TCI) 69,325

Insurance (1% total capital costs) 1% of total capital costs (TCI) 69,325

Capital Recovery 9.44% for a 20- year equipment life and a 7% interest rate 654,375

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 961,913

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,350,218

Pollutant Removed (tons/yr)B NOx 231

Cost per ton of Pollutant Removed NOx 14,500

Notes & Assumptions

1) July 2001 Cost Estimates from BOC

2) Cost factors for packed bed scrubber, unit is a combined ventrui/packed bed system

3) EPA Air Pollution Control Cost Manual 6th Ed 2002

4) LoTOx cost of $60/kW ($52/kW adjusted for inflation) Table 5, Paper #147 Adrian Day and Naresh Suchak BOC Gases
 

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A-5-109 

BACT Attachment 2 Table 13: Furnace 5 NOx Control - Low Temperature Oxidation (LTO) (Continued)

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Stainless Steel Packing Replacement Cost

Packing Life 5 years

CRF 0.0000

Packing cost per unit 35.86956522 $/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

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ 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

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Packing 0

Design Flow 207,240 dscfm

 acf 235,500 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 32.00 Hr 0.5 hr/8 hr shift 500 16,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 2,400 15% of Operator Costs

Maint Labor 32.00 Hr 0.5 hr/8 hr shift 500 16,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls 100% of Maint Labor NA 16,000 of Maint Labor, 0.0 , 8000 hr/yr

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1852.3 kW-hr 14,818,792 677,527 $/kW-hr, 1,852 kW-hr, 8000 hr/yr

Natural Gas 5.50 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr

Water 0.22 Mgal 124.3 gpm 59,685 13,044 $/Mgal, 124.3 gpm, 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr

Reagent #1 (O2) 17.45 Mscf 10.6 Mscfh 76,016 1,326,487 $/Mscf, 10.6 Mscfh, 8000 hr/yr, 

Reagent #2 0 Ton 0.00 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr

SW Disposal 25.00 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273.18 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Bio Treat 5.38 Mgal 124.3 gpm 59,685 320,847 $/Mgal, 124.3 gpm, 8000 hr/yr, 

Catalyst 0 ft3 0 ft3 0 0 $/ft3, 0.0 ft3, 0, 8000 hr/yr

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Emis Rate

Factor Measure Hrs Capacity T/yr Comments/Notes

48.0 ppm 207,240 dscfm 257 Annual emission rate from hourly P to E adjusted for

Controlled Emission Rate normal hours of operation and untilzation

Perf Unit of Flow Unit of Emis Rate

Guarantee Measure Rate Measure T/yr Comments/Notes

90% Pct Red 26 Basis:8000 hr/yr, 0.0% of capcity

Emission Reduction T/yr 231

Flow acfm P in H2O Blower Eff Motor Eff kW

Blower OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 622 Estimated from Vendor Data (gpm= mscfh gas * 3)

H2O WW Disch 124 Water Makeup Rate/WW Disch = 20% of circulating water rate

LTO Electric Use 1,852 Estimated from Table 5 LoTOx Paper #147

BOC LoTox Bid July 2001

Rate scfm

Bid Basis 200,805 Design close to NSM; don't adjust cost numbers

O2 required mscf/Hr 10.6 Adj H2 Use BOC Estimate 608 scfm for 222 lb/hr NOx NSM 64.25 lb/hr

July 2001 BOC BID
 

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A-5-111 

BACT ATTACHMENT 3 

Summary of NSM Emission Testing Data 

P:\23\38\107 NSM Furnace 5 Restart\Air Permit App\Submittal\050502 to MPCA (PSD App)\Original Files\Vol I Sect 5 App A (BACT).doc 

Attachment 3, Table 1. NSM Stack Test Results

Line 5 Restart Project, Northshore Mining Company

Temp Flow Flow 

(F) (acfm) (dscfm) 

Fine Crushing PM Stack Test Data with Fabric Filter Controls 

SV 013 EU 013 Fine Crusher Line 2 Crush 7/20/04 [18] PM Dry Catch + Organic Wet Catch 80 14,433 13,600 0.22 0.96 0.0277 620.3 SV 014 EU 014 Fine Crusher Line 1 Crush 7/20/04 [18] PM Dry Catch + Organic Wet Catch - Note - EU did not meet permit 79 15,733 14,600 0.39 1.69 0.0488 574.7 

SV 017 EU 017 No. 2 Fine Crusher Stack (EP11) Crush 06/27/95 [6] PM Dry Catch + Organic Wet Catch 75 16,553 15,596 0.31 1.34 0.0385 *** N/A 

SV 017 EU 017 No. 2 Fine Crusher Stack (EP11) Crush 06/27/95 [6] PM Dry + Method 202 75 16,479 15,595 0.31 1.38 0.0397 *** N/A 

SV 017 EU 017 No. 2 Fine Crusher Stack (EP11) Crush 06/27/95 [6] PM Dry + organic wet catch 75 16,457 15,460 0.14 0.63 0.0182 *** N/A 

SV 017 EU 017 No. 2 Fine Crusher Stack (EP11) Crush 01/13/95 [7] PM 68 16,098 15,393 0.62 2.70 0.0776 *** N/A 

SV 017 EU 017 No. 2 Fine Crusher (EP11) Crush 05/25/94 [8] PM Dry catch + organic wet catch 65 16,658 15,820 0.41 1.78 0.0513 *** N/A 

SV 017 EU 017 No. 2 Fine Crusher Stack (EP11) Crush 06/27/95 [6] PM10 Dry + Method 202 76 17,214 16,155 0.35 1.53 0.0441 *** N/A 

SV 017 EU 017 No. 2 Fine Crusher Stack (EP11) Crush 06/27/95 [6] PM10 Dry + organic wet catch 76 17,208 16,206 0.14 0.61 0.0177 *** N/A 

SV 017 EU 017 No. 2 Fine Crusher Stack (EP11) Crush 06/27/95 [6] PM10 Dry + Method 202 76 16,654 15,626 0.23 1.00 0.0288 *** N/A 

Average Test Result 0.28 

Maximum Test Result 0.41 

Safety Factor 0.00 

Proposed BACT 0.39 

Indruation Hood Exhaust Stack Test Data with Wet ESP Controls. For Reference Only 

SV 113 EU 110 Furnace 12 Hood Exhaust (1203) Hood 12/20/00 [15] Natural Gas NOx 115 83,000 66,533 10.80 47.30 1.3620 219.0 

SV 111 EU 110 No. 12 Pelletizer Hood Exhaust Stack (EP101) Hood 05/24/94 [8] NOx Electronics on 2.50 10.95 0.3153 N/A SV 111 EU 110 No. 12 Pelletizer Hood Exhaust Stack (EP101) Hood 05/24/94 [8] NOx Electronics off 2.40 10.51 0.3027 N/A 

Hood Exhaust Stack Hood 01/07/92 [10] NOx 76,764 60,155 8.66 37.91 1.0916 N/A Hood Exhaust Stack Hood 01/09/92 [10] NOx 81,270 62,497 9.98 43.71 1.2586 N/A 

SV 111 EU 110 No. 12 Pelletizer Hood Exhaust Stack (EP101) Hood 05/24/94 [8] PM Dry catch + organic wet catch, electronics on 129 79,603 61,803 4.87 21.32 0.6137 N/A SV 111 EU 110 No. 12 Pelletizer Hood Exhaust Stack (EP101) Hood 05/24/94 [8] PM Dry catch only, electronics on 129 79,603 61,803 4.63 20.29 0.5843 N/A SV 111 EU 110 No. 12 Pelletizer Hood Exhaust Stack (EP101) Hood 05/24/94 [8] PM Dry catch + organic wet catch, electronics off 121 79,418 62,574 5.07 22.21 0.6394 N/A SV 111 EU 110 No. 12 Pelletizer Hood Exhaust Stack (EP101) Hood 05/24/94 [8] PM Dry catch only, electronics off 121 79,418 62,574 4.78 20.92 0.6024 N/A SV 011 EU 110 No. 1202 Line 12 Hood Exhaust Hood 04/29/04 [19] PM Dry catch + organic wet catch, electronics on 120 77,000 62,000 2.90 12.70 0.3657 

SV 011 EU 110 No. 1202 Line 12 Hood Exhaust Hood 04/29/04 [19] PM Dry catch + organic wet catch+ aq phase, electronics on 120 77,000 62,000 6.00 26.28 0.7567 

SV 011 EU 110 No. 1202 Line 12 Hood Exhaust Hood 04/29/04 [19] PM Dry catch + organic wet catch, electronics off 118 79,000 64,000 3.20 14.02 0.4036 

SV 011 EU 110 No. 1202 Line 12 Hood Exhaust Hood 04/29/04 [19] PM Dry catch + organic wet catch+ aq phase, electronics off 118 79,000 64,000 6.70 29.35 0.8449 

SV 111 EU 110 No. 12 Pelletizer Hood Exhaust Stack (EP101) Hood 05/24/94 [8] SO2 Electronics on 2.07 9.05 0.2606 N/A SV 111 EU 110 No. 12 Pelletizer Hood Exhaust Stack (EP101) Hood 05/24/94 [8] SO2 Electronics off 1.68 7.34 0.2114 N/A 

Hood Exhaust Stack Hood 01/07/92 [10] SOx 76,764 60,155 0.66 2.88 0.0828 N/A Hood Exhaust Stack Hood 01/09/92 [10] SOx 81,270 62,497 1.12 4.92 0.1417 N/A 

Indruation Furnace Waste Gas NOx Stack Test Data 

SV 262 EU 262 Furnace 6 HE/WG (602) Waste 12/20/00 [15] Natural Gas NOx 120 73,300 57,700 13.30 58.25 1.6773 120.0 

SV 263 EU 262 No. 601 Pelletizer Stack (EP97) Waste 10/10/95 [5] NOx 13.23 57.96 1.6689 *** N/A 

Average Test Result 13.23 On Per Stack Basis 

Maximum Test Result Safety Factor 15% Proposed BACT 45.7 Furnace Total (3 stacks) 

Indruation Furnace Waste Gas PM Stack Test Data with Wet ESP Controls. 

SV 104 EU 104 Furnace 11 Waste Gas (EP104) Waste 7/31/96 [4] PM Dry + organic wet catch 142 87,139 61,383 4.13 18.09 0.5208 *** N/A SV 105 EU 105 Furnace 11 Waste Gas (EP105) Waste 7/31/96 [4] PM Dry + organic wet catch 141 86,623 61,778 3.22 14.09 0.4057 *** N/A SV 114 EU 114 Furnace 12 Waste Gas (EP106) Waste 7/30/96 [4] PM Dry + organic wet catch 139 84,510 59,783 3.70 16.21 0.4666 *** N/A SV 115 EU 115 Furnace 12 Waste Gas (EP107) Waste 7/30/96 [4] PM Dry + organic wet catch 138 78,597 56,336 3.07 13.46 0.3876 *** N/A SV 263 EU 262 No. 601 Pelletizer Stack (EP97) Waste 10/10/95 [5] PM Dry + organic wet catch 137 73,289 52,802 3.74 16.40 0.4721 *** N/A SV 104 EU 104 No. 1104 Pelletizer Waste Gas Stack (EP104) Waste 01/10/95 [7] PM Dry 132 93,253 69,282 5.32 23.30 0.6710 *** N/A SV 105 EU 105 No. 1105 Pelletizer Waste Gas Stack (EP105) Waste 01/10/95 [7] PM Dry 128 94,711 71,079 6.58 28.82 0.8297 *** N/A SV 114 EU 114 No. 1204 Waste Gas Stack (EP106) Waste 01/11/95 [7] PM Dry 139 90,456 63,312 3.95 17.32 0.4986 *** N/A SV 115 EU 114 No. 1205 Waste Gas Stack (EP107) Waste 01/11/95 [7] PM Dry 139 89,678 63,868 5.22 22.86 0.6582 *** N/A SV 114 EU 114 No. 12 Pelletizer Waste Gas Stack (EP107) Waste 05/25/94 [8] PM Dry + organic wet catch 137 89,748 63,113 18.02 78.94 2.2729 *** N/A SV 114 EU 114 No. 12 Pelletizer Waste Gas Stack (EP107) Waste 05/25/94 [8] PM Dry catch only, electronics on 137 89,748 63,113 17.26 75.60 2.1767 *** N/A 

SV 114 EU 114 No. 12 Pelletizer Waste Gas Stack (EP107) Waste 05/25/94 [8] PM Dry + organic wet catch 138 89,428 61,560 19.93 87.28 2.5130 *** N/A SV 114 EU 114 No. 12 Pelletizer Waste Gas Stack (EP107) Waste 05/25/94 [8] PM Dry catch only, electronics off 138 89,428 61,560 22.20 97.22 2.7992 *** N/A SV 104 EU 104 No. 1104 Pelletizer Waste Gas Stack Waste 05/26/94 [8] PM Dry catch + organic wet catch, electronics on 144 93,066 68,002 22.20 97.22 2.7992 *** N/A SV 105 EU 104 No. 1105 Pelletizer Waste Gas Stack Waste 05/26/94 [8] PM Dry + organic wet catch 151 98,063 72,647 9.69 42.44 1.2220 *** N/A SV 105 EU 104 No. 1105 Pelletizer Waste Gas Stack Waste 04/29/04 [19] PM Dry catch + organic wet catch, electronics on 135 81,000 59,000 3.60 15.77 0.4540 *** 

SV 105 EU 104 No. 1105 Pelletizer Waste Gas Stack Waste 04/29/04 [19] PM Dry catch + organic wet catch, electronics off 135 83,000 59,000 3.30 14.45 0.4162 *** 

Average Test Result NA Not same desgn as Furnace 5 

Maximum Test Result NA Not same desgn as Furnace 5 

Safety Factor NA 

Proposed BACT 18.4 Furnace 5 Max Flow & 0.01 gr/dscf 

Indruation Furnace Waste Gas SO2 Stack Test Data with Wet ESP Controls. 

SV 263 EU 262 No. 601 Pelletizer Stack (EP97) Waste 10/10/95 [5] SO2 1.6133 7.07 0.2035 *** N/A 

SV 115 EU 114 No. 1205 Waste Gas Stack (EP107) Waste 01/11/95 [7] SO2 0.7500 3.29 0.0946 *** N/A 

SV 114 EU 114 No. 12 Pelletizer Waste Gas Stack (EP107) Waste 05/25/94 [8] SO2 Electronics on 0.8500 3.72 0.1072 *** N/A 

SV 114 EU 114 No. 12 Pelletizer Waste Gas Stack (EP107) Waste 05/25/94 [8] SO2 Dry + organic wet catch 0.6200 2.72 0.0782 *** N/A 

SV 104 EU 104 No. 1104 Pelletizer Waste Gas Stack Waste 05/26/94 [8] SO2 Electronics on 1.1500 5.04 0.1450 *** N/A 

SV 105 EU 104 No. 1105 Pelletizer Waste Gas Stack Waste 05/26/94 [8] SO2 Dry catch only, electronics on 2.4000 10.51 0.3027 *** N/A 

No. 12 Waste Gas Stack Waste 01/08/92 [10] SOx 82,613 58,708 0.5900 2.58 0.0744 *** N/A 

Average Test Result 4.78 Furnace total lb/hr 

Maximum Test Result 0.0147 lb/ton of pellets based on stack test EF, natural gas as fuel Safety Factor 7.97 Adjust emission rates for fuel oil comb 

Proposed BACT 12.75 Furnace Total (3 stacks) 

*** NSM to collect production 

(lb/to

gree

Con

(calc

Stack Test Results

Date Pollutant Comments Fuel

(if applicable)

(lb/hr) (ton/yr) (g/s)

Test Parameters Measured Emission Rate Measured T/put

(LT green 

balls/hr)

(LT 

pellets/hr) (LT ore/hr)

Type

Source Information

Emission Unit

Stack ID ID Description
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Notes:[1] "Results of the May 19-21, 1998 Trace Metals Emission Engineering Tests at the Northshore Mining Facility in Silver Bay, Minnesota", June 24, 1998, Interpoll Laboratories, Inc. Report number 8-11183M.[2] "Results of the October 23, 1997 Particulate Emission Compliance Test at the Northshore Mining Plant in Silver Bay, Minnesota", December 1, 1997, Interpoll Laboratories, Inc. Report number 7-10191.[3] "Results of the August 19, 1997 Particulate and Visible Emission Compliance Tests at the Northshore Mining Plant in Silver Bay, Minnesota", September 4, 1997, Interpoll Laboratories, Inc. Report number 7-9908.[4] "Results of the July 30 & 31, 1996 Air Emission Testing at the Northshore Mining Facility in Silver Bay, Minnesota", August 30, 1996, Interpoll Laboratories, Inc. Report number 6-8063.[5] "Results of the October 10-12, 1995 EPA-Required Emission Compliance Testing at the Northshore Mining Facility in Silver Bay, Minnesota", November 3, 1995, Interpoll Laboratories, Inc. Report number 5-6648.[6] "Results of the June 27 - 29 and July 13,1995 Air Emission Testing at the Northshore Mining Facility in Silver Bay, Minnesota", August 1, 1995, Interpoll Laboratories, Inc. Report number 5-5897.[7] "Results of the January 10 - 13, 1995 Air Emission Compliance Testing at the Northshore Mining Facility in Silver Bay, Minnesota", January 25, 1995, Interpoll Laboratories, Inc. Report number 5-4664.[8] "Results of the May 24 - 27, 1994 Air Emission Testing at the Cyprus Northshore Mining Facility in Silver Bay, Minnesota", July 6, 1994, Interpoll Laboratories, Inc. Report number 4-2971.

[9] "Results of the June 2 - 3, 1993 Particulate and PM-10 Emission Tests on the North and South Rotoclones at the Cyprus Northshore Mining Facility in Silver Bay, Minnesota", July 21, 1993, Interpoll Laboratories, Inc.  Report number 3-8983.[10] "Results of the January 7 - 9, 1992 Engineering Scrubber Performance Tests at the Cyprus Northshore Mining Facility in Silver Bay, Minnesota", Febuary 6, 1992, Interpoll Laboratories, Inc. Report number 2-3480.[11] "Results of the September 16-17, 1998 Northshore Mining Company Metals Emission Engineering Testing on the No. 12 Pelletizer Hood Exhaust and Waste Gas Exhaust" by Barr Engineering Company, Project No. 2338041TMR300.[12] The rest of the three runs reported more metal HAP in blank than in sample.[13] The result for run 1 is currently under review with the contract laboratory.[14] "Results of the November 23, 1999 Northshore Mining Company Ore Transfer Bins PM Emission Tests" by Barr Engineering Company, Project No. 2338052TAK003.[15] "Results of the December 20-21, 2000 Nitrogen Oxides Engineering Tests on the Furnace 12 Waste Gas and Hood Exhaust (1203 and 1205) and Furnace 6 hood Exhaust/Waste Gas Stack (602) at the Northshore Mining Company E.W. Davis Works Facility" by Barr

[16] "Results of the March 6, 2003 Formaldehyde Emission Testing of Furnace No. 11 Waste Gas Stack (1105) and Hood Exhaust Stack (1103) at Northshore Mining Co." by Barr Engineering Company, Project No. 2338081[17] "Results of the April 22-23, 2003 Hexavalent Chrome Emission Testing Performed on Furnace No. 11 Waste Gas Stack (105) and Hood Exhaust Stack (1103) at Northshore Mining Co." by Barr Engineering Company, Project No. 2338082[18] "Results of the July 20-22, 2004 Title V Air Emissions Performance Testing Performed at Northshore Mining Company" by Barr Engineering, Project No. 23/38-104 MTP 002Revised since 1999 DRI PSD Permit ApplicationNote: shading denotes that the test result is below the detection limit (BDL). The detection limit is reported.