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Mittal Steel BART Report 

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Table of Contents 

1. Executive Summary .............................................................................................................................iii

2. Introduction.......................................................................................................................................... 1

2.A BART Eligibility ............................................................................................................................ 3 

2.B BART Determinations .................................................................................................................... 3 

3. Streamlined BART Analysis................................................................................................................. 9

3.A Indurating Furnaces ........................................................................................................................ 9 

3.B PM-Only Taconite MACT Emission Units ...................................................................................... 9 

3.C Sources of fugitive PM that are subject to MACT standards .......................................................... 10 

3.D Non-MACT Units and Fugitive Sources (PM only) ....................................................................... 10 

3.E Other Combustion Units ............................................................................................................... 11 

3.F Visibility Impact Modeling for Negligible Impacts........................................................................ 11 

4. Baseline Conditions and Visibility Impacts for BART Eligible Units ............................................... 13

4.A MPCA Subject-to-BART Modeling .............................................................................................. 13 

4.B Facility Baseline Modeling ........................................................................................................... 14 

4.C Facility Baseline Modeling Results ............................................................................................... 14 

5. Full BART Analysis for BART Eligible Emission Units .................................................................... 18

5.A Indurating Furnace........................................................................................................................ 18 

5.A.i Sulfur Dioxide Controls ............................................................................................................ 19

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies......................................... 19 

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options........................................................... 19 

5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies .................. 25 

5.A.i.d STEP 4 – Evaluate Impacts and Document the Results ...................................................... 25 

5.A.i.e STEP 5 – Evaluate Visibility Impacts ............................................................................... 27 

5.A.ii Nitrogen Oxide Controls....................................................................................................... 28

5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies......................................... 28 

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options........................................................... 28 

5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies .................. 42 

5.A.ii.d STEP 4 – Evaluate Impacts and Document the Result........................................................ 42 

5.A.ii.e STEP 5 – Evaluate Visibility Impacts ............................................................................... 44 

6. Visibility Impacts................................................................................................................................ 48
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7. Select BART........................................................................................................................................ 49

List of Tables 

Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis ............. 12

Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data........... 16

Table 4-2 Baseline Visibility Modeling Results .................................................................................. 17

Table 5-1 Indurating Furnace SO2 Control Technology – Availability, Applicability, and 

Technical Feasibility .......................................................................................................... 24

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness ................................................. 25

Table 5-3 SO2 Control Cost Summary ................................................................................................ 26

Table 5-4 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility .......................................................................................................... 41

Table 5-5 Indurating Furnace NOx Control Technology Effectiveness................................................. 42

Table 5-6 NOx Control Cost Summary................................................................................................ 43

Table 5-7 NOx Control Technology Impacts Assessment .................................................................... 44

Table 5-8 Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates ........................... 46

Table 5-9 Post-BART NOX Modeling Scenarios - Visibility Modeling Results.................................... 47

List of Figures 

Figure 2-1 Minnesota’s BART Geography ............................................................................................. 2

List of Appendices 

Appendix A Control Cost Analysis Spreadsheets 

Appendix B Changes to MPCA BART Modeling Protocol 

Appendix C Visibility Impacts Modeling Report 

Appendix D Applicable and Available Retrofit Technologies 

Appendix E Summary of Relevant Economic Feasibility ($/ton) Control Costs 
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1. Executive Summary 

Mittal Steel USA - Minorca Mine (Mittal Steel) is located in northern Minnesota, with taconite 

mining and processing facilities in Virginia, Minnesota. This report describes the background and 

methods for the selection of the Best Available Retrofit Technology (BART) as proposed by Mittal 

Steel for the taconite processing plant located in Virginia, MN. 

Mittal Steel’s BART eligible units include one straight grate indurating furnace (EU 026) as well as 

several material handling and/or storage units for ore, product, and additives. Preliminary visibility 

modeling conducted by the Minnesota Pollution Control Agency (MPCA) found that air emissions 

from Mittal Steel’s BART-eligible emission units “cause or contribute to visibility impairment” in a 

federally protected Class I area, therefore making the facility subject-to-BART. As a subject-toBART source, the facility was required to determine the Best Available Retrofit Technology (BART) 

for each of the affected emission units. 

This report describes the methods for the selection of BART and proposes BART applicable emission 

units. US Environmental Protection Agency (U.S. EPA) Guidelines found at 40 CFR §51 Appendix 

Y and MPCA “Guidance for Facilities Conducting a BART Analysis” (Attachment 2) and 

“Suggested Format for BART Analysis” (Attachment 3) were used to determine BART. 

Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include 

a streamlined approach for BART analyses1

. The streamlined approach allows both the states and the 

facilities to focus their resources on the main contributors to visibility impairment. As described in 

section 3 of this document, the emissions from several of the sources at this facility meet the criteria 

for a streamlined analysis. 

The streamlined analysis includes the specific provision that compliance with the Taconite MACT 

(40 CFR Part 63 Subpart RRRRR) for PM emissions as equivalent to BART. This provision is 

applicable to the indurating furnace, ore crushing and handling operations, and finished pellet 

handling operations that are subject to BART. The Taconite MACT standard includes requirements 

for performance testing and continuous parametric monitoring for compliance demonstration. 

 

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After completion of the streamlined analysis, the focus of the BART analysis was the SO2 and NOx

emissions from the indurating furnace. The existing pollution control equipment on the straight grate 

indurating furnace includes a wet scrubber for each of the four exhaust stacks designed to control 

emissions of particulate matter (PM) with collateral control of sulfur dioxide (SO2). 

According to US EPA guidance, the following impacts must be considered within the process for the 

selection of BART2

: 

(a) The costs of compliance, 

(b) The energy and non-air quality environmental impacts of compliance, 

(c) Existing pollution control technology in use at the source, 

(d) The remaining useful life of the source, and 

(e) The degree of visibility improvement which may reasonably be anticipated from the use of 

BART. 

These impacts are addressed within sections 5, 6 and 7 of this document. A dispersion modeling 

sequence of CALMET, CALPUFF, and CALBART was used to assess the visibility impacts of the 

baseline emissions and after the application of candidate BART controls. Visibility impacts were 

evaluated in the selection of BART, as required in the fifth element in the U.S. EPA guidance. 

However, it is important to note that CALPUFF is a conservative model that overestimates real 

impacts. Therefore, although the CALPUFF modeling results are important to comparing control 

alternatives on a relative basis, they do not accurately predict real impacts. It is also important to 

note that the modeling for Mittal Steel was conducted based on maximum permitted limits rather than 

the maximum actual emissions. Therefore, the emissions and the associated visibility impacts are 

overestimated for this facility. 

Note that the improvements required under the Regional Haze regulations are different from the 

BART requirements. Facilities subject to BART are not required to make all of the reasonable 

progress towards improving regional haze in Class I areas. Rather, BART is but one of many 

measures which states may rely upon in making “reasonable progress” towards regional haze 

improvement goals. 

 

2

 40 CFR Part 51, Appendix Y, Subpart 1.C. 
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Based on consideration of all of the above criteria, Mittal Steel is proposing BART to be the 

following: 

(1) For the material handling and storage units subject to MACT: 

 PM limitation of 0.008 gr/dscf, Taconite MACT standards3

. 

 Compliance with this limit will be based on the performance test methods, emissions 

averaging options, and monitoring requirements of the Taconite MACT standards. 

(2) For material handling and storage units not subject to MACT (EU 018 and 019/020): 

 PM control equipment will be the existing baghouses. 

 PM limitation of 0.008 gr/dscf, which is equivalent to the Taconite MACT standards. 

 Compliance with this limit will be based on the performance test methods, emissions 

averaging options, and monitoring requirements of the Taconite MACT standards. 

(3) Fugitive Sources Subject to BART – None. 

 (4) For the indurating furnace: 

 SO2 limitation of 2.0 lbs/MMBtu when liquid fuel is being burned, which equates to 540 

lb/hr per furnace based upon a furnace heat input rating of 270 MMBtu/hr (controlled by 

the existing wet scrubbers for the furnace). 

 NOx limitation of 1,088 lb/hr from the preheat burners (controlled by existing combustion 

practices for the furnace and low-NOx burners in the preheat section). 

 PM limitation of 0.01 gr/dscf (controlled by the existing wet scrubbers, equivalent to the 

emission limits established by the taconite MACT standard).4 

The schedule for implementation of these limits is within the 5-year time-frame required for BART 

implementation.

 

3

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

Processing 

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2. Introduction 

To meet the Clean Air Act’s requirements, the U.S. Environmental Protection Agency (U.S. EPA) 

published regulations in 1999 to address visibility impairment in our nation’s largest national parks 

and wilderness (“Class I”) areas. This rule is commonly known as the “Regional Haze Rule” [64 

Fed. Reg. 35714 (July, 1999) and 70 Fed. Reg. 39104 (July 6, 2005), and] and is found in 40 CFR 

part 51, in §51.300 through §51.309. 

Within its boundary, Minnesota has two Class I areas – the Boundary Water Canoe Area Wilderness 

and Voyageurs National Park. In addition, emissions from Minnesota may contribute to visibility 

impairment in other states’ Class I areas, such as Michigan’s Isle Royale National Park and Seney 

Wilderness Area. By December 2007, MPCA must submit to U.S. EPA a Regional Haze State 

Implementation Plan (SIP) that identifies sources that cause or contribute to visibility impairment in 

these areas. The Regional Haze SIP must also include a demonstration of reasonable progress toward 

reaching the 2018 visibility goal for each of the state’s Class I areas. 

One of the provisions of the Regional Haze Rule is that certain large stationary sources that were put 

in place between 1962 and 1977 must conduct a Best Available Retrofit Technology (BART) 

analysis. The purpose of the BART analysis is to analyze available retrofit control technologies to 

determine if a technology should be installed to improve visibility in Class I areas. The chosen 

technology is referred to as the BART controls, or simply BART. The SIP must require BART on all 

BART-eligible sources and mandate a plan to achieve natural background visibility by 2064. 

Figure 2-1 illustrates the BART-eligible facilities and the two Class I areas in Minnesota. When 

reviewing Figure 2-1, it is important to note that Minnesota Steel Industries (MSI) and Mesabi 

Nugget (Nugget), which are illustrated in the figure, are not currently in operation. The SIP must 

also include milestones for establishing reasonable progress towards the visibility improvement goals 

and plans for the first five-year period. Upon submission of the Regional Haze SIP, states must make 

the requirements for BART sources federally enforceable through rules, administrative orders or 

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Figure 2-1 Minnesota’s BART Geography 

The Minnesota SIP will address the 2 PSD Class I Areas [Voyageurs National Park (VPN) and Boundary 

Waters Canoe Area (BWCA)] and BART-eligible units illustrated above.

(Source MPCA BART-Strategy October 4, 2005) 

By U.S. EPA’s definition, reasonable progress means that there is no degradation of the 20 bestvisibility days, and the 20 worst-visibility days must have no more visibility impairment as the 20 

worst days under natural conditions by 20645. Assuming a uniform rate of progress, the default glide 

path would require 1 to 2 percent improvement per year in visibility on the 20 worst days. The state 

must submit progress reports every five years to establish their advancement toward the Class I area 

natural visibility backgrounds. If a state feels it may be unable to adopt the default glide path, a 

slower rate of improvement may be proposed on the basis of cost or time required for compliance and 

non-air quality impacts. 

Note that the improvements required under the Regional Haze regulations are different from the 

BART requirements. Facilities subject to BART are not required to make all of the reasonable 

 

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progress towards improving regional haze in Class I areas. Rather, BART is but one of many 

measures which states may rely upon in making “reasonable progress” towards regional haze 

improvement goals. 

2.A BART Eligibility 

BART eligibility is established on the basis of three criteria. In order to be BART-eligible, sources 

must meet the following three conditions: 

1. Contain emission units in one or more of the 26 listed source categories under the PSD rules 

(e.g., taconite ore processing plants, fossil-fuel-fired steam electric plants larger than 250 

MMBtu/hr, fossil-fuel boilers larger than 250 MMBtu/hr, petroleum refineries, coal cleaning 

plants, sulfur recovery plants, etc.); 

2. Were in existence on August 7, 1977, but were not in operation before August 7, 1962; 

3. Have total potential emissions greater than 250 tons per year for at least one visibilityimpairing pollutant from the emission units meeting the two criteria above. 

Under the BART rules, large sources that have previously installed pollution-control equipment 

required under another standard (e.g., MACT, NSPS and BACT) are required to conduct visibility 

analyses to determine if the source is subject-to-BART. Installation of additional controls may be 

required to further reduce emissions of visibility impairing pollutants such as PM, PM10, PM2.5, SO2, 

NOx, and possibly Volatile Organic Compounds (VOCs) and ammonia. Sources built before the 

implementation of the Clean Air Act (CAA), which had previously been grandfathered, may also 

have to conduct such analyses and possibly install controls, even though they have been exempted to 

date from any other CAA requirements. 

Once BART eligibility is determined, a source must then determine if it is ‘subject-to-BART.’ A 

source is subject-to-BART if emissions ‘cause or contribute’ to visibility impairment at any Class I 

area. Visibility modeling conducted with CALPUFF or another U.S. EPA -approved visibility model 

is necessary to make a definitive visibility impairment determination (>0.5 deciviews). Sources that 

do not cause or contribute to visibility impairment are exempt from BART requirements, even if they 

are BART-eligible. 

2.B BART Determinations 

Each source that is subject to BART must determine BART on a case-by-case basis. Even if a source 

was previously part of a group BART determination, individual BART determinations must be made 
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for each source. The BART analysis takes into account six criteria and is analyzed using five steps. 

The criteria that comprise the engineering analysis include: the availability of the control technology, 

existing controls at a facility, the cost of compliance, the remaining useful life of a source, the energy 

and non-air quality environmental impacts of the technology, and the visibility impacts.6

 

The five steps of a BART analysis are: 

Step 1 - Identify all Control Technologies 

The first step in the analysis is to identify all available retrofit control technologies for 

each applicable emission unit. U.S. EPA is very specific about the criteria to be met 

for a technology to be considered available. In preambles to the interim and final rules 

U.S. EPA defines “available” as follows: 

Available retrofit technologies are those air pollution control technologies 

with a practical potential for application to the emissions unit and the 

regulated pollutant under evaluation. Air pollution control technologies can 

include a wide variety of available methods, systems, and techniques for 

control of the affected pollutant. Technologies required as BACT or LAER 

are available for BART purposes and must be included as control 

alternatives. The control alternatives can include not only existing controls 

for the source category in question, but also take into account technology 

transfer of controls that have been applied to similar source categories or gas 

streams. Technologies which have not yet been applied to (or permitted for) 

full scale operations need not be considered as available; we do not expect 

the source owner to purchase or construct a process or control device that 

has not been demonstrated in practice.7

Step 2 - Eliminate Technically Infeasible Options 

In the second step, the technical feasibility of each control option identified in step one 

is evaluated by answering three specific questions: 

1. Is the control technology “available” to the specific source which is undergoing the 

BART analysis? 

 

6

 40 CFR 51 Appendix Y 

7

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The U.S. EPA states that a control technique is considered “available” to a specific 

source “if it has reached the stage of licensing and commercial availability.” 

However, the U.S. EPA further states that they “do not expect a source owner to 

conduct extended trials to learn how to apply a technology on a totally new and 

dissimilar source type.” 8

2. Is the control technology an “applicable technology” for the specific source which 

is undergoing the BART analysis? 

In general, a commercially available control technology, as defined in question 1, 

“will be presumed applicable if it has been used on the same or a similar source 

type.” If a control technology has not been demonstrated on a same or a similar 

source type, the technical feasibility is determined by “examining the physical and 

chemical characteristics of the pollutant-bearing stream and comparing them to the 

gas stream characteristics of the source types to which the technology has been 

applied previously.”9

 

3. Are there source-specific issues/conditions that would make the control technology 

not technically feasible? 

This question addresses specific circumstances that “preclude its application to a 

particular emission unit.” This demonstration typically includes an “evaluation of 

the characteristics of the pollutant-bearing gas stream and the capabilities of the 

technology.” This also involves the identification of “un-resolvable technical 

difficulties.” However, when the technical difficulties are merely a matter of 

increased cost, the technology should be considered technically feasible and the 

technological difficulty evaluated as part of the economic analysis.10

 

It is also important to note that vendor guarantees can provide an indication of 

technical feasibility but the U.S. EPA does not “consider a vendor guarantee alone 

to be sufficient justification that a control option will work.” Conversely, the U.S. 

EPA does not consider the lack of a vender guarantee as “sufficient justification 

 

8

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that a control option or emission limit is technically infeasible.” In general, the 

decisions on technical feasibility should be based on a combination of the 

evaluation of the chemical and engineering analysis and the information from 

vendor guarantees.11

Step 3 - Evaluate Control Effectiveness 

In step three, the remaining controls are ranked based on the control efficiency at the 

expected emission rate (post-BART) as compared to the emission rate before addition 

of controls (pre-BART) for the pollutant of concern. 

Step 4 - Evaluate Impacts and Document Results 

In the fourth step, an engineering analysis documents the impacts of each remaining 

control technology option. The economic analysis compares dollar per ton of pollutant 

removed for each technology. In addition it includes an incremental dollar per ton cost 

analysis to illustrate the economic effectiveness of one technology in relation to the 

others. Finally, step four includes an assessment of energy impacts and other non-air 

quality environmental impacts. 

Economic impacts were analyzed using the procedures found in the U.S. EPA Air 

Pollution Control Cost Manual – Sixth Edition (EPA 452/B-02-001). Equipment cost 

estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA’s Air 

Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model 

version 7.5 were used. Vendor cost estimates for this project were used when 

applicable. The source of the control equipment cost data are noted in each of the 

control cost analysis worksheets as found in Appendix A. 

Step 5 - Evaluate Visibility Impacts 

The fifth step requires a modeling analysis conducted with U.S. EPA -approved models 

such as CALPUFF. The modeling protocol12, including receptor grid, meteorological 

data, and other factors used for this part of the analysis were provided by the Minnesota 

Pollution Control Agency. The model outputs, including the 98th percentile deciview 

(dV) value and the number of days the facility contributes more than a 0.5 dV of 

 

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12 MPCA. October 10, 2005. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to 

BART in the State of Minnesota. 
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visibility impairment at each of the Class I areas, are used to establish the degree of 

improvement that can be reasonably attributed to each technology. 

The final step in the BART analysis is to select the “best alternative” using the results of steps 1 

through 5. When selecting the “best alternative,” the U.S. EPA and MPCA guidance states that the 

“affordability” of the controls should be considered, and specifically states: 

1. Even if the control technology is cost effective, there may be cases where the installation 

of controls would affect the viability of plant operations. 

2. There may be unusual circumstances that justify taking into consideration the conditions 

of the plant and the economic effects requiring the use of a given control technology. 

These effects would include effects on product prices, the market share, and profitability 

of the source. Where there are such unusual circumstances that are judged to affect 

plant operations, you may take into consideration the conditions of the plant and the 

economic effects of requiring the use of a control technology. Where these effects are 

judged to have severe impacts on plant operations you may consider them in the selection 

process, but you may wish to provide an economic analysis that demonstrates, in 

sufficient detail for public review, the specific economic effects, parameters, and 

reasoning. (We recognize that this review process must preserve the confidentiality of 

sensitive business information). Any analysis may also consider whether competing 

plants in the same industry have been required to install BART controls if this 

information is available.13

To complete the BART process, the analysis must “establish enforceable emission limits that reflect 

the BART requirements and requires compliance within a reasonable period of time.”14 Those limits 

must be developed for inclusion in the state implementation plan (SIP) that is due to U.S. EPA in 

December of 2007. In addition, the analysis must include requirements that the source “employ 

techniques that ensure compliance on a continuous basis”15 which could include the incorporation of 

other regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR 

64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If 

technological or economic limitations make measurement methodology for an emission unit 

 

13 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 20. 

14 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 

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infeasible, the BART limit can “instead prescribe a design, equipment, work practice, operation 

standard, or combination of these types of standards.”16

Compliance with the BART emission limits will be required within 5 years of U.S. EPA approval of 

the Minnesota SIP. 

 

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3. Streamlined BART Analysis 

Within the preamble to the final BART rule, U.S. EPA explicitly encouraged states to include a 

streamlined approach for BART analyses.17 The streamlined approach will allow both states and the 

facilities to focus their resources on the main contributors to visibility impairment. This section of 

the report follows the MPCA-approved streamlined BART analysis for taconite facilities and 

presents the results of the streamlined approach in Table 3-1. 

3.A Indurating Furnaces 

The indurating furnace is a source of three visibility impairing pollutants: NOx, SO2, and PM. The 

indurating furnace is subject to the taconite MACT standard [40 CFR Part 63 Subpart RRRRRNESHAPS: Taconite Iron Ore Processing] for the PM emissions. MPCA’s guidance for conducting a 

BART review states that “MPCA will rely on MACT standards to represent BART level of control 

for those visibility impairing pollutants addressed by the MACT standard unless there are new 

technologies subsequent to the MACT standard, which would lead to cost-effective increases in the 

level of control.”18 Since the MACT standard was established very recently and becomes effective in 

2006, the technology analysis is up-to-date. As a result, BART will be presumed to be equivalent to 

MACT for PM and no further analysis will be required to establish BART for PM for this source. 

A full BART analysis will be conducted for NOx and SO2 where applicable. 

3.B PM-Only Taconite MACT Emission Units 

In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions from 

Ore Crushing and Handling operations, Pellet Coolers, and Finished Pellet Handling operations. 

These sources operate near ambient temperature, only emit PM, and do not emit NOx or SO2. The 

Ore Crushing and Handling sources and the Finished Pellet Handling sources operate with control 

equipment to meet the applicable MACT limits (0.008 gr/dscf for existing sources and 0.005 gr/dscf 

for new sources). The Pellet Cooler sources are excluded from additional control under the MACT 

standard due to the large size of the particles and the relatively low concentration of particle 

emissions.19 Therefore, the emissions from the pellet coolers are considered to have a negligible 

 

17 Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116 

18 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 2. 

19 Federal Register 67, no. 143 (December 18, 2002): 77570 
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impact on visibility impairment, and no control requirements under the MACT standard is consistent 

with the intention of the BART analysis. 

Since the MACT standard was established recently and will become effective in 2006, the technology 

analysis is up-to-date. Again, for these units subject to a MACT standard, BART will be presumed 

to be equivalent to MACT according to MPCA guidance. 

No further analysis will be required to establish BART for these sources. 

3.C Sources of fugitive PM that are subject to MACT standards 

The taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from nonMACT sources are addressed in section 3.D). No equipment that emits fugitive PM has been 

identified by the MPCA at Mittal Steel as potentially BART-eligible equipment, so these sources are 

not required to be addressed. Therefore, no analysis is required to establish BART for fugitive PM 

sources. 

3.D Non-MACT Units and Fugitive Sources (PM only) 

A few sources of PM emissions and sources of fugitive PM are not subject to a MACT standard. At 

the Mittal Steel facility, two bentonite sources fall into this category: Binder Transfer to Storage Silo 

(EU 018) and Binder Shift Bins and Blending (EU 019/EU 020). There are no fugitive sources at the 

facility which have been identified as subject-to-BART. 

Considering all PM emissions which are subject to the BART standard, the PM emissions from the 

bentonite storage and handling units represent less than 2.5% of facility subject-to-BART PM 

emissions. 

These emission units are controlled by baghouses, which is a technology that achieves high levels of 

control for PM. Since these units already have control equipment for PM emissions, and since the 

PM emissions from these sources are small relative to the total PM emissions that are subject to the 

BART standard, additional control of these sources can be presumed to have minimal impact on 

visibility improvement in Class I areas. For these controlled sources, existing controls will be 

considered BART consistent with direction from MPCA in the May 18, 2006 meeting. 

No further analysis is required to establish BART for these non-MACT PM-only sources. 
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3.E Other Combustion Units 

There were no other combustion units identified as subject-to-BART at the Mittal Steel facility. 

Therefore, no analysis is required for “other combustion units.” 

3.F Visibility Impact Modeling for Negligible Impacts 

There were no sources requiring visibility impacts modeling for negligible impacts at the Mittal Steel 

facility. Therefore, no visibility impacts analysis was required for modeling for negligible impacts. 
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Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysi

Emission Unit # Emission Unit Description

NOx Max. 24-hr 

Actual

Emissions (lb/day)

SO2 Max. 24-hr 

Actual

Emissions 

(lb/day)

PM10 Max. 24-

hr Actual

Emissions 

(lb/day)

MACT

PM Emission 

Limit*

(g/dscf)

Stack 

Number 

3A. Indurating Furnaces

EU 026 Indurating Machine --- --- 51.4 0.01 014 BAR

EU 026 Indurating Machine --- --- 50.0 0.01 015 BAR

EU 026 Indurating Machine --- --- 48.9 0.01 016 BAR

EU 026 Indurating Machine --- --- 54.8 0.01 017 BAR

3.B. PM-Only Taconite MACT Emission Units

EU 001 Primary Crusher --- --- 8.6 0.008 001 

EU 003 Drop Onto Coarse Ore Pile Conveyor --- --- 8.6 0.008 003 

EU 003/004/005 Secondary Crushing --- --- 14.5 0.008 004 EU 003/004/005 Secondary Crushing --- --- 14.5 0.008 005 

EU 007/008/009/010 Tertiary Crushing --- --- 14.5 0.008 006 EU 007/008/009/010 Tertiary Crushing --- --- 16.5 0.008 007 

EU 006 Outside Ore Transfer --- --- 16.7 0.008 009 

EU 011/012 Fine Ore Drop --- --- 16.7 0.008 010 

EU 013/014/015/016/017 Fine Ore Drop, rod mill material handling --- --- 14.5 0.008 011 

EU 018 Machine Discharge and Conveyor to Spl Bin --- --- 26.9 0.008 018 

EU 021/022/023 Pellet Hearth Layer Conveyor, Bin, and Grate Feed --- --- 7.4 0.008 019 

EU 024/025 Pellet Hearth Layer Screen & Conveyor to HL Bin --- --- 13.2 0.008 020 EU 029/030 Drop Into Spl Bin and Into Prod Spl Bin Conv --- --- 12.3 0.008 021 

EU 032 Drop onto P3 Pellet Pile Underfeed Conveyor --- --- 9.9 0.008 022 

EU 031 Drop in P1-P2 Transfer House --- --- 10.0 0.008 024 

3.C. Sources of fugitive PM that are subject to MACT standards 

None --- --- --- --- --- --- 

3.D. Non-MACT Units and Fugitive Sources (PM only)

EU 018 Binder Transer to Storage Silo --- --- 2.1 --- 012 

EU 019/020 Binder Shift Bins and Blending --- --- 7.0 --- 013 

3.E. Other Combustion Units 

None --- --- --- --- --- --- 

* The taconite MACT emission limits are based on EPA Method 5 and include the applicable averaging and grouping provisions, as presented in the regulation.
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4. Baseline Conditions and Visibility Impacts for 

BART Eligible Units 

As indicated in U.S. EPA’s final BART guidance20, one of the factors to consider when determining 

BART for an individual source is the degree of visibility improvement resulting from the retrofit 

technology. The visibility impacts for this facility were determined using CALPUFF, an U.S. EPA 

approved model. The CALPUFF program models how a pollutant contributes to visibility 

impairment with consideration for the background atmospheric ammonia, ozone and meteorological 

data. Additionally, the interactions between the visibility impairing pollutants NOx, SO2, PM2.5 and 

PM10 can play a large part in predicting impairment. It is therefore important to take a multi-pollutant 

approach when assessing visibility impacts. 

However, it is important to note that CALPUFF is a conservative model that overestimates real 

impacts. Therefore, although the CALPUFF modeling results are important to comparing control 

alternatives on a relative basis, they do not accurately predict real impacts. 

In order to determine the visibility improvement resulting from the retrofit technology, the source 

must first be modeled at baseline conditions. Per MPCA guidance, the baseline, or pre-BART 

conditions, shall represent the average emission rate in units of pounds per hour (lbs/hr) and reflect 

the maximum 24-hour actual emissions.21

 

4.A MPCA Subject-to-BART Modeling 

In order to determine which sources are “Subject-to-BART” in the state of Minnesota, the MPCA 

completed modeling of the BART-eligible emission units at various facilities in Minnesota in 

accordance with the Regional Haze rule. The modeling by MPCA was conducted using CALPUFF, 

as detailed in the “Best Available Retrofit Technology (BART) Modeling Protocol to Determine 

Sources Subject-to-BART in the State of Minnesota,” finalized in March 2006. The modeling by 

MPCA was conducted using emission rate information submitted by the facility. The emissions were 

reported in units of pounds per hour (lbs/hr) and were intended to reflect the maximum actual 

emissions during a 24-hour period under steady-state operating conditions during periods of high 

capacity utilization. The results of the modeling were presented in the document titled “Results of 

 

20 Federal Register 70, no. 128 (July 6, 2005): 39106. 

21 MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources 

Subject-to-BART in the State of Minnesota. Page 8. 
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Best Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the 

State of Minnesota ,” finalized in March 2006. The modeling conducted by MPCA demonstrated that 

this facility is subject-to-BART. 

4.B Facility Baseline Modeling 

Prior to re-creating the MPCA visibility impairment model, the modeling protocol was re-revaluated. 

On behalf of Mittal Steel and the other Minnesota taconite facilities, Barr Engineering proposed 

changes to the modeling protocol. The changes, as submitted to MPCA on May 16, 2006 are 

presented in Appendix B. The MPCA has given verbal approval to the proposed changes to the 

modeling protocol. 

In addition, the maximum 24-hour emission rates were re-evaluated and adjusted, as appropriate, to 

confirm that the emission rates represent the maximum steady-state operating conditions during 

periods of high capacity utilization. In the BART questionnaire, the 24-hour maximum NOx

emissions were reported as 272 lb/hr per stack which is equivalent to the permit limit of 1,088 lbs/hr. 

However, the equal distribution of NOx emissions to each stack does not reflect the actual 

distribution. Based on 2005 stack test data, the percent of total NOx emitting from each stack was 

calculated, and this distribution, along with the permit limit of 1,088 lb/hr, was used to determine the 

maximum 24-hour NOx emissions of each stack. No changes were made to the maximum 24-hour 

particulate matter or SO2 emissions. 

It is also important to note that the modeling for Mittal Steel was conducted based on maximum 

permitted limits rather than the maximum actual emissions. Therefore, the emissions and the 

associated visibility impacts are over estimated for this facility. 

The facility baseline data reflecting these changes is summarized in the Table 4-1. The full modeling 

analysis is presented in Appendix C. 

4.C Facility Baseline Modeling Results 

The Minnesota BART modeling protocol22 describes the functions of the POSTUTIL and CALBART 

post processing elements. The CALBART output files provide the following two methods to assess 

the expected post-BART visibility improvement: 

 

22 MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources 

Subject-to-BART in the State of Minnesota. Page 8. 
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• 98th Percentile: As defined by federal guidance and as stated in the MPCA’s document which 

identifies the Minnesota facilities that are subject to BART23, a source "contributes to 

visibility impairment” if the 98th percentile of any year’s modeling results (i.e. 7th highest 

day) meets or exceeds the threshold of five-tenths (0.5) of a deciview (dV) at a Federally 

protected Class I area receptor. 

• Number of Days Exceeding 0.5 dV: The severity of the visibility impairment contribution, or 

reasonably attributed visibility impairment, can be gauged by assessing the number of days 

on which a source exceeds a visibility impairment threshold of 0.5 dV. 

A summary of the baseline visibility modeling is presented in Table 4-2. As illustrated in the table, 

this facility is considered to contribute to visibility impairment in Class I areas because the modeled 

98th percentile of the baseline conditions exceeds the threshold of 0.5 dV. The results of this 

modeling are also utilized in the post-BART modeling analysis in section 6 of this document. 

The full modeling analysis is presented in Appendix C. 

 

23 MPCA. March 2006. Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources 

Subject-to-BART in the State of Minnesota. 
Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data 

EU # EU Description

SO2 Maximum 

24-hr Emission 

Rate (lbs/day)

NOx Maximum 

24-hr Emission 

Rate (lbs/day)

PM2.5 Maximum 

24-hr Emission 

Rate (lbs/day)

PM10 Maximum 

24-hr Emission 

Rate (lbs/day) SV #

Stack 

Easting (utm)

Stack 

Northing 

(utm)

Height of 

Opening 

from 

Ground (ft)

Base 

Elevation of 

Ground (ft)

Stack length, 

width, or 

Diameter (ft)

Flow Rate 

at exit 

(acfm)

Exit 

Temp (°F)

Basis for SO2 24-

hour Actual 

Emissions

Basis fo

hour 

Emi

EU 001 Primary Crusher --- --- --- 8.63 SV 001 535972.61 5267596.97 41.5 1,657 2.00 12,013 65 n/a n

EU 003 Drop Onto Coarse Ore Pile Conveyor --- --- --- 8.63 SV 003 535972.61 5267596.97 10.0 1,620 3.51 26,159 65 n/a n

EU 

003/004/0

05

Secondary Crushing --- --- --- 14.47 SV 004 535972.61 5267596.97 10.0 1,620 3.51 26,159 65 n/a n

EU 

003/004/0

05

Secondary Crushing --- --- --- 14.47 SV 005 535972.61 5267596.97 10.0 1,620 3.51 26,159 65 n/a n

EU 

007/008/0

09/010

Tertiary Crushing --- --- --- 14.47 SV 006 535972.61 5267596.97 10.0 1,620 3.51 26,159 65 n/a n

EU 

007/008/0

09/010

Tertiary Crushing --- --- --- 16.48 SV 007 535972.61 5267596.97 10.0 1,620 3.51 26,159 65 n/a n

EU 006 Outside Ore Transfer --- --- --- 16.74 SV 009 535972.61 5267596.97 10.0 1,620 3.51 26,159 65 n/a n

EU 

011/012 Fine Ore Drop --- --- --- 16.74 SV 010 535972.61 5267596.97 10.0 1,620 3.51 26,159 65 n/a n

EU 

013/014/015/016/01

7

Fine Ore Drop, rod mill material handling --- --- --- 14.47 SV 011 535972.61 5267596.97 23.2 1,685 2.99 25,756 65 n/a n

EU 018 Binder Transer to Storage Silo --- --- --- 2.14 SV 012 535972.61 5267596.97 56.0 1,685 1.41 8,637 65 n/a n

EU 

019/020 Binder Shift Bins and Blending --- --- --- 6.99 SV 013 535972.61 5267596.97 56.0 1,685 1.41 8,637 65 n/a n

EU 026 Indurating Machine 3000 3731 --- 51.37 SV 014 535972.61 5267596.97 136.0 1,605 8.75 205478 124

Based on engineering 

estimate of 500 lbs/hr 

for the furnace, which 

was equally divided 

between the four 

stacks

Emission

PTE/Per

distribute

stacks bas

percenta

stack 

EU 026 Indurating Machine 3000 4800 --- 50.00 SV 015 535972.61 5267596.97 136.0 1,605 8.75 205478 124

Based on engineering 

estimate of 500 lbs/hr 

for the furnace, which 

was equally divided 

between the four 

stacks

Emission

PTE/Per

distribute

stacks bas

percenta

stack 

EU 026 Indurating Machine 3000 7398 --- 48.86 SV 016 535972.61 5267596.97 136.0 1,605 8.75 205478 124

Based on engineering 

estimate of 500 lbs/hr 

for the furnace, which 

was equally divided 

between the four 

stacks

Emission

PTE/Per

distribute

stacks bas

percenta

stack 

EU 026 Indurating Machine 3000 10183 --- 54.79 SV 017 535972.61 5267596.97 136.0 1,605 8.75 205478 124

Based on engineering 

estimate of 500 lbs/hr 

for the furnace, which 

was equally divided 

between the four 

stacks

Emission

PTE/Per

distribute

stacks bas

percenta

stack 

EU 018 Machine Discharge and Conveyor to Spl Bin --- --- --- 26.94 SV 018 535972.61 5267596.97 54.0 1,651 4.99 63,669 65 n/a n

EU 

021/022/0

23

Pellet Hearth Layer Conveyor, Bin, and 

Grate Feed --- --- --- 7.42 SV 019 535972.61 5267596.97 71.0 1,670 1.84 9,576 65 n/a n

EU 

024/025

Pellet Hearth Layer Screen & Conveyor to 

HL Bin --- --- --- 13.24 SV 020 535972.61 5267596.97 58.0 1,647 2.82 20,123 65 n/a n

EU 

029/030

Drop Into Spl Bin and Into Prod Spl Bin 

Conv --- --- --- 12.33 SV 021 535972.61 5267596.97 23.0 1,653 2.66 20,057 65 n/a n

EU 032 Drop onto P3 Pellet Pile Underfeed Conveyor --- --- --- 9.93 SV 022 535972.61 5267596.97 48.0 1,595 3.90 14,540 65 n/a n

EU 031 Drop in P1-P2 Transfer House --- --- --- 10.02 SV 024 535972.61 5267596.97 138.0 1,568 2.43 15,100 65 n/a n
Table 4-2 Baseline Visibility Modeling Results

2002 2003 2004 

Modeling 

Scenario

Operating 

Conditions

Class I 

Area with 

Greatest 

Impact

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

P

0 Baseline BWCA 2.285 97 2.457 90 2.586 70 
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5. Full BART Analysis for BART Eligible Emission 

Units 

As presented in section 3 and Table 3-1, the only source at the Mittal Steel facility that requires a full 

BART analysis is the indurating furnace (EU 026). The BART analysis is required for SO2 and NOx. 

5.A Indurating Furnace 

“Soft” or “green” pellets are oxidized and heat-hardened in the induration furnace. The induration 

process involves pellet pre-heating, drying, hardening, oxidation and cooling. 

Mittal Steel uses a straight grate furnace, in which pellets move through the entire furnace on a 

traveling grate. 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. Fuel 

combustion in the induration furnace is carried out at 300% to 400% excess air to provide sufficient 

oxygen for pellet oxidation. 

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, the induration furnace has been designed to recover 

as much heat as possible using hot exhaust gases to heat up incoming pellets. Pellet drying and 

preheat zones are heated with the hot gases generated in the pellet hardening/oxidation section and 

the pellet cooler sections. Each of these sections is designed to maximize heat recovery within 

process constraints. The pellet coolers are also used to preheat combustion air so more of the fuel’s 

energy to be directed to the process instead of heating ambient air to combustion temperatures. 

Mittal Steel has one straight grate furnace which is permitted to burn natural gas and fuel oil. 

Furnace emissions are controlled with 4 wet scrubbers (CE 014, 015, 016, and 017) and are emitted 

through four stacks (SV 014, 015, 016, and 017). The wet scrubbers are designed to remove PM and 

would be considered high efficiency PM wet scrubbers. SO2 reductions also occur within the 

existing wet scrubbers; they are considered low efficiency SO2 scrubbers and will be evaluated as 

such within this BART analysis. NOx is controlled by low-NOx burners in the preheat section which 

were installed as BACT in 1988, through existing combustion practices and by minimizing energy 

use. 
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5.A.i Sulfur Dioxide Controls 

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies 

Step 1 identifies a comprehensive list of all potential retrofit control technologies that were 

evaluated. The comprehensive list is presented in Appendix D. Many emerging technologies were 

identified that are not currently commercially available. A preliminary list of technologies was 

submitted to MPCA on May 9 with the status of the technology as it was understood at that time. In 

regards to the availability of the technology with respect to Step 1 of the BART analysis, the list has 

not changed from the information submitted at that time. Appendix D presents the current status of 

the availability and applicability of each technology. 

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options 

Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As 

stated in section 2.B of this document, the technical feasibility of each option is determined by 

answering three specific questions: 

1. Is the control technology “available” to the specific source which is undergoing the 

BART analysis? 

2. Is the control technology an “applicable technology” for the specific source which 

is undergoing the BART analysis? 

3. Are there source-specific issues/conditions that would make the control technology 

not technically feasible? 

A preliminary list of technologies was submitted to MPCA on May 9, 2006 with the status of the 

technology as it was understood at that time. As work on this evaluation progressed, additional 

information became apparent regarding the limited scope and scale of some of the technology 

applications. Appendix D presents the current status of the availability and applicability of each 

technology. 

The following section describes retrofit SO2 control technologies that were identified as available and 

applicable in the May 9 submittal and discusses aspects of those technologies that determine whether 

or not the technology is technically feasible for the indurating furnace. 
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Wet Walled Electrostatic Precipitator (WWESP) 

An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the 

flue gas stream. The suspended particles are given an electrical charge by passing through a high 

voltage 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. 

A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry 

ESP and uses a water spray to remove particulate matter from the collection plates. For SO2 removal, 

caustic is added to the water spray system, allowing the WWESP spray system to function as an SO2

absorber. 

The SO2 control efficiency for a WWESP is dependent upon various process specific variables, such 

as SO2 flue gas concentration, fuel used, and ore composition. Since Mittal Steel currently employs a 

low efficiency SO2 wet scrubber. The addition of a WWESP would act as a polishing scrubber and 

would experience reduced control efficiency due to lower SO2 inlet concentrations. A control 

efficiency as a polishing WWESP ranges from 30-80% dependent upon the process specific operating 

parameters. 

Based on the definitions contained within this report, a WWESP is considered an available 

technology for SO2 reduction for this BART analysis. The technology is commercially available and 

has been demonstrated to be effective for SO2 removal on indurating furnaces. 

Wet Scrubbing (High and Low Efficiency) 

Wet scrubbing, when applied to remove SO2, is generally termed flue-gas desulfurization (FGD). 

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

liquid, to remove SO2 in the waste gas. Crushed limestone, lime, or caustic are used as scrubbing 

agents. Most SO2 wet scrubbers recirculate the scrubbing solution, which minimizes the wastewater 

discharge flow. However, higher concentrations of solids exist within the recirculated wastewater. 

For a wet scrubber to be considered a high efficiency SO2 wet scrubber, the scrubber would require 

designs for removal efficiency up to 95% SO2. Typical high efficiency SO2 wet scrubbers are packedbed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO2 wet scrubber can 

have a control efficiency of 30% or lower. A low efficiency SO2 could be a venturi rod scrubber 

design using water as a scrubbing solvent. Venturi rod scrubbers, which are frequently used for PM 
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control at taconite facilities, will also remove some of the SO2 from the flue gas as collateral 

emission reduction. 

Limestone scrubbing introduces limestone slurry with the water in the scrubber. The sulfur dioxide is 

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

reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O 

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is 

used as the reagent than limestone. The reactions for lime scrubbing are as follows: 

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

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

When caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are as 

follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Caustic scrubbing produces a liquid waste, and requires less equipment as compared to lime or 

limestone scrubbers. If lime or limestone is used as the reagent for SO2 removal, additional 

equipment will be 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 on coal-fired utility boilers with low 

excess air is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency scrubbers. 

The highest control efficiencies can be achieved when SO2 concentrations are the highest. Unlike 

coal-fired boilers, indurating furnaces operate with maximum excess air to enable proper oxidation of 

the pellet. The excess air dilutes the SO2 concentration and creates higher flow rates to control. 

Additionally, the varying sulfur concentration within the ore causes fluctuations of the SO2

concentrations in the exhaust gas stream. This could also impact the SO2 control efficiency of the 

wet scrubber. 
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As stated in the beginning of this section, wet scrubbers are currently in place on the furnace 

exhausts and are believed to remove 15% to 30% of the SO2 in the exhaust based on Barr’s 

experience and testing which has been completed. Taking into consideration the removal of SO2

from the low-efficiency primary PM scrubber as well as a high efficiency SO2 polishing wet 

scrubber, an overall efficiency of the control train would then be 80%. 

In theory, the SO2 removal efficiency of the existing scrubbers could be improved through the 

additions of caustic, lime, or limestone in the scrubber water to raise the pH. The existing scrubber 

currently operates at a neutral pH. However, the scrubbers, piping, pumps and water tanks were not 

designed to operate at a higher pH so corrosion of the system would be a concern. In addition, the 

addition of the solution would create additional solids in the scrubber recirculation system which 

would require an increased blowdown rate and therefore an increased make-up water rate. However, 

the water balance at the facility is at maximum usage so that the additional make-up water would not 

be available. Based on these concerns, the improvement of SO2 removal efficiency of the existing 

scrubbers is not a practical solution and is not considered further in this report. 

Based on the information contained within this report, a wet scrubber is considered an available 

technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Lime/limestone 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. Further SO2

removal occurs as the flue gas flows through the filter cake on the bags. The normal SO2 control 

efficiency range for dry SO2 scrubbers is 70% to 90 % for coal fired utility boilers. 

Induration waste gas streams are high in water content and are exhausted at or near their dew points. 

Gases leaving the induration furnace are currently treated for removal of particulate matter using a 

wet scrubber or a wet walled ESP. The exhaust temperature is typically in the range of 100 °F to 150 

°F and is saturated with water. For comparison, a utility boiler exhaust operates at 350 °F or higher 

and is not saturated with water. Under induration furnace waste gas conditions, the baghouse filter 

cake would become saturated with moisture and plug both the filters and the dust removal system. 

Although this may be an available and applicable control option, it is not technically feasible due to 

the high moisture content and will not be further evaluated in this report. 
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Spray Dryer Absorption (SDA) 

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

absorbed by the slurry, forming CaSO3/CaSO4. 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. When used to specifically control SO2, the term flue-gas 

desulfurization (FGD) may also be used. 

Under induration furnace waste gas conditions, the baghouse filter cake would become saturated with 

moisture and plug both the filters and the dust removal system. In addition, because of the moisture 

in the exhaust, the lime slurry would not dry properly and it would plug up the dust collection 

system. Similarly to the dry sorbent injection control option, this is an available and applicable 

control option, but is not technically feasible due to the high moisture content. This option will not 

be further evaluated in this report. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption, 

which results in lower operating costs. Typically reduced fuel usage translates into reduced air 

emissions. An example of an energy efficiency project could be to improve the heat distribution and 

flow of air in the furnace which would reduce the fuel usage. Each project is very dependent upon 

the fuel usage, process equipment, type of product and many other variables. 

Due to the increased price of fuel, Mittal Steel has already implemented energy efficiency projects. 

Each project carries its own fuel usage reductions and, potentially, corresponding emission 

reductions. It would be impossible to assign a general potential emission reduction for the energy 

efficient category. Due to the uncertainty and generalization of this category, this will not be further 

evaluated in this report. However, it should be noted that Mittal Steel will continue to evaluate and 

implement energy efficiency projects as they arise 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has pushed companies 

to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To 

achieve reduction of SO2 emissions through alternative fuel usage, the source must be currently 

burning large quantities of high-sulfur fuels. Since Mittal Steel’s primary fuel source is natural gas 

which is low in sulfur content, this option is not applicable for SO2 reductions at this facility. 
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It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.24 

However, Mittal Steel will continue to evaluate and implement alternate fuel usage as the feasibility 

arises. 

Step 2 Conclusion 

Based upon the determination within Step 2, the remaining SO2 control technologies that are 

available and applicable to the indurating furnace process are identified in Table 5-1. The technical 

feasibility as determined in Step 2 is also included in Table 5-1.

Table 5-1 Indurating Furnace SO2 Control Technology – Availability, Applicability, and 

Technical Feasibility 

Step 1 Step 2 

SO2 Pollution Control 

Technology 

Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source? 

Wet Walled Electrostatic 

Precipitator (WWESP) Y Y Y Y 

Secondary Wet Scrubber Y Y Y Y 

Modifications to Existing Wet 

Scrubbing (Low Efficiency) Y Y N N 

Dry Sorbent Injection Y Y Y N 

Spray Dry Absorption Y Y Y N 

Energy Efficiency Projects Y Y Y N 

Alternative Fuels Y Y Y 

N 

(not required 

by BART) 

 

24 Federal Register 70, no. 128 (July 6, 2005): 39164
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5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-2 describes the expected control efficiency from each of the remaining feasible control 

options. WWESP and wet scrubbing control options listed in Table 5-2 would be considered a 

polishing scrubber since a wet scrubber currently exists. 

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Wet Walled Electrostatic Precipitator (WWESP) 80% 

Secondary Wet Scrubber 60% 

5.A.i.d STEP 4 – Evaluate Impacts and Document the Results 

As illustrated in Table 5-2 above, the technically feasible controls remaining provide varying levels 

of emission reduction. Therefore, it is necessary to consider the economic, energy, and 

environmental impacts to better differentiate as presented below. 

Economic Impacts 

Table 5-3 details the expected costs associated with installation of a secondary wet scrubber or a wet 

walled electrostatic precipitator (WWESP) after the existing scrubber on each stack. Equipment 

design was based on the maximum 24-hour emissions, vendor estimates, and U.S. EPA cost models. 

Capital costs were based on recent vendor quotations. The cost for that unit was scaled to each 

stack’s flow rate using the 6/10 power law as shown in the following equation: 

 Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6

Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. 

EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours 

per year. Operating costs of consumable materials, such as electricity, water, and chemicals were 

established based on the U.S. EPA control cost manual25 and engineering experience, and were 

adjusted for the specific flow rates and pollutant concentrations. 

 

25 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 
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Table 5-3 SO2 Control Cost Summary 

Control 

Technology

Installed Capital Cost 

(MM$)

Operating Cost 

(MM$/yr)

Annualized 

Pollution 

Control Cost 

($/ton)

SV 014 $22,809,844 $4,184,373 $116,801

SV 015 $22,809,844 $4,184,373 $116,801

SV 016 $22,809,844 $4,184,373 $116,801

SV 017 $22,809,844 $4,184,373 $116,801

SV 014 $16,454,216 $2,229,797 $82,989

SV 015 $16,454,216 $2,229,797 $82,989

SV 016 $16,454,216 $2,229,797 $82,989

SV 017 $16,454,216 $2,229,797 $82,989

Wet Walled Electrostatic Precipitator (WWESP)

Secondary Wet Scrubber

Due to space considerations, 60%26 of the total capital investment was originally included in the costs 

to account for a retrofit installation. After discussions with facility staff and/or management, it was 

determined the space surrounding the furnaces is congested and the area surrounding the building 

supports vehicle traffic to transport materials to and from the building and maintenance access to the 

large equipment. Additionally, the structural design of the existing building would not support 

additional equipment, such as an SO2 scrubber or WWESP, on the roof. Therefore, the cost estimates 

provide for additional site-work and construction costs to accommodate the new equipment within 

the facility. A site-specific estimate for site work, foundations, and structural steel was added to 

arrive at the total retrofit installed cost of the control technology. The site specific estimate was 

based on Barr’s experience with similar projects. The detailed cost analysis is provided in Appendix 

A. 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by U.S. EPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,3000 cost 

 

26 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. 
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effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are 

evaluated. MPCA set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant27

. 

Therefore, all air pollution controls with annualized costs less than this screening threshold will be 

evaluated for visibility improvement, energy and other impacts. 

The cost of SO2 control for Mittal Steel is greater than $80,000 per ton of pollutant removed for a 

wet scrubber and over $100,000 per ton of pollutant removed for a WWESP. This cost is far in 

excess of any cost that is considered to be cost effective for BART, or even for BACT. Therefore, it 

is not necessary to calculate the incremental control cost of a WWESP compared to a wet scrubber. 

Energy and Environmental Impacts 

Because the cost of SO2 controls for Mittal Steel is so high and does not meet a reasonable definition 

of cost effective technology, these alternatives are removed from further consideration in this 

analysis. 

5.A.i.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. However, the economic impacts of controls for SO2 are not reasonably cost effective, so 

visibility impacts were not modeled for SO2 controls. 

 

27 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean 

Processing Plant, Fairmont, MN Permit 09100059-002. 
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5.A.ii Nitrogen Oxide Controls 

To be able to control NOx it is important to understand how NOx is formed. There are three 

mechanisms by which NOx production occurs: thermal, fuel and prompt NOx. 

• Fuel bound NOx is formed when nitrogen compounds in the fuel are oxidized in the 

combustion process. 

• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen 

molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen. 

Thermal NOx production is a function of the residence time, free oxygen, and temperature. 

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

result of reactions between nitrogen and carbon radicals generated during combustion. Only 

minor amounts of NOx are emitted as prompt NOx. 

The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the heater, the balance 

of NO2 is formed in the atmosphere when NO reacts with oxygen in the air. The majority of NOx

emitted is thermal NOx – very little fuel bound NOx is emitted. 

5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies 

With some understanding of how NOx is formed, available and applicable control technologies were 

evaluated. Step 1 identifies a comprehensive list of all potential retrofit control technologies that 

were evaluated. Many emerging technologies were identified that are not currently commercially 

available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the 

technology as it was understood at that time. In regards to the availability of the technology with 

respect to Step 1 of the BART analysis, the list has not changed from the information submitted at 

that time. The comprehensive list of control technologies is presented in Appendix D. 

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options 

Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As 

stated in section 2.B of this document, the technical feasibility of each option is determined by 

answering three specific questions: 

1. Is the control technology “available” to the specific source which is undergoing the 

BART analysis? 
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2. Is the control technology an “applicable technology” for the specific source which 

is undergoing the BART analysis? 

3. Are there source-specific issues/conditions that would make the control technology 

not technically feasible? 

A preliminary list of technologies was submitted to MPCA on May 9, 2006 with the status of the 

technology as it was understood at that time. As work on this evaluation progressed, additional 

information became apparent regarding the limited scope and scale of some of the technology 

applications. Appendix D presents the current status of the availability and applicability of each 

technology. 

The following section describes retrofit NOx control technologies that were identified as available 

and applicable in the May 9 submittal and discusses aspects of those technologies that determine 

whether or not the technology is technically feasible for the indurating furnace. 

External Flue Gas Recirculation (EFGR) 

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures 

thereby reducing thermal NOx formation. 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. For 

this technology to be effective, the combustion conditions must have the ability to be controlled at 

the burner tip. 

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

Application for EFGR technology in taconite induration is problematic for three reasons: 

1. The process exhaust gas in an induration furnace has approximately 15% - 18% oxygen 

versus a boiler which has 2% - 3% oxygen. In a boiler, the flue gas is relatively inert so 

it can be used as a diluent for flame temperature reduction. Taconite waste gas has much 

higher oxygen level; thus use of taconite waste gas for EFGR would be equivalent to 

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2. The oxidation zone of induration furnaces needs to be above 2,400oF in order to meet 

product specifications. Existing burners are designed to meet these process conditions. 

Application of EFGR would reduce flame temperatures. Lower flame temperatures 

would reduce furnace temperatures to the point that product quality could be jeopardized. 

3. Application of EFGR technology increases flame length. Dilution of the combustion 

reactants increases the reaction time needed for fuel oxidation to occur; so, flame length 

increases. Therefore, application of EFGR could result in flame impingement on furnace 

components. That would subject those components to excessive temperatures and cause 

equipment failures. 

Although this may be an available and applicable control option, it is not technically feasible due to 

the high oxygen content of the flue gas and will not be further evaluated in this report. 

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 typically 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 

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 10%. 

Application of low NOx burners would be limited to the preheating section of the furnace, where the 

temperature is less critical to product quality. If LNB were to be applied in the indurating section of 

the furnace, the reduced flame temperatures associated with LNB would adversely affect taconite 

pellet product quality. Mittal Steel already has Low-NOx burners in the pre-heat section. Since this 

option has already been implemented, further reductions beyond those already accounted for are not 

expected. 
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It is also important to note that there are other methods being developed for low NOx burners which 

are not yet commercially available. Some incorporate various fuel dilution techniques to reduce 

flame temperatures; such as mixing an inert gas like CO2 with natural gas. Water injection to cool 

the burner peak flame temperature is also being investigated. This technique has already been 

successfully used for reducing NOx emissions from gas turbines and a straight grate taconite 

indurating furnace in Europe, but is not yet commercially available. The water injection technique 

shows promise for high temperature applications, but will not be further investigated in this report as 

the technology is still in the research and development phase. 

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 25-50%. 

As noted above, taconite furnaces are designed to operate with oxygen levels of approximately 15% 

to 18%. At these oxygen levels, flue gas recirculation is ineffective at NOx reduction, and it would 

adversely affect combustion because excessive amounts of oxygen would be injected into the flame 

pattern. In addition, IFGR relies on convective flow of flue gas through the burner and requires 

burners to be up-fired; meaning that the burner is mounted in the furnace floor and the flame rises up. 

Furthermore, IFGR is not feasible because the reduced flame temperatures associated with IFGR 

would adversely affect taconite pellet product quality. 

Although this may be an available and applicable control option, it is not technically feasible due to 

the high oxygen content of the flue gas and will not be further evaluated in this report. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption 

which results in lower operating costs. Typically reduced fuel usage translates into reduced air 

emissions. An energy efficiency project would be to improve the heat distribution and flow of air in 

the furnace which would reduce the fuel usage. Each project is very dependent upon the fuel usage, 

process equipment, type of product and so many other variables. 

Due to the increased price of fuel, Mittal Steel has already implemented energy efficiency projects. 

Each project carries its own fuel usage reductions and, potentially, corresponding emission 
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reductions. It would be impossible to assign a general potential emission reduction for the energy 

efficient category. Due to the uncertainty and generalization of this category, this will not be further 

evaluated in this report. However, it should be noted that Mittal Steel will continue to evaluate and 

implement energy efficiency projects as they arise. 

Ported Kilns 

Ported kilns are rotary kilns that have air ports installed at specified points along the length of the 

kiln for process improvement. The purpose of the ports is to allow air injection into the pellet bed as 

it travels down the kiln bed. Ports are installed about the circumference of the kiln. Each port is 

equipped with a closure device that opens when it is at the bottom position to inject air in the pellet 

bed, and closed when it rotates out of position. 

The purpose of air injection is to provide additional oxygen for pellet oxidation. The oxidation 

reaction extracts enough heat to offset the heat loss associated with air injection. Air injection 

reduces the overall energy use of the kiln and produces a higher quality taconite pellet. Air injection 

also prevents carry over of the oxidation reaction into the pellet coolers. 

Ported kilns are applicable to grate kilns but not to straight grate indurating furnaces, as are present at 

Mittal Steel. Therefore, ported kilns are not an applicable technology for this facility. 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has pushed companies 

to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To 

achieve reduction of NOx emissions through alternative fuel usage, the source must be currently 

burning natural gas as the primary fuel. Switching from natural gas to a solid fuel for the indurating 

process would emit significantly less NOx. Switching natural gas usage to coal or other solid fuels 

exchanges one visibility impairment pollutant (NOx) for another (SO2). Therefore, if this option is 

pursued, the impact on emissions of all visibility impairing pollutants must be quantified and the 

cumulative visibility impact modeled to determine the net benefit of a particular alternative fuel. 
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It is important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.28 It is also important to note that furnace and process 

modifications to the straight-grate furnace would be required in order to use alternative fuels. 

However, similar to energy efficiency, Mittal Steel will continue to evaluate and implement alternate 

fuel usage as the feasibility arises. 

Process Optimization with NOx CEMS or Other Parametric Monitoring 

MPCA guidance lists “NOx CEMS” as a work practice/operational change for controlling NOx

emissions29. Parametric monitoring is a possible derivative of this alternative. 

Based on conversations with MPCA staff, this work practice would include process adjustments, or 

optimization, to minimize NOx emissions. The impact of the process adjustments would be measured 

using the NOx CEMS. This approach has been used in the electric utility industry to fine tune NOx

emissions from boilers. 

One taconite plant has installed NOx CEMS to monitor emissions but not to optimize NOx emissions 

through process fine tuning. That plant has experienced some reduction in NOx emissions but these 

encompass multiple variables and are not attributed to process fine tuning with the NOx CEMS. 

Therefore, this alternative has not been demonstrated in the taconite industry. 

There are several concerns with utilizing process optimization as an available, applicable and 

technically feasible control option for the taconite industry: 

• Taconite furnaces are designed and operated to convert magnetite to hematite in the presence 

of excess oxygen and require heat input to initiate the reaction which is exothermic and 

releases heat once initiated. Fuel combustion is only part of the process and therefore this 

process is different from a boiler. 

• The quality of the process feed materials to the furnace is variable at some taconite 

operations and product quality may be compromised by attempting to fine tune heat input to 

minimize NOx formation. 

 

28 Federal Register 70, no. 128 (July 6, 2005): 39164

29 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 4. 
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• At some operations, the operating parameters which generally influence the rate of NOx

generation such as flame temperature, fuel usage and excess air are relatively constant during 

operation of the furnace, independent of process operation variability. This indicates that NOx

formation may not be dependent upon controllable operating parameters. In the absence of 

controllable parameters, process optimization would not be effective at controlling NOx

emissions. 

Based upon this information, there is no indication that further emission reductions would be 

achieved through the use of the process optimization, using NOx CEMS or other parametric 

monitoring, as a control technology. Therefore, process optimization as a control option will not be 

evaluated further in this report. 

Post Combustion Controls 

NOx can be controlled using add-on systems located downstream of the furnace area of the 

combustion process. The two main techniques in commercial service include the selective non 

catalytic reduction (SNCR) process and the selective catalytic reduction (SCR) process. There are a 

number of different process systems in each of these categories of control techniques. 

In addition to these treatment systems, there are a large number of other processes being developed 

and tested on the market. These approaches involve innovative techniques of chemically reducing, 

absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives 

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these 

alternatives is described below.

Non-Selective Catalytic Reduction (NSCR) 

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

treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied 

primarily in natural gas combustion applications. 

NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx, 

unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx

emission reductions of 90 percent. In order to operate properly, the combustion process must be near 

stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO, 

resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal 

are: 
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2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part 

to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to the 

indurating furnace. In addition, we are not aware of any NSCR installations on taconite induration 

furnaces or similar combustion equipment. Therefore, this technology will not be further evaluated in 

this report. 

Selective Catalytic Reduction and Regenerative 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 the following chemical reaction: 

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2) 

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 about 570°F – 850°F for a 

normal catalyst. At temperature exceeding approximately 670oF, the oxidation of ammonia begins to 

become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and 

corrosion problems. 

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. 

Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia 

increases during load changes due to the instability of the temperature in the catalyst bed as well as at 

low loads because of the low gas temperature. 

Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR) 

control process as described below with a preheat process step to reheat the flue gas stream up to 

SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink 

(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR 

and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the 

preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow 
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alternates between vessels. Each of the vessels alternates between preheating/treating and heat 

recovery. 

The benefits of RSCR compared to SCR with conventional reheat is: 

• RSCR has a thermal efficiency of 90% - 95% versus the heat exchanger system in a reheat 

SCR system which has a thermal efficiency of 60% to 70%. 

There are several other concerns about the technical feasibility and applicability of RSCR on an 

indurating furnace: 

• The composition of the indurating furnace flue gas is significantly different from the 

composition of the flue gas from the boilers that utilize RSCR; 

• The taconite dust is highly erosive and can cause significantly equipment damage. RSCR has 

a number of valves which must be opened and closed frequently to switch catalyst/heat 

recovery beds. These valves could be subject to excessive wear in a taconite application due 

to the erosive nature of the taconite dust; 

• RSCR has not been applied downstream of a wet scrubber. Treating a stream saturated with 

water may present design problems in equipment sizing for proper heat transfer and in 

corrosion protection; 

• RSCR catalyst had been shown to oxidize mercury. Oxidized mercury can be absorbed by 

the local environment and have adverse impact. The impact of RSCR on mercury emissions 

needs to be studied to determine whether or not mercury oxidation is a problem and to 

identify mitigation methods if needed. 

To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not 

been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace 

exhausts, nor to exhaust streams with similar, high moisture content. Using RSCR at a taconite plant 

would require research, test runs, and extended trials to identify potential issues related to catalyst 

selection, and impacts on plant systems, including the furnaces and emission control systems. It is 

not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of 

a demonstration project. The timeline required to perform such a demonstration project would likely 

be two years to develop and agree on the test plan, obtain permits for the trial, commission the 

equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and 
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report on the results. The results would not be available within the time window for establishing 

emission limits to be incorporated in the state implementation plan (SIP) by December 2007. 

Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as 

mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to 

learn how to apply a control technology to a completely new and significantly different source type. 

Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this 

BART analysis. 

SCR with reheat through a conventional duct burner (rather than using a regenerative heater) has 

been successfully implemented more widely and in higher airflow applications and will be carried 

forward in this analysis as available and applicable technology that is reasonably expected to be 

technically feasible. 

Low Temperature Oxidation (LTO) 

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2, 

and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas 

(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium 

hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 

nitrates are removed from the scrubbing system and discharged to an appropriate water treatment 

system. Commercially available LTO systems include Tri-NOx® and LoTOx®. 

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

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

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

reactions are as follows: 
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O3 + NO → O2 + NO2

(1)

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

Tri-NOx

®

 is a multi-staged wet scrubbing process in industrial use. Several process columns, each 

assigned a separate processing stage, are involved. In the first stage, the incoming material is 

quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent 

stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx

®

 is 

typically applied at small to medium sized sources with high NOx concentration in the exhaust gas 

(1,000 ppm NOx). NOx concentrations in taconite exhaust are typically less than 200 ppm. 

Therefore, Tri-NOx

®

 is not applicable to taconite processing and will not be analyzed further in this 

BART analysis. 

Low Temperature Oxidation (LoTOx®) 

BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone 

to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same 

scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a 

scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an 

electrically powered ozone generator. The ozone generation rate is controlled to match the amount 

needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be 

economically feasible, a source of low cost oxygen must be available from a pipeline or on site 

generation. 

The first component of the technical feasibility review includes determining if the technology would 

apply to the process being reviewed. This would include a review and comparison of the chemical 

and physical properties required. Although it appears that the chemistry involved in the LTO 

technology may apply to an indurating furnace, the furnace exhaust contains other ore components 

that may participate in side reactions. This technology has not been demonstrated on a taconite pellet 

indurating furnace. This raises uncertainties about how or whether the technology will transfer to a 

different type of process. 

The second component of the technical feasibility review includes determining if the technology is 

commercially available. Evaluations of LTO found that it has only been applied to small to medium 

sized coal or gas fired boiler applications, and has never been demonstrated on a large-scale facility. 

For example, the current installations of LoTOx®

 are on sources with flue gas flow rates from 150 – 

35,000 acfm, which is quite small, compared to the indurating furnace flue gas flow rates of up to 
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205,000 acfm. This large scale-up is contrary to good engineering practices and could be 

problematic in maintaining the current removal efficiencies. 

In addition, only two of BOC’s LoTOx®

 installations are fully installed and operational applications. 

Therefore, although this is an emerging technology, the limited application means that it has not been 

demonstrated to be an effective technology in widespread application. 

There are several other concerns about the technical feasibility and applicability of LTO on an 

indurating furnace: 

• The composition of the indurating furnace flue gas is significantly different than the 

composition of the flue gas from the boilers and process heaters that utilize LTO; 

• The taconite dust in the flue gas is primarily magnetite (Fe3O4) which would react with the 

ozone to form hematite (Fe2O3); since the ozone injection point would be before the scrubber, 

there can be more than 400 pounds per hour of taconite dust in the flue gas which could 

consume a significant amount of the ozone being generated which may change the reaction 

kinetics; consequently, this would necessitate either an increase in the amount of ozone 

generated or a decrease in the estimated control efficiency; 

• The ozone that would be injected into the flue gas would react with the SO2, converting the 

material to SO3 which could result in the generation of sulfuric acid mist from the scrubber; 

• Since LTO has not been installed at a taconite plant, it is likely that the application of LTO to 

an indurating furnace waste gas could present technical problems which were not 

encountered, or even considered, in the existing LTO applications; 

• An LTO system at a taconite facility would also be a source of nitrate discharge to the 

tailings basin which would change the facility water chemistry which could cause operational 

problems and would likely cause additional problems with National Pollutant Discharge 

Elimination System (NPDES) discharge limits and requirements. 

Application of this technology has not been applied to taconite induration furnaces, to airflows of the 

magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high moisture content. 

Using LTO at a taconite plant would require research, test runs, and extended trials to identify 

potential issues related to design for high airflows and impacts on plant systems, including the 

furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of 
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performance would be forthcoming in advance of a demonstration project. The timeline required to 

perform such a demonstration project would likely be two years to develop and agree on the test 

plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs 

for a reasonable study period, and evaluate and report on the results. The results would not be 

available within the time window for establishing emission limits to be incorporated in the state 

implementation plan (SIP) by December 2007. 

Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as 

mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to 

learn how to apply a control technology to a completely new and significantly different source type. 

Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for 

this application and will not be evaluated further. 

Step 2 Conclusion 

Based upon the determination within Step 2, the remaining NOx control technologies that are 

available and applicable to the indurating furnace process are identified in Table 5-4. The technical 

feasibility as determined in Step 2 is also included in Table 5-4. 
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Table 5-4 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility 

Step 1 Step 2 

SO2 Pollution Control 

Technology 

Is this a generally available control technology? Is the control technology available to indurating furnaces?Is the control technology applicable to this specific source?Is it technically feasible for this source? 

External Flue Gas 

Recirculation (EFGR) Y Y N --- 

Low- NOx Burners Y Y 

Y 

(preheat 

section) 

Y 

(already 

installed) 

Induced Flue Gas 

Recirculation Burners Y Y N --- 

Energy Efficiency Projects Y Y Y N 

Ported Kilns 

(Applies to Grate Kilns Only) Y Y N --- 

Alternative Fuels Y Y N 

N 

(not 

required 

by BART) 

Process Optimization using 

NOx CEMS Y N --- --- 

Non-Selective Catalytic 

Reduction (NSCR) Y N --- --- 

Selective Catalytic Reduction 

(SCR) with conventional 

reheat 

Y Y Y Y 

Regenerative SCR Y N --- --- 

Selective Non-Catalytic 

Reduction (SNCR) Y N --- --- 

Low Temperature Oxidation 

(LTO) Y N --- --- 
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5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control 

Technologies 

Table 5-5 describes the expected control efficiency from each of the remaining technically feasible 

control options as identified in Step 2. 

Table 5-5 Indurating Furnace NOx Control Technology Effectiveness 

NOx Pollution Control 

Technology 

Approximate Control 

Efficiency 

SCR with Conventional 

Reheat 80% 

5.A.ii.d STEP 4 – Evaluate Impacts and Document the Result 

Table 5-6 details the expected costs associated with installation of SCR with conventional reheat. 

Equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S. EPA 

cost models. Capital cost was based on U.S. EPA control cost manual methods. 

Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. 

EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours 

per year. Operating costs of consumable materials, such as electricity, water, and chemicals were 

established based on the U.S. EPA control cost manual30 and engineering experience, and were 

adjusted for the specific flow rates and pollutant concentrations. 

Due to space considerations, 60%31 of the total capital investment was initially included in the costs 

to account for a retrofit installation. After discussions with facility staff and/or management, it was 

determined the space surrounding the furnaces is congested and the area surrounding the building 

supports vehicle traffic to transport materials to and from the building and maintenance access to the 

large equipment. Additionally, the structural design of the existing building would not support 

additional equipment on the roof. Therefore, the cost estimates provide for additional site-work and 

construction costs to accommodate the new equipment within the facility. A site-specific estimate for 

site work, foundations, and structural steel was added to arrive at the total retrofit installed cost of the 

control technology. The site specific estimate was based on Barr’s experience with similar projects. 

See Appendix C for an aerial photo of the facility. The detailed cost analysis is provided in Appendix 

A. 

 

30 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 

31 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. 
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Table 5-6 NOx Control Cost Summary 

Control 

Technology

Installed 

Capital Cost 

(MM$)

Operating 

Cost 

(MM$/yr)

Annualized 

Pollution 

Control 

Cost ($/ton)

SV 014 $33,429,177 $9,776,865 $23,504

SV 015 $33,531,232 $9,928,660 $18,552

SV 016 $33,713,372 $10,288,957 $12,473

SV 017 $33,855,392 $10,668,091 $9,396

Selective Catalytic Reduction (SCR) 

with Conventional Reheat

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by U.S. EPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,3000 cost 

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are 

evaluated. MPCA set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant32

. 

Therefore, all air pollution controls with annualized costs less than this screening threshold will be 

evaluated for visibility improvement, energy and other impacts. 

 

32 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean 

Processing Plant, Fairmont, MN Permit 09100059-002. 
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The cost of NOx control for stacks SV 014, 015, and 016 range from $12,473 to $23,504 per ton of 

pollutant removed. These costs are in excess of any cost that is considered to be cost effective for 

BART, or even for BACT. Therefore, NOx controls for these stacks will not be carried forward in 

this analysis. However, the cost of NOx control for stack SV 017 is $9,396 per ton of pollutant 

removed. Although this cost is in excess of any cost that is considered to be cost effective for 

BART, the technology for this stack will be carried forward as it is less than the $12,000 per ton 

screening threshold as recommended by MPCA. 

Energy and Environmental Impact 

The energy and non-air quality impacts for SCR with conventional reheat are presented in Table 5-7. 

Table 5-7 NOx Control Technology Impacts Assessment 

Control Technology Energy Impacts Other Impacts 

SCR with 

Conventional Reheat 

• Increased fan sizes 

due to increased 

pressure drop 

• Natural gas burning 

to reheat flue gas to 

reaction temperature 

• Ammonia slip, which is 

a visibility impairing 

pollutant 

• Catalyst disposal 

5.A.ii.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. This section of the report evaluates the visibility impacts of BART NOx control and the 

resulting degree of visibility improvement. 

However, it is important to note that CALPUFF is a conservative model that overestimates real 

impacts. Therefore, although the CALPUFF modeling results are important to comparing control 

alternatives on a relative basis, they are do not accurately predict real impacts. 
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Predicted 24-Hour Maximum Emission Rates 

Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts, 

the post-BART emissions to be used for the visibility impacts analysis should also reflect a 

maximum 24-hour average project emission rate. Emission reductions due to the SCR with standard 

reheat were based on the current operations. 

Table 5-8 provides a summary of the modeled NOx 24-hour maximum emission rates for the postbaseline (i.e. post-BART) operations. The stack parameters (location, height, velocity, and 

temperature) were assumed to remain unchanged from the baseline modeling. 

Post-BART Visibility Impacts Modeling Results 

Results of the post-BART visibility impacts modeling for current operations are presented in Table 

5-9. The results summarize the 98th percentile dV value and the number of days the facility 

contributes more than a 0.5 dV of visibility impairment at each of the Class I areas. As illustrated in 

table 5-9, post-BART modeled visibility improvements are as follows: 

o The operation of SCR with conventional reheat results in a visibility improvement of 

0.637 dV which represents a 24% improvement compared to the baseline. In 

addition, the number of days in which the visibility impacts from the facility 

exceeded 0.5 dV decreased from 257 days to 197 days. 
Table 5-8 Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates

Scenario Control Technology SO2 

Control 

Scenario SV #

Emission 

Unit SO2 NOx

% 

Reduction

Max 24-

hour 

lbs/day

% 

Reduc

SV 014 EU 026 Base (SO2 Scrubbers) SCR w/ Reheat (SV 017 Only) --- 3,000 --- 

SV 015 EU 026 Base (SO2 Scrubbers) SCR w/ Reheat (SV 017 Only) --- 3,000 --- SV 016 EU 026 Base (SO2 Scrubbers) SCR w/ Reheat (SV 017 Only) --- 3,000 --- SV 017 EU 026 Base (SO2 Scrubbers) SCR w/ Reheat (SV 017 Only) --- 3,000 80% 

1
Table 5-9 Post-BART NOx Modeling Scenarios - Visibility Modeling Results

Scenario #

Control 

Scenario

Class I 

Area with 

Greatest 

Impact

Modeled 98th 

Percentile 

Value 

(deciview)

No. of days 

exceeding 

0.5 deciview

Modeled 98th 

Percentile 

Value 

(deciview)

No. of days 

exceeding 

0.5 deciview

Modeled 98th 

Percentile 

Value 

(deciview)

No. of days 

exceeding 

0.5 deciview

M

P

(

0 Baseline BWCA 2.285 97 2.457 90 2.586 70 1 SCR on Stack SV 017 BWCA 1.69 80 1.949 69 1.909 48 

2002 2003 2004
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6. Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality, when determining BART for an individual source. 

The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document. 

The visibility impacts of individual control technologies were presented in Step 5 of sections 5.A.i.e 

and 5.A.ii.e. This section of the report was intended to evaluate the various BART control scenarios 

utilizing both SO2 and NOx controls, and determines the resulting degree of visibility improvement. 

However, since there were no SO2 controls that were carried forward from the economic screening 

analysis, no additional modeling is required. The applicable modeling for the NOx control 

technology is presented in section 5.A.ii.e. 
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7. Select BART 

The final step in the BART analysis process is to select BART. The selection is based on 

consideration of all of the criteria presented in MPCA and U.S. EPA guidance for determining 

BART, as presented in this report. 

The following technologies were identified as technically feasible and subject to the full BART 

analysis: the existing wet scrubbers that control PM and SO2, the low-NOx burners that are already 

installed on the preheat section of the furnace, and SCR (with conventional flue gas reheat) on SV 

017. The SCR alternative was not proposed as BART for the following reasons: 

Employment of SCR on SV 017 is not cost effective at $9396/ton NOx removed. Use of the 

technology would involve substantial electric use to operate new fans and substantial gas use 

to reheat the exhaust to temperatures required for the technology to effectively remove NOx. 

The spent catalyst would create a new solid waste. In addition, ammonia, a visibility 

impairing pollutant, would be emitted due to ammonia slip from the process and would 

decrease the visibility benefit and would potentially cause additional deposition of nitrogen 

to nearby surface waters. 

Mittal Steel is proposing BART to be the following: 

(1) For the material handling and storage units subject to MACT: 

 PM limitation of 0.008 gr/dscf, Taconite MACT standards33. 

 Compliance with this limit will be based on the performance test methods, emissions 

averaging options, and monitoring requirements of the Taconite MACT standards. 

(2) For material handling and storage units not subject to MACT (EU 018 and 019/020): 

 PM control equipment will be the existing baghouses. 

 PM limitation of 0.008 gr/dscf, which is equivalent to the Taconite MACT standards. 

 

33 40 CFR Part 63 Subpart RRRRR: National Emission Standards for Hazardous Air Pollutants: Taconite Iron Ore 

Processing 
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 Compliance with this limit will be based on the performance test methods, emissions 

averaging options, and monitoring requirements of the Taconite MACT standards. 

(3) Fugitive Sources Subject to BART – None. 

(4) For the indurating furnace: 

 SO2 limitation of 2.0 lbs/MMBtu when liquid fuel is being burned, which equates to 540 

lb/hr per furnace based upon a furnace heat input rating of 270 MMBtu/hr (controlled by 

the existing wet scrubbers for the furnace). 

 NOx limitation 1,088 lb/hr from the preheat burners (controlled by existing combustion 

practices for the furnace and low-NOx burners in the preheat section). 

 PM limitation of 0.01 gr/dscf (controlled by the existing wet scrubbers, equivalent to the 

emission limits established by the taconite MACT standard).34

 

The schedule for implementation of these limits is within the 5-year time-frame required for BART 

implementation. 

 

34 Ibid 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

Emission Unit # Emission Unit Description

NOx Max. 24-hr 

Actual

Emissions (lb/day)

SO2 Max. 24-hr 

Actual

Emissions 

(lb/day)

PM10 Max. 24-

hr Actual

Emissions 

(lb/day)

MACT

PM Emission 

Limit

*

(g/dscf)

Stack 

Number 

3A. Indurating Furnaces

EU 026 Indurating Machine --- --- 51.4 0.01 014 BA

EU 026 Indurating Machine --- --- 50.0 0.01 015 BA

EU 026 Indurating Machine --- --- 48.9 0.01 016 BA

EU 026 Indurating Machine --- --- 54.8 0.01 017 BA

3.B. PM-Only Taconite MACT Emission Units

EU 001 Primary Crusher --- --- 8.6 0.008 001 

EU 003 Drop Onto Coarse Ore Pile Conveyor --- --- 8.6 0.008 003 

EU 003/004/005 Secondary Crushing --- --- 14.5 0.008 004 

EU 003/004/005 Secondary Crushing --- --- 14.5 0.008 005 

EU 007/008/009/010 Tertiary Crushing --- --- 14.5 0.008 006 EU 007/008/009/010 Tertiary Crushing --- --- 16.5 0.008 007 

EU 006 Outside Ore Transfer --- --- 16.7 0.008 009 

EU 011/012 Fine Ore Drop --- --- 16.7 0.008 010 

EU 013/014/015/016/017 Fine Ore Drop, rod mill material handling --- --- 14.5 0.008 011 

EU 018 Machine Discharge and Conveyor to Spl Bin --- --- 26.9 0.008 018 

EU 021/022/023 Pellet Hearth Layer Conveyor, Bin, and Grate Feed --- --- 7.4 0.008 019 

EU 024/025 Pellet Hearth Layer Screen & Conveyor to HL Bin --- --- 13.2 0.008 020 

EU 029/030 Drop Into Spl Bin and Into Prod Spl Bin Conv --- --- 12.3 0.008 021 

EU 032 Drop onto P3 Pellet Pile Underfeed Conveyor --- --- 9.9 0.008 022 

EU 031 Drop in P1-P2 Transfer House --- --- 10.0 0.008 024 

3.C. Sources of fugitive PM that are subject to MACT standards 

None --- --- --- --- --- --- 

3.D. Non-MACT Units and Fugitive Sources (PM only)

EU 018 Binder Transer to Storage Silo --- --- 2.1 --- 012 

EU 019/020 Binder Shift Bins and Blending --- --- 7.0 --- 013 

3.E. Other Combustion Units 

None --- --- --- --- --- --- 

* The taconite MACT emission limits are based on EPA Method 5 and include the applicable averaging and grouping provisions, as presented in the regulation.
Ispat Inland Mining Company 9/6/2006

BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Cost Summary

NOx Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/tonSV 014 80% 104.0 416.0 $33,429,177 $9,776,865 $23,504SV 015 80% 133.8 535.2 $33,531,232 $9,928,660 $18,552SV 016 80% 206.2 824.9 $33,713,372 $10,288,957 $12,473SV 017 80% 283.8 1135.4 $33,855,392 $10,668,091 $9,396

SO2 Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/tonSV 014 80% 9.0 35.8 $22,809,844 $4,184,373 $116,801

SV 015 80% 9.0 35.8 $22,809,844 $4,184,373 $116,801SV 016 80% 9.0 35.8 $22,809,844 $4,184,373 $116,801SV 017 80% 9.0 35.8 $22,809,844 $4,184,373 $116,801SV 014 60% 17.9 26.9 $16,454,216 $2,229,797 $82,989

SV 015 60% 17.9 26.9 $16,454,216 $2,229,797 $82,989SV 016 60% 17.9 26.9 $16,454,216 $2,229,797 $82,989SV 017 60% 17.9 26.9 $16,454,216 $2,229,797 $82,989Wet Walled Electrostatic Precipitator (WWESP)(after existing scrubber)Secondary Wet Scrubber(after existing scrubber)Selective Catalytic Reduction with Reheat

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost AnalysisTable A.2: Summary of Utility, Chemical and Supply Costs

Operating Unit: Indurating Furnace Study Year 2006

Emission Unit Number EU 026Stack/Vent Number SV 014

Operating Unit: Indurating Furnace

Emission Unit Number EU 026Stack/Vent Number SV 015

Operating Unit: Indurating Furnace

Emission Unit Number EU 026Stack/Vent Number SV 016

Operating Unit: Indurating Furnace

Emission Unit Number EU 026Stack/Vent Number SV 017

Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 32 $/hr

Average union labor rate for MN mining industry

Maintenance Labor 32 $/hr

Average union labor rate for MN mining industry

Electricity 0.051 $/kwh 2006

Energy Information Administration. Expected annual average industrial price of electricity in the West North Central Division for 2007 - DOE http://tonto.eia.doe.gov/steo_query/app/elecpage

Natural Gas 9.2575 $/mscf 2005

Energy Information Administration. Average US Industrial Natural Gas Prices. July '05 to June '06. http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3m.

Water 0.28 $/mgal 0.20 1995

EPA Air Pollution Control Cost Manual, 6th Ed 2002, Section 5 Ch 1, page 1-40

Annual Costs for Packed Tower Absorber Exampadjusted for 3% inflation.

Cooling Water 0.28 $/mgal 0.23 1999

EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1

Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg 3% inflation

Compressed Air 0.32 $/mscf 0.25 1998

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 

Example problem; Dried & Filtered, Ch 1.6 '98 coinflation

Wastewater Disposal Neutralization 1.69 $/mgal 1.50 2002

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $1- $2/1000 gal. Cost adjusted for 3 lists $1.30 - $2.15/1,000 gal

Chemicals & SuppliesLime 90.80 $/ton 90.80 2006 Estimate from Cutler-Magney Company.Oxygen 40.00 $/ton 2006 BOC estimate.

Ammonia (29% aqua.) 0.12 $/lb 0.101 2000

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2, page 2-50

Annual costs for a retrofit SCR system example padjusted for 3% inflation.

Caustic 305.96 $/ton 280 2003 Hawkins Chemical 50% solution (50 Deg Be); includes delivery. '03 c

SCR Catalyst 141.00 $/ft3 Cormetech, Inc.

OtherSales Tax 6.5% %Interest Rate 7.00% %

EPA Air Pollution Control Cost Manual Introduction, Chapter 2, section 2.4.2. Social (discount) rate used as a default.

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Operating Information

Annual Op. Hrs 7946 Hours Engineering Estimate

Utilization Rate 93%Equipment Life 20 yrs Engineering EstimateStandardized Flow RateSV 014 173,108 scfm @ 32o F Calculated.

SV 015 173,108 scfm @ 32o F Calculated.

SV 016 173,108 scfm @ 32o F Calculated.

SV 017 173,108 scfm @ 32o F Calculated.

TemperatureSV 014 124 Deg F BART spreadsheet.SV 015 124 Deg F BART spreadsheet.SV 016 124 Deg F BART spreadsheet.SV 017 124 Deg F BART spreadsheet.Moisture ContentSV 014 10.5% Assumed value.

SV 015 10.5% Assumed value.

SV 016 10.5% Assumed value.

SV 017 10.5% Assumed value.

Actual Flow RateSV 014 205,478 acfm BART spreadsheet.

SV 015 205,478 acfm BART spreadsheet.

SV 016 205,478 acfm BART spreadsheet.

SV 017 205,478 acfm BART spreadsheet.

Standardized Flow RateSV 014 185,775 scfm @ 68o F Calculated.

SV 015 185,775 scfm @ 68o F Calculated.

SV 016 185,775 scfm @ 68o F Calculated.

SV 017 185,775 scfm @ 68o F Calculated.

Dry Std Flow RateSV 014 166,268 dscfm @ 68o F Calculated.

SV 015 166,268 dscfm @ 68o F Calculated.

SV 016 166,268 dscfm @ 68o F Calculated.

SV 017 166,268 dscfm @ 68o F Calculated.

Max Emis Future Actual Emis. lb/hr ton/year

Pollutant Lb/Hr tpy ppmv ppmv

Nitrous Oxides (NOx)SV 014 155.4 520.0 130 99.6

SV 015 200.0 669.0 168 128.1

SV 016 308.3 1,031.1 259 197.5SV 017 424.3 1,419.2 356 271.8Sulfur Dioxides (SO2)SV 014 125.0 44.8 75 6.2

SV 015 125.0 44.8 75 6.2

SV 016 125.0 44.8 75 6.2

SV 017 125.0 44.8 75 6.2

Max emissions are based on the permit limit and distributed to each stack based on 2005 stack test data. Future actual emissions based on 2005 stack tesMax emissions are based on emissions as reported in the BART questionairre

Future actual emissions based on AP-42 factors factor.

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control CostsUtility Chem$ Data 
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 014

Design Capacity 39 mmbtu/hr Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment 10,607,954

 Purchased Equipment Total SCR Only 11,297,471

SCR + Reheat 11,940,272

Total Capital Investment (TCI) = DC + IC SCR + Reheat 33,429,177

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 5,853,091

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 3,953,922

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 9,776,865

Emission Control Cost Calculation

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 155.4 520.0 80% 104.0 416.0 23,504

Notes & Assumptions

1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 SCR SV014 SCR 4 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,607,954

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 689,517

Freight 5% of control device cost (A) NA

Purchased Equipment Total 11,297,471

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 23% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 23% of purchased equip cost (A) 2,643,899

Project Contingeny (C) 15% of (A + B) 2,091,205

Total Plant Cost (D) A + B + C 16,032,575

Allowance for Funds During Construction (E) 0 for SCR 0

Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 320,652

Inventory Capital Reagent Vol * $/gal 18,190

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 16,371,417

Retrofit factor(11) 60% of TCI 9,822,850

Sitework and Foundations 1,400,000

Structural Steel 4,800,000

Total Capital Investment Retrofit Installed 32,394,267

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568

Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 245,571

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 414 kW-hr, 7946 hr/yr, 93% utilization 156,002

SCR Catalyst 64.71 Catalyst Replacement 124,656

Ammonia (29% aqua.) 0.12 $/lb, 536 lb/hr, 7946 hr/yr, 93% utilization 477,700

Total Annual Direct Operating Costs 1,077,032

Indirect Operating Costs

Overhead 60% of total labor and material costs 42,007

Administration (2% total capital costs) 2% of total capital costs (TCI) 327,428

Property tax (1% total capital costs) 1% of total capital costs (TCI) 163,714

Insurance (1% total capital costs) 1% of total capital costs (TCI) 163,714

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,057,790

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,754,654

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,831,686

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 SCR SV014 SCR 5 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst Estimate amount of catalyst required 

Equipment Life 24,000 hours Vol. #1 2708 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 185,775

Vol #2 2842.2 ft3

Amount Required 2,842 ft

3

Catalyst Cost 400,757

Y catalyst life factor 3 Years

Annualized Cost 124,656

Equivalent Duty 1,084 Plant Cap kW A 111,228

Est power platn eff 35% Unc Nox lb/mmBtu B 0.16 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35

Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066

Equivalent power plant kW 111,228 Capital Cost $/kW D $95.37 $10,607,954.15 Total SCR Equipment

Uncontrolled Nox t/y 155.4 Fixed O&M E $70,012.50

Annual Operating Hrs 8000 Variable O&M F $219,032.81

Uncontrolled Nox lb/mmBtu 0.158 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

Electrical Use

Duty 1,084 MMBtu/hr kW

NOx Cont Eff 80% Power 413.9

NOx in 0.16 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 413.9

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

155 lb/hr Neat 71.6 gal/hr

29% solution Volume 14 day inventory 24,060 gal $18,190 Inventory Cost

536 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.158

Actual dscf/MMBtu 258,612

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 1,084 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 9,535 15% of Operator Costs

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 245,571 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 413.9 kW-hr 3,058,863 156,002 $/kwh, 414 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 124,656 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 536 lb/hr 3,961,050 477,700 $/lb, 536 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 SCR SV014 SCR 6 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 014 Chemical Engineering

Design Capacity 39 mmbtu/hr Standardized Flow Rate 173,108 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 124 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 529,054

 Purchased Equipment Total (B) 22% of control device cost (A) 642,801

 Installation - Standard Costs 30% of purchased equip cost (B) 192,840

 Installation - Site Specific Costs NA

 Installation Total 192,840

 Total Direct Capital Cost, DC 835,641

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 199,268

Total Capital Investment (TCI) = DC + IC 1,034,910

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,776,058

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 169,120

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,945,179

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 Reheat SV014 Reheat 7 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 529,054

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 52,905

MN Sales Taxes 6.5% of control device cost (A) 34,389

Freight 5% of control device cost (A) 26,453

Purchased Equipment Total (B) 22% 642,801

Installation

Foundations & supports 8% of purchased equip cost (B) 51,424

Handling & erection 14% of purchased equip cost (B) 89,992

Electrical 4% of purchased equip cost (B) 25,712

Piping 2% of purchased equip cost (B) 12,856

Insulation 1% of purchased equip cost (B) 6,428

Painting 1% of purchased equip cost (B) 6,428

Installation Subtotal Standard Expenses 30% 192,840

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 192,840

Total Direct Capital Cost, DC 835,641

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 64,280

Construction & field expenses 5% of purchased equip cost (B) 32,140

Contractor fees 10% of purchased equip cost (B) 64,280

Start-up 2% of purchased equip cost (B) 12,856

Performance test 1% of purchased equip cost (B) 6,428

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 19,284

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 199,268

Total Capital Investment (TCI) = DC + IC 1,034,910

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,034,910

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Supervisor 15% 15% of Operator Costs 2,384

Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Maintenance Materials 100% of maintenance labor costs 15,892

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization 286,916

Natural Gas 9.26 $/mscf, 1,081 scfm, 7946 hr/yr, 93% utilization 4,439,082

Total Annual Direct Operating Costs 4,776,058

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,698

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,349

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,349

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 97,688

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 169,120

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,945,179

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 Reheat SV014 Reheat 8 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 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 OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 205,478 19 0.6 761.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 205,478 23 0.6 921.6 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 761.3

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 2,384 15% of Operator Costs

Maintenance

Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 761.3 kW-hr 5,625,810 286,916 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 1,081 scfm 479,512 4,439,082 $/mscf, 1,081 scfm, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 Reheat SV014 Reheat 9 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 

Twi 124 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 562 Deg F - Temperature of waste gas out of heat recovery

Tfo 312 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F

Qwg 185,775 scfm - Flow of waste gas 

Qaf 1,081 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 186,856 scfm Flue Gas Cost in 1989 $'s $443,723

Current Cost Using CHE Plant Cost Index $529,054

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 Reheat SV014 Reheat 10 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 015

Design Capacity 50 mmbtu/hr Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment 10,654,839

 Purchased Equipment Total SCR Only 11,347,404

SCR + Reheat 11,990,205

Total Capital Investment (TCI) = DC + IC SCR + Reheat 33,531,232

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 5,992,515

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 3,966,292

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 9,928,660

Emission Control Cost Calculation

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 200.0 669.0 80% 133.8 535.2 18,552

Notes & Assumptions

1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 CUECost Workbook Version 1.0, USEPA Document Page 2

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SV015 SCR SV015 SCR 11 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,654,839

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 692,565

Freight 5% of control device cost (A) NA

Purchased Equipment Total 11,347,404

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 23% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 23% of purchased equip cost (A) 2,643,899

Project Contingeny (C) 15% of (A + B) 2,098,695

Total Plant Cost (D) A + B + C 16,089,998

Allowance for Funds During Construction (E) 0 for SCR 0

Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 321,800

Inventory Capital Reagent Vol * $/gal 23,404

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 16,435,201

Retrofit factor(11) 60% of TCI 9,861,121

Sitework and Foundations 1,400,000

Structural Steel 4,800,000

Total Capital Investment Retrofit Installed 32,496,322

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568

Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 246,528

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 418 kW-hr, 7946 hr/yr, 93% utilization 157,561

SCR Catalyst 64.71 Catalyst Replacement 124,656

Ammonia (29% aqua.) 0.12 $/lb, 690 lb/hr, 7946 hr/yr, 93% utilization 614,609

Total Annual Direct Operating Costs 1,216,457

Indirect Operating Costs

Overhead 60% of total labor and material costs 42,193

Administration (2% total capital costs) 2% of total capital costs (TCI) 328,704

Property tax (1% total capital costs) 1% of total capital costs (TCI) 164,352

Insurance (1% total capital costs) 1% of total capital costs (TCI) 164,352

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,067,423

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,767,024

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,983,481

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV015 SCR SV015 SCR 12 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b: NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst Estimate amount of catalyst required 

Equipment Life 24,000 hours Vol. #1 2708 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 185,775

Vol #2 2842.2 ft3

Amount Required 2,842 ft

3

Catalyst Cost 400,757

Y catalyst life factor 3 Years

Annualized Cost 124,656

Equivalent Duty 1,084 Plant Cap kW A 111,228

Est power platn eff 35% Unc Nox lb/mmBtu B 0.20 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35

Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066

Equivalent power plant kW 111,228 Capital Cost $/kW D $95.79 $10,654,839.28 Total SCR Equipment

Uncontrolled Nox t/y 200.0 Fixed O&M E $70,321.94

Annual Operating Hrs 8000 Variable O&M F $221,135.84

Uncontrolled Nox lb/mmBtu 0.203 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

Electrical Use

Duty 1,084 MMBtu/hr kW

NOx Cont Eff 80% Power 418.1

NOx in 0.20 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 418.1

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

200 lb/hr Neat 92.1 gal/hr

29% solution Volume 14 day inventory 30,955 gal $23,404 Inventory Cost

690 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.203

Actual dscf/MMBtu 201,004

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 1,084 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 9,535 15% of Operator Costs

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 246,528 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 418.1 kW-hr 3,089,427 157,561 $/kwh, 418 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 124,656 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 690 lb/hr 5,096,292 614,609 $/lb, 690 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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SV015 SCR SV015 SCR 13 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 015 Chemical Engineering

Design Capacity 50 mmbtu/hr Standardized Flow Rate 173,108 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 124 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 529,054

 Purchased Equipment Total (B) 22% of control device cost (A) 642,801

 Installation - Standard Costs 30% of purchased equip cost (B) 192,840

 Installation - Site Specific Costs NA

 Installation Total 192,840

 Total Direct Capital Cost, DC 835,641

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 199,268

Total Capital Investment (TCI) = DC + IC 1,034,910

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,776,058

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 169,120

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,945,179

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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SV015 Reheat SV015 Reheat 14 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 529,054

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 52,905

MN Sales Taxes 6.5% of control device cost (A) 34,389

Freight 5% of control device cost (A) 26,453

Purchased Equipment Total (B) 22% 642,801

Installation

Foundations & supports 8% of purchased equip cost (B) 51,424

Handling & erection 14% of purchased equip cost (B) 89,992

Electrical 4% of purchased equip cost (B) 25,712

Piping 2% of purchased equip cost (B) 12,856

Insulation 1% of purchased equip cost (B) 6,428

Painting 1% of purchased equip cost (B) 6,428

Installation Subtotal Standard Expenses 30% 192,840

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 192,840

Total Direct Capital Cost, DC 835,641

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 64,280

Construction & field expenses 5% of purchased equip cost (B) 32,140

Contractor fees 10% of purchased equip cost (B) 64,280

Start-up 2% of purchased equip cost (B) 12,856

Performance test 1% of purchased equip cost (B) 6,428

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 19,284

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 199,268

Total Capital Investment (TCI) = DC + IC 1,034,910

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,034,910

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Supervisor 15% 15% of Operator Costs 2,384

Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Maintenance Materials 100% of maintenance labor costs 15,892

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization 286,916

Natural Gas 9.26 $/mscf, 1,081 scfm, 7946 hr/yr, 93% utilization 4,439,082

Total Annual Direct Operating Costs 4,776,058

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,698

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,349

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,349

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 97,688

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 169,120

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,945,179

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV015 Reheat SV015 Reheat 15 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 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 OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 205,478 19 0.6 761.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 205,478 23 0.6 921.6 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 761.3

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 2,384 15% of Operator Costs

Maintenance

Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 761.3 kW-hr 5,625,810 286,916 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 1,081 scfm 479,512 4,439,082 $/mscf, 1,081 scfm, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 

Twi 124 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 562 Deg F - Temperature of waste gas out of heat recovery

Tfo 312 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F

Qwg 185,775 scfm - Flow of waste gas 

Qaf 1,081 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 186,856 scfm Flue Gas Cost in 1989 $'s $443,723

Current Cost Using CHE Plant Cost Index $529,054

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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SV015 Reheat SV015 Reheat 17 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 016

Design Capacity 77 mmbtu/hr Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment 10,735,822

 Purchased Equipment Total SCR Only 11,433,650

SCR + Reheat #REF!

Total Capital Investment (TCI) = DC + IC SCR + Reheat 33,713,372

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 6,330,746

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 3,958,211

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 10,288,957

Emission Control Cost Calculation

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 308.3 1,031.1 80% 206.2 824.9 12,473

Notes & Assumptions

1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 CUECost Workbook Version 1.0, USEPA Document Page 2

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SV016 SCR SV016 SCR 18 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,735,822

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 697,828

Freight 5% of control device cost (A) NA

Purchased Equipment Total 11,433,650

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 23% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 23% of purchased equip cost (A) 2,643,899

Project Contingeny (C) 15% of (A + B) 2,111,632

Total Plant Cost (D) A + B + C 16,189,181

Allowance for Funds During Construction (E) 0 for SCR 0

Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 323,784

Inventory Capital Reagent Vol * $/gal 36,074

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 16,549,039

Retrofit factor(11) 60% of TCI 9,929,423

Sitework and Foundations 1,400,000

Structural Steel 4,800,000

Total Capital Investment Retrofit Installed 32,678,462

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568

Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 248,236

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 428 kW-hr, 7946 hr/yr, 93% utilization 161,349

SCR Catalyst 64.71 Catalyst Replacement 124,656

Ammonia (29% aqua.) 0.12 $/lb, 1,063 lb/hr, 7946 hr/yr, 93% utilization 947,344

Total Annual Direct Operating Costs 1,554,687

Indirect Operating Costs

Overhead 60% of total labor and material costs 42,514

Administration (2% total capital costs) 2% of total capital costs (TCI) 330,981

Property tax (1% total capital costs) 1% of total capital costs (TCI) 165,490

Insurance (1% total capital costs) 1% of total capital costs (TCI) 165,490

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,084,616

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,789,091

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,343,779

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV016 SCR SV016 SCR 19 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c: NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst Estimate amount of catalyst required 

Equipment Life 24,000 hours Vol. #1 2708 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 185,775

Vol #2 2842.2 ft3

Amount Required 2,842 ft

3

Catalyst Cost 400,757

Y catalyst life factor 3 Years

Annualized Cost 124,656

Equivalent Duty 1,084 Plant Cap kW A 111,228

Est power platn eff 35% Unc Nox lb/mmBtu B 0.31 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35

Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066

Equivalent power plant kW 111,228 Capital Cost $/kW D $96.52 $10,735,821.98 Total SCR Equipment

Uncontrolled Nox t/y 308.3 Fixed O&M E $70,856.43

Annual Operating Hrs 8000 Variable O&M F $225,270.93

Uncontrolled Nox lb/mmBtu 0.313 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

Electrical Use

Duty 1,084 MMBtu/hr kW

NOx Cont Eff 80% Power 428.1

NOx in 0.31 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 428.1

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

308 lb/hr Neat 142.0 gal/hr

29% solution Volume 14 day inventory 47,714 gal $36,074 Inventory Cost

1063 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.313

Actual dscf/MMBtu 130,406

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 1,084 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 9,535 15% of Operator Costs

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 248,236 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 428.1 kW-hr 3,163,707 161,349 $/kwh, 428 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 124,656 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 1063 lb/hr 7,855,300 947,344 $/lb, 1,063 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV016 SCR SV016 SCR 20 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 016 Chemical Engineering

Design Capacity 77 mmbtu/hr Standardized Flow Rate 173,108 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 124 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 529,054

 Purchased Equipment Total (B) 22% of control device cost (A) 642,801

 Installation - Standard Costs 30% of purchased equip cost (B) 192,840

 Installation - Site Specific Costs NA

 Installation Total 192,840

 Total Direct Capital Cost, DC 835,641

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 199,268

Total Capital Investment (TCI) = DC + IC 1,034,910

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,776,058

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 169,120

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,945,179

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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SV016 Reheat SV016 Reheat 21 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 529,054

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 52,905

MN Sales Taxes 6.5% of control device cost (A) 34,389

Freight 5% of control device cost (A) 26,453

Purchased Equipment Total (B) 22% 642,801

Installation

Foundations & supports 8% of purchased equip cost (B) 51,424

Handling & erection 14% of purchased equip cost (B) 89,992

Electrical 4% of purchased equip cost (B) 25,712

Piping 2% of purchased equip cost (B) 12,856

Insulation 1% of purchased equip cost (B) 6,428

Painting 1% of purchased equip cost (B) 6,428

Installation Subtotal Standard Expenses 30% 192,840

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 192,840

Total Direct Capital Cost, DC 835,641

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 64,280

Construction & field expenses 5% of purchased equip cost (B) 32,140

Contractor fees 10% of purchased equip cost (B) 64,280

Start-up 2% of purchased equip cost (B) 12,856

Performance test 1% of purchased equip cost (B) 6,428

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 19,284

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 199,268

Total Capital Investment (TCI) = DC + IC 1,034,910

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,034,910

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Supervisor 15% 15% of Operator Costs 2,384

Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Maintenance Materials 100% of maintenance labor costs 15,892

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization 286,916

Natural Gas 9.26 $/mscf, 1,081 scfm, 7946 hr/yr, 93% utilization 4,439,082

Total Annual Direct Operating Costs 4,776,058

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,698

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,349

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,349

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 97,688

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 169,120

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,945,179

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 205,478 19 0.6 761.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 205,478 23 0.6 921.6 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 761.3

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 2,384 15% of Operator Costs

Maintenance

Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 761.3 kW-hr 5,625,810 286,916 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 1,081 scfm 479,512 4,439,082 $/mscf, 1,081 scfm, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 

Twi 124 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 562 Deg F - Temperature of waste gas out of heat recovery

Tfo 312 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F

Qwg 185,775 scfm - Flow of waste gas 

Qaf 1,081 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 186,856 scfm Flue Gas Cost in 1989 $'s $443,723

Current Cost Using CHE Plant Cost Index $529,054

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 017

Design Capacity 105 mmbtu/hr Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment 10,796,007

 Purchased Equipment Total SCR Only 11,497,747

SCR + Reheat 12,140,548

Total Capital Investment (TCI) = DC + IC SCR + Reheat 33,855,392

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 6,692,685

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,005,554

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 10,668,091

Emission Control Cost Calculation

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 424.3 1,419.2 80% 283.8 1,135.4 9,396

Notes & Assumptions

1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 CUECost Workbook Version 1.0, USEPA Document Page 2

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,796,007

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 701,740

Freight 5% of control device cost (A) NA

Purchased Equipment Total 11,497,747

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 23% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 23% of purchased equip cost (A) 2,643,899

Project Contingeny (C) 15% of (A + B) 2,121,247

Total Plant Cost (D) A + B + C 16,262,893

Allowance for Funds During Construction (E) 0 for SCR 0

Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 325,258

Inventory Capital Reagent Vol * $/gal 49,651

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 16,637,801

Retrofit factor(11) 60% of TCI 9,982,681

Sitework and Foundations 1,400,000

Structural Steel 4,800,000

Total Capital Investment Retrofit Installed 32,820,482

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568

Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 249,567

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 439 kW-hr, 7946 hr/yr, 93% utilization 165,408

SCR Catalyst 64.71 Catalyst Replacement 124,656

Ammonia (29% aqua.) 0.12 $/lb, 1,463 lb/hr, 7946 hr/yr, 93% utilization 1,303,892

Total Annual Direct Operating Costs 1,916,627

Indirect Operating Costs

Overhead 60% of total labor and material costs 42,752

Administration (2% total capital costs) 2% of total capital costs (TCI) 332,756

Property tax (1% total capital costs) 1% of total capital costs (TCI) 166,378

Insurance (1% total capital costs) 1% of total capital costs (TCI) 166,378

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,098,021

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,806,286

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,722,912

See Summary page for notes and assumptions

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d: NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst Estimate amount of catalyst required 

Equipment Life 24,000 hours Vol. #1 2708 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 185,775

Vol #2 2842.2 ft3

Amount Required 2,842 ft

3

Catalyst Cost 400,757

Y catalyst life factor 3 Years

Annualized Cost 124,656

Equivalent Duty 1,084 Plant Cap kW A 111,228

Est power platn eff 35% Unc Nox lb/mmBtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35

Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066

Equivalent power plant kW 111,228 Capital Cost $/kW D $97.06 $10,796,006.80 Total SCR Equipment

Uncontrolled Nox t/y 424.3 Fixed O&M E $71,253.64

Annual Operating Hrs 8000 Variable O&M F $228,901.35

Uncontrolled Nox lb/mmBtu 0.431 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

Electrical Use

Duty 1,084 MMBtu/hr kW

NOx Cont Eff 80% Power 438.9

NOx in 0.43 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 438.9

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

424 lb/hr Neat 195.5 gal/hr

29% solution Volume 14 day inventory 65,671 gal $49,651 Inventory Cost

1463 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.431

Actual dscf/MMBtu 94,746

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 1,084 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 9,535 15% of Operator Costs

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 249,567 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 438.9 kW-hr 3,243,304 165,408 $/kwh, 439 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 124,656 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 1463 lb/hr 10,811,773 1,303,892 $/lb, 1,463 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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SV017 SCR SV017 SCR 27 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 017 Chemical Engineering

Design Capacity 105 mmbtu/hr Standardized Flow Rate 173,108 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 124 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 529,054

 Purchased Equipment Total (B) 22% of control device cost (A) 642,801

 Installation - Standard Costs 30% of purchased equip cost (B) 192,840

 Installation - Site Specific Costs NA

 Installation Total 192,840

 Total Direct Capital Cost, DC 835,641

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 199,268

Total Capital Investment (TCI) = DC + IC 1,034,910

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,776,058

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 169,120

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,945,179

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 529,054

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 52,905

MN Sales Taxes 6.5% of control device cost (A) 34,389

Freight 5% of control device cost (A) 26,453

Purchased Equipment Total (B) 22% 642,801

Installation

Foundations & supports 8% of purchased equip cost (B) 51,424

Handling & erection 14% of purchased equip cost (B) 89,992

Electrical 4% of purchased equip cost (B) 25,712

Piping 2% of purchased equip cost (B) 12,856

Insulation 1% of purchased equip cost (B) 6,428

Painting 1% of purchased equip cost (B) 6,428

Installation Subtotal Standard Expenses 30% 192,840

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 192,840

Total Direct Capital Cost, DC 835,641

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 64,280

Construction & field expenses 5% of purchased equip cost (B) 32,140

Contractor fees 10% of purchased equip cost (B) 64,280

Start-up 2% of purchased equip cost (B) 12,856

Performance test 1% of purchased equip cost (B) 6,428

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 19,284

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 199,268

Total Capital Investment (TCI) = DC + IC 1,034,910

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,034,910

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Supervisor 15% 15% of Operator Costs 2,384

Maintenance

Maintenance Labor 32.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Maintenance Materials 100% of maintenance labor costs 15,892

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization 286,916

Natural Gas 9.26 $/mscf, 1,081 scfm, 7946 hr/yr, 93% utilization 4,439,082

Total Annual Direct Operating Costs 4,776,058

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,698

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,349

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,349

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 97,688

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 169,120

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,945,179

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 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 OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 205,478 19 0.6 761.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 205,478 23 0.6 921.6 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 761.3

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 2,384 15% of Operator Costs

Maintenance

Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 761.3 kW-hr 5,625,810 286,916 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 1,081 scfm 479,512 4,439,082 $/mscf, 1,081 scfm, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d: NOx Control - Cost of Flue Gas Reheat (Thermal Oxidizer)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 

Twi 124 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 562 Deg F - Temperature of waste gas out of heat recovery

Tfo 312 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F

Qwg 185,775 scfm - Flow of waste gas 

Qaf 1,081 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 186,856 scfm Flue Gas Cost in 1989 $'s $443,723

Current Cost Using CHE Plant Cost Index $529,054

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.a: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 014

Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,814,356

 Purchased Equipment Total (B) 22% of control device cost (A) 4,634,443

 Installation - Standard Costs 67% of purchased equip cost (B) 3,105,077

 Installation - Site Specific Costs 6,200,000

 Installation Total 3,105,077

 Total Direct Capital Cost, DC 7,739,520

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,641,632

Total Capital Investment (TCI) = DC + IC 22,809,844

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,546,816

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,637,557

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,184,373

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 155.4 520.0 0% 520.0 - NA

Sulfur Dioxide (SO2) 125.0 44.8 80% 9.0 35.8 116,801

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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SV014 WWESP 9/7/2006 Page 32 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.a: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,814,356

Instrumentation 10% of control device cost (A) 381,436

MN Sales Taxes 6.5% of control device cost (A) 247,933

Freight 5% of control device cost (A) 190,718

Purchased Equipment Total (B) 22% 4,634,443

Installation

Foundations & supports 4% of purchased equip cost (B) 185,378

Handling & erection 50% of purchased equip cost (B) 2,317,221

Electrical 8% of purchased equip cost (B) 370,755

Piping 1% of purchased equip cost (B) 46,344

Insulation 2% of purchased equip cost (B) 92,689

Painting 2% of purchased equip cost (B) 92,689

Installation Subtotal Standard Expenses 67% 3,105,077

Total Direct Capital Cost, DC 7,739,520

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 926,889

Construction & field expenses 20% of purchased equip cost (B) 926,889

Contractor fees 10% of purchased equip cost (B) 463,444

Start-up 1% of purchased equip cost (B) 46,344

Performance test 1% of purchased equip cost (B) 46,344

Model Studies 2% of purchased equip cost (B) 92,689

Contingencies 3% of purchased equip cost (B) 139,033

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,641,632

Total Capital Investment (TCI) = DC + IC 10,381,152

Retrofit multiplier3

60% of TCI 6,228,691

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 22,809,844

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568

Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Labor 32.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 4,125

Maintenance Materials 1.00 % of Maintenance Labor 38,144

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 486 kW-hr, 7946 hr/yr, 93% utilization 182,993

Water 0.28 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization 126,112

WW Treat Neutralization 1.69 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization 769,057

Caustic 305.96 $/ton, 313 lb/hr, 7946 hr/yr, 93% utilization 353,282

Total Annual Direct Operating Costs 1,546,816

Indirect Operating Costs

Overhead 60% of total labor and material costs 69,223

Administration (2% total capital costs) 2% of total capital costs (TCI) 207,623

Property tax (1% total capital costs) 1% of total capital costs (TCI) 103,812

Insurance (1% total capital costs) 1% of total capital costs (TCI) 103,812

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,153,088

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,637,557

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,184,373

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 WWESP 9/7/2006 Page 33 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.a: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit

Amount Required 0

Total Rep Parts Cost 0

Installation Labor 0

Total Installed Cost 0

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O kW

Fan Power 205,478 10 371.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 19.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 48,598 94.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 485.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 1027.39 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 312.50 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 9,535 15% of Operator Costs

Maintenance

Maint Labor 32.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 38,144 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 485.5 kW-hr 3,588,105 182,993 $/kwh, 486 kW-hr, 7946 hr/yr, 93% utilization

Water 0.28 $/mgal 1,027.4 gpm 455,531 126,112 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/mgal 1,027.4 gpm 455,531 769,057 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization

Caustic 305.96 $/ton 312.5 lb/hr 1,155 353,282 $/ton, 313 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV014 WWESP 9/7/2006 Page 34 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.b: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 015

Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,814,356

 Purchased Equipment Total (B) 22% of control device cost (A) 4,634,443

 Installation - Standard Costs 67% of purchased equip cost (B) 3,105,077

 Installation - Site Specific Costs 6,200,000

 Installation Total 3,105,077

 Total Direct Capital Cost, DC 7,739,520

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,641,632

Total Capital Investment (TCI) = DC + IC 22,809,844

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,546,816

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,637,557

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,184,373

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 200.0 669.0 0% 669.0 - NA

Sulfur Dioxide (SO2) 125.0 44.8 80% 9.0 35.8 116,801

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm

3 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV015 WWESP 9/7/2006 Page 35 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.b: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,814,356

Instrumentation 10% of control device cost (A) 381,436

MN Sales Taxes 6.5% of control device cost (A) 247,933

Freight 5% of control device cost (A) 190,718

Purchased Equipment Total (B) 22% 4,634,443

Installation

Foundations & supports 4% of purchased equip cost (B) 185,378

Handling & erection 50% of purchased equip cost (B) 2,317,221

Electrical 8% of purchased equip cost (B) 370,755

Piping 1% of purchased equip cost (B) 46,344

Insulation 2% of purchased equip cost (B) 92,689

Painting 2% of purchased equip cost (B) 92,689

Installation Subtotal Standard Expenses 67% 3,105,077

Total Direct Capital Cost, DC 7,739,520

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 926,889

Construction & field expenses 20% of purchased equip cost (B) 926,889

Contractor fees 10% of purchased equip cost (B) 463,444

Start-up 1% of purchased equip cost (B) 46,344

Performance test 1% of purchased equip cost (B) 46,344

Model Studies 2% of purchased equip cost (B) 92,689

Contingencies 3% of purchased equip cost (B) 139,033

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,641,632

Total Capital Investment (TCI) = DC + IC 10,381,152

Retrofit multiplier3

60% of TCI 6,228,691

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 22,809,844

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568

Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Labor 32.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 4,125

Maintenance Materials 1.00 % of Maintenance Labor 38,144

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 486 kW-hr, 7946 hr/yr, 93% utilization 182,993

Water 0.28 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization 126,112

WW Treat Neutralization 1.69 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization 769,057

Caustic 305.96 $/ton, 313 lb/hr, 7946 hr/yr, 93% utilization 353,282

Total Annual Direct Operating Costs 1,546,816

Indirect Operating Costs

Overhead 60% of total labor and material costs 69,223

Administration (2% total capital costs) 2% of total capital costs (TCI) 207,623

Property tax (1% total capital costs) 1% of total capital costs (TCI) 103,812

Insurance (1% total capital costs) 1% of total capital costs (TCI) 103,812

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,153,088

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,637,557

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,184,373

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV015 WWESP 9/7/2006 Page 36 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.b: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit

Amount Required 0

Total Rep Parts Cost 0

Installation Labor 0

Total Installed Cost 0

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O kW

Fan Power 205,478 10 371.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 19.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 48,598 94.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 485.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 1027.39 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 312.50 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 9,535 15% of Operator Costs

Maintenance

Maint Labor 32.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 38,144 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 485.5 kW-hr 3,588,105 182,993 $/kwh, 486 kW-hr, 7946 hr/yr, 93% utilization

Water 0.28 $/mgal 1,027.4 gpm 455,531 126,112 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/mgal 1,027.4 gpm 455,531 769,057 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization

Caustic 305.96 $/ton 312.5 lb/hr 1,155 353,282 $/ton, 313 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV015 WWESP 9/7/2006 Page 37 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.c: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 016

Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,814,356

 Purchased Equipment Total (B) 22% of control device cost (A) 4,634,443

 Installation - Standard Costs 67% of purchased equip cost (B) 3,105,077

 Installation - Site Specific Costs 6,200,000

 Installation Total 3,105,077

 Total Direct Capital Cost, DC 7,739,520

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,641,632

Total Capital Investment (TCI) = DC + IC 22,809,844

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,546,816

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,637,557

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,184,373

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 308.3 1,031.1 0% 1031.1 - NA

Sulfur Dioxide (SO2) 125.0 44.8 80% 9.0 35.8 116,801

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm

3 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV016 WWESP 9/7/2006 Page 38 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.c: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,814,356

Instrumentation 10% of control device cost (A) 381,436

MN Sales Taxes 6.5% of control device cost (A) 247,933

Freight 5% of control device cost (A) 190,718

Purchased Equipment Total (B) 22% 4,634,443

Installation

Foundations & supports 4% of purchased equip cost (B) 185,378

Handling & erection 50% of purchased equip cost (B) 2,317,221

Electrical 8% of purchased equip cost (B) 370,755

Piping 1% of purchased equip cost (B) 46,344

Insulation 2% of purchased equip cost (B) 92,689

Painting 2% of purchased equip cost (B) 92,689

Installation Subtotal Standard Expenses 67% 3,105,077

Total Direct Capital Cost, DC 7,739,520

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 926,889

Construction & field expenses 20% of purchased equip cost (B) 926,889

Contractor fees 10% of purchased equip cost (B) 463,444

Start-up 1% of purchased equip cost (B) 46,344

Performance test 1% of purchased equip cost (B) 46,344

Model Studies 2% of purchased equip cost (B) 92,689

Contingencies 3% of purchased equip cost (B) 139,033

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,641,632

Total Capital Investment (TCI) = DC + IC 10,381,152

Retrofit multiplier3

60% of TCI 6,228,691

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 22,809,844

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568

Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Labor 32.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 4,125

Maintenance Materials 1.00 % of Maintenance Labor 38,144

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 486 kW-hr, 7946 hr/yr, 93% utilization 182,993

Water 0.28 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization 126,112

WW Treat Neutralization 1.69 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization 769,057

Caustic 305.96 $/ton, 313 lb/hr, 7946 hr/yr, 93% utilization 353,282

Total Annual Direct Operating Costs 1,546,816

Indirect Operating Costs

Overhead 60% of total labor and material costs 69,223

Administration (2% total capital costs) 2% of total capital costs (TCI) 207,623

Property tax (1% total capital costs) 1% of total capital costs (TCI) 103,812

Insurance (1% total capital costs) 1% of total capital costs (TCI) 103,812

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,153,088

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,637,557

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,184,373

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV016 WWESP 9/7/2006 Page 39 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.c: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit

Amount Required 0

Total Rep Parts Cost 0

Installation Labor 0

Total Installed Cost 0

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O kW

Fan Power 205,478 10 371.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 19.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 48,598 94.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 485.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 1027.39 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 312.50 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 9,535 15% of Operator Costs

Maintenance

Maint Labor 32.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 38,144 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 485.5 kW-hr 3,588,105 182,993 $/kwh, 486 kW-hr, 7946 hr/yr, 93% utilization

Water 0.28 $/mgal 1,027.4 gpm 455,531 126,112 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/mgal 1,027.4 gpm 455,531 769,057 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization

Caustic 305.96 $/ton 312.5 lb/hr 1,155 353,282 $/ton, 313 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV016 WWESP 9/7/2006 Page 40 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.d: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 017

Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,814,356

 Purchased Equipment Total (B) 22% of control device cost (A) 4,634,443

 Installation - Standard Costs 67% of purchased equip cost (B) 3,105,077

 Installation - Site Specific Costs 6,200,000

 Installation Total 3,105,077

 Total Direct Capital Cost, DC 7,739,520

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,641,632

Total Capital Investment (TCI) = DC + IC 22,809,844

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,546,816

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,637,557

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,184,373

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 424.3 1,419.2 0% 1419.2 - NA

Sulfur Dioxide (SO2) 125.0 44.8 80% 9.0 35.8 116,801

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm

3 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV017 WWESP 9/7/2006 Page 41 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.d: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,814,356

Instrumentation 10% of control device cost (A) 381,436

MN Sales Taxes 6.5% of control device cost (A) 247,933

Freight 5% of control device cost (A) 190,718

Purchased Equipment Total (B) 22% 4,634,443

Installation

Foundations & supports 4% of purchased equip cost (B) 185,378

Handling & erection 50% of purchased equip cost (B) 2,317,221

Electrical 8% of purchased equip cost (B) 370,755

Piping 1% of purchased equip cost (B) 46,344

Insulation 2% of purchased equip cost (B) 92,689

Painting 2% of purchased equip cost (B) 92,689

Installation Subtotal Standard Expenses 67% 3,105,077

Total Direct Capital Cost, DC 7,739,520

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 926,889

Construction & field expenses 20% of purchased equip cost (B) 926,889

Contractor fees 10% of purchased equip cost (B) 463,444

Start-up 1% of purchased equip cost (B) 46,344

Performance test 1% of purchased equip cost (B) 46,344

Model Studies 2% of purchased equip cost (B) 92,689

Contingencies 3% of purchased equip cost (B) 139,033

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,641,632

Total Capital Investment (TCI) = DC + IC 10,381,152

Retrofit multiplier3

60% of TCI 6,228,691

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 22,809,844

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 32.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 63,568

Supervisor 15% 15% of Operator Costs 9,535

Maintenance

Maintenance Labor 32.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 4,125

Maintenance Materials 1.00 % of Maintenance Labor 38,144

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 486 kW-hr, 7946 hr/yr, 93% utilization 182,993

Water 0.28 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization 126,112

WW Treat Neutralization 1.69 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization 769,057

Caustic 305.96 $/ton, 313 lb/hr, 7946 hr/yr, 93% utilization 353,282

Total Annual Direct Operating Costs 1,546,816

Indirect Operating Costs

Overhead 60% of total labor and material costs 69,223

Administration (2% total capital costs) 2% of total capital costs (TCI) 207,623

Property tax (1% total capital costs) 1% of total capital costs (TCI) 103,812

Insurance (1% total capital costs) 1% of total capital costs (TCI) 103,812

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,153,088

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,637,557

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,184,373

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV017 WWESP 9/7/2006 Page 42 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.d: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit

Amount Required 0

Total Rep Parts Cost 0

Installation Labor 0

Total Installed Cost 0

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O kW

Fan Power 205,478 10 371.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 19.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 48,598 94.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 485.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 1027.39 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 312.50 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32 $/Hr 2.0 hr/8 hr shift 1,987 63,568 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 9,535 15% of Operator Costs

Maintenance

Maint Labor 32.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 38,144 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 485.5 kW-hr 3,588,105 182,993 $/kwh, 486 kW-hr, 7946 hr/yr, 93% utilization

Water 0.28 $/mgal 1,027.4 gpm 455,531 126,112 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/mgal 1,027.4 gpm 455,531 769,057 $/mgal, 1,027 gpm, 7946 hr/yr, 93% utilization

Caustic 305.96 $/ton 312.5 lb/hr 1,155 353,282 $/ton, 313 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control Costs

SV017 WWESP 9/7/2006 Page 43 of 55
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.a: SO2 Control - Wet Scrubber

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 014

Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 2,637,401

 Purchased Equipment Total (B) 22% of control device cost (A) 3,204,443

 Installation - Standard Costs 85% of purchased equip cost (B) 2,723,776

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,723,776

 Total Direct Capital Cost, DC 5,928,219

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 480,666

Total Capital Investment (TCI) = DC + IC 16,454,216

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 390,244

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,839,553

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,229,797

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 155.4 520.0 0% 520.0 - NA

Sulfur Dioxide (SO2) 125.0 44.8 60% 17.9 26.9 82,989

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

SV014 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.a: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment1

 (A)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,637,401

Instrumentation 10% of control device cost (A) 263,740

MN Sales Taxes 7% of control device cost (A) 171,431

Freight 5% of control device cost (A) 131,870

Purchased Equipment Total (B) 22% 3,204,443

Installation

Foundations & supports 12% of purchased equip cost (B) 384,533

Handling & erection 40% of purchased equip cost (B) 1,281,777

Electrical 1% of purchased equip cost (B) 32,044

Piping 30% of purchased equip cost (B) 961,333

Insulation 1% of purchased equip cost (B) 32,044

Painting 1% of purchased equip cost (B) 32,044

Installation Subtotal Standard Expenses 85% 2,723,776

Total Direct Capital Cost, DC 5,928,219

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 160,222

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 160,222

Start-up 1% of purchased equip cost (B) 32,044

Performance test 1% of purchased equip cost (B) 32,044

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 96,133

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 480,666

Total Capital Investment (TCI) = DC + IC 6,408,885

Retrofit multiplier560% of TCI 3,845,331

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 16,454,216

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Supervisor 15% 15% of Operator Costs 2,384

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Maintenance Materials 100% of maintenance labor costs 15,892

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 423 kW-hr, 7946 hr/yr, 93% utilization 159,257

Water 0.28 $/kgal, 193 gpm, 7946 hr/yr, 93% utilization 23,667

WW Treat Neutralization 1.69 $/kgal, 156 gpm, 7946 hr/yr, 93% utilization 116,897

Lime 90.80 $/ton, 120 lb/hr, 7946 hr/yr, 93% utilization 40,364

Total Annual Direct Operating Costs 390,244

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036

Administration (2% total capital costs) 2% of total capital costs (TCI) 128,178

Property tax (1% total capital costs) 1% of total capital costs (TCI) 64,089

Insurance (1% total capital costs) 1% of total capital costs (TCI) 64,089

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,553,162

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,839,553

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,229,797

See Summary page for notes and assumptions

SV014 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.a: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 205,478 8.55 0.7 - 293.6 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 7,808 gpm 1 60 0.7 - 125.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 193 gpm 1 60 0.7 - 3.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 422.6

Reagent Use & Other Operating Costs

Caustic Use 125.00 lb/hr SO2 2.50 lb NaOH/lb SO2 312.50 lb/hr Caustic

Lime Use 125.00 lb/hr SO2 0.96 lb Lime/lb SO2 120.31 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio 

Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf

Circulating Water Rate2

7,808 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 193 gpm

Evaporation Loss4 = 36.64 gpm

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 2,384

Maintenance

Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 422.6 kW-hr 3,122,678 159,257 $/kwh, 423 kW-hr, 7946 hr/yr, 93% utilization

Water 0.28 $/kgal 192.8 gpm 85,486 23,667 $/kgal, 193 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 156.2 gpm 69,241 116,897 $/kgal, 156 gpm, 7946 hr/yr, 93% utilization

Lime 90.8 $/ton 120.3 lb/hr 445 40,364 $/ton, 120 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

SV014 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.a: SO2 Control - Wet Scrubber

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 015

Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 2,637,401

 Purchased Equipment Total (B) 22% of control device cost (A) 3,204,443

 Installation - Standard Costs 85% of purchased equip cost (B) 2,723,776

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,723,776

 Total Direct Capital Cost, DC 5,928,219

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 480,666

Total Capital Investment (TCI) = DC + IC 16,454,216

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 390,244

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,839,553

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,229,797

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 200.0 669.0 0% 669.0 - NA

Sulfur Dioxide (SO2) 125.0 44.8 60% 17.9 26.9 82,989

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

SV015 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.a: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,637,401

Instrumentation 10% of control device cost (A) 263,740

MN Sales Taxes 7% of control device cost (A) 171,431

Freight 5% of control device cost (A) 131,870

Purchased Equipment Total (B) 22% 3,204,443

Installation

Foundations & supports 12% of purchased equip cost (B) 384,533

Handling & erection 40% of purchased equip cost (B) 1,281,777

Electrical 1% of purchased equip cost (B) 32,044

Piping 30% of purchased equip cost (B) 961,333

Insulation 1% of purchased equip cost (B) 32,044

Painting 1% of purchased equip cost (B) 32,044

Installation Subtotal Standard Expenses 85% 2,723,776

Total Direct Capital Cost, DC 5,928,219

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 160,222

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 160,222

Start-up 1% of purchased equip cost (B) 32,044

Performance test 1% of purchased equip cost (B) 32,044

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 96,133

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 480,666

Total Capital Investment (TCI) = DC + IC 6,408,885

Retrofit multiplier560% of TCI 3,845,331

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 16,454,216

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Supervisor 15% 15% of Operator Costs 2,384

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Maintenance Materials 100% of maintenance labor costs 15,892

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 423 kW-hr, 7946 hr/yr, 93% utilization 159,257

Water 0.28 $/kgal, 193 gpm, 7946 hr/yr, 93% utilization 23,667

WW Treat Neutralization 1.69 $/kgal, 156 gpm, 7946 hr/yr, 93% utilization 116,897

Lime 90.80 $/ton, 120 lb/hr, 7946 hr/yr, 93% utilization 40,364

Total Annual Direct Operating Costs 390,244

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036

Administration (2% total capital costs) 2% of total capital costs (TCI) 128,178

Property tax (1% total capital costs) 1% of total capital costs (TCI) 64,089

Insurance (1% total capital costs) 1% of total capital costs (TCI) 64,089

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,553,162

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,839,553

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,229,797

See Summary page for notes and assumptions

SV015 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.a: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 205,478 8.55 0.7 - 293.6 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 7,808 gpm 1 60 0.7 - 125.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 193 gpm 1 60 0.7 - 3.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 422.6

Reagent Use & Other Operating Costs

Caustic Use 125.00 lb/hr SO2 2.50 lb NaOH/lb SO2 312.50 lb/hr Caustic

Lime Use 125.00 lb/hr SO2 0.96 lb Lime/lb SO2 120.31 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio 

Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf

Circulating Water Rate2

7,808 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 193 gpm

Evaporation Loss4

 = 36.64 gpm

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 2,384

Maintenance

Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 422.6 kW-hr 3,122,678 159,257 $/kwh, 423 kW-hr, 7946 hr/yr, 93% utilization

Water 0.28 $/kgal 192.8 gpm 85,486 23,667 $/kgal, 193 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 156.2 gpm 69,241 116,897 $/kgal, 156 gpm, 7946 hr/yr, 93% utilization

Lime 90.8 $/ton 120.3 lb/hr 445 40,364 $/ton, 120 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

SV015 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.c: SO2 Control - Wet Scrubber

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 016

Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 2,637,401

 Purchased Equipment Total (B) 22% of control device cost (A) 3,204,443

 Installation - Standard Costs 85% of purchased equip cost (B) 2,723,776

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,723,776

 Total Direct Capital Cost, DC 5,928,219

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 480,666

Total Capital Investment (TCI) = DC + IC 16,454,216

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 390,244

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,839,553

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,229,797

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 308.3 1,031.1 0% 1031.1 - NA

Sulfur Dioxide (SO2) 125.0 44.8 60% 17.9 26.9 82,989

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

SV016 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.c: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,637,401

Instrumentation 10% of control device cost (A) 263,740

MN Sales Taxes 7% of control device cost (A) 171,431

Freight 5% of control device cost (A) 131,870

Purchased Equipment Total (B) 22% 3,204,443

Installation

Foundations & supports 12% of purchased equip cost (B) 384,533

Handling & erection 40% of purchased equip cost (B) 1,281,777

Electrical 1% of purchased equip cost (B) 32,044

Piping 30% of purchased equip cost (B) 961,333

Insulation 1% of purchased equip cost (B) 32,044

Painting 1% of purchased equip cost (B) 32,044

Installation Subtotal Standard Expenses 85% 2,723,776

Total Direct Capital Cost, DC 5,928,219

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 160,222

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 160,222

Start-up 1% of purchased equip cost (B) 32,044

Performance test 1% of purchased equip cost (B) 32,044

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 96,133

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 480,666

Total Capital Investment (TCI) = DC + IC 6,408,885

Retrofit multiplier560% of TCI 3,845,331

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 16,454,216

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Supervisor 15% 15% of Operator Costs 2,384

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Maintenance Materials 100% of maintenance labor costs 15,892

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 423 kW-hr, 7946 hr/yr, 93% utilization 159,257

Water 0.28 $/kgal, 193 gpm, 7946 hr/yr, 93% utilization 23,667

WW Treat Neutralization 1.69 $/kgal, 156 gpm, 7946 hr/yr, 93% utilization 116,897

Lime 90.80 $/ton, 120 lb/hr, 7946 hr/yr, 93% utilization 40,364

Total Annual Direct Operating Costs 390,244

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036

Administration (2% total capital costs) 2% of total capital costs (TCI) 128,178

Property tax (1% total capital costs) 1% of total capital costs (TCI) 64,089

Insurance (1% total capital costs) 1% of total capital costs (TCI) 64,089

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,553,162

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,839,553

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,229,797

See Summary page for notes and assumptions

SV016 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.c: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 205,478 8.55 0.7 - 293.6 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 7,808 gpm 1 60 0.7 - 125.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 193 gpm 1 60 0.7 - 3.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 422.6

Reagent Use & Other Operating Costs

Caustic Use 125.00 lb/hr SO2 2.50 lb NaOH/lb SO2 312.50 lb/hr Caustic

Lime Use 125.00 lb/hr SO2 0.96 lb Lime/lb SO2 120.31 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio 

Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf

Circulating Water Rate2

7,808 gpm

Water Makeup Rate/WW Disch3

 = 2.0% of circulating water rate + evap. loss = 193 gpm

Evaporation Loss4 = 36.64 gpm

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 2,384

Maintenance

Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 422.6 kW-hr 3,122,678 159,257 $/kwh, 423 kW-hr, 7946 hr/yr, 93% utilization

Water 0.28 $/kgal 192.8 gpm 85,486 23,667 $/kgal, 193 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 156.2 gpm 69,241 116,897 $/kgal, 156 gpm, 7946 hr/yr, 93% utilization

Lime 90.8 $/ton 120.3 lb/hr 445 40,364 $/ton, 120 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

SV016 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.d: SO2 Control - Wet Scrubber

Operating Unit: Indurating Furnace

Emission Unit Number EU 026 Stack/Vent Number SV 017

Standardized Flow Rate 173,108 scfm @ 32o F

Expected Utilization Rate 93% Temperature 124 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 205,478 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 185,775 scfm @ 68o F

Dry Std Flow Rate 166,268 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 2,637,401

 Purchased Equipment Total (B) 22% of control device cost (A) 3,204,443

 Installation - Standard Costs 85% of purchased equip cost (B) 2,723,776

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,723,776

 Total Direct Capital Cost, DC 5,928,219

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 480,666

Total Capital Investment (TCI) = DC + IC 16,454,216

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 390,244

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,839,553

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,229,797

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 424.3 1,419.2 0% 1419.2 - NA

Sulfur Dioxide (SO2) 125.0 44.8 60% 17.9 26.9 82,989

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

SV017 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.d: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,637,401

Instrumentation 10% of control device cost (A) 263,740

MN Sales Taxes 7% of control device cost (A) 171,431

Freight 5% of control device cost (A) 131,870

Purchased Equipment Total (B) 22% 3,204,443

Installation

Foundations & supports 12% of purchased equip cost (B) 384,533

Handling & erection 40% of purchased equip cost (B) 1,281,777

Electrical 1% of purchased equip cost (B) 32,044

Piping 30% of purchased equip cost (B) 961,333

Insulation 1% of purchased equip cost (B) 32,044

Painting 1% of purchased equip cost (B) 32,044

Installation Subtotal Standard Expenses 85% 2,723,776

Total Direct Capital Cost, DC 5,928,219

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 160,222

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 160,222

Start-up 1% of purchased equip cost (B) 32,044

Performance test 1% of purchased equip cost (B) 32,044

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 96,133

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 480,666

Total Capital Investment (TCI) = DC + IC 6,408,885

Retrofit multiplier560% of TCI 3,845,331

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 16,454,216

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Supervisor 15% 15% of Operator Costs 2,384

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 15,892

Maintenance Materials 100% of maintenance labor costs 15,892

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 423 kW-hr, 7946 hr/yr, 93% utilization 159,257

Water 0.28 $/kgal, 193 gpm, 7946 hr/yr, 93% utilization 23,667

WW Treat Neutralization 1.69 $/kgal, 156 gpm, 7946 hr/yr, 93% utilization 116,897

Lime 90.80 $/ton, 120 lb/hr, 7946 hr/yr, 93% utilization 40,364

Total Annual Direct Operating Costs 390,244

Indirect Operating Costs

Overhead 60% of total labor and material costs 30,036

Administration (2% total capital costs) 2% of total capital costs (TCI) 128,178

Property tax (1% total capital costs) 1% of total capital costs (TCI) 64,089

Insurance (1% total capital costs) 1% of total capital costs (TCI) 64,089

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,553,162

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,839,553

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,229,797

See Summary page for notes and assumptions

SV017 Wet Scrubber
Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.d: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 205,478 8.55 0.7 - 293.6 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 7,808 gpm 1 60 0.7 - 125.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 193 gpm 1 60 0.7 - 3.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 422.6

Reagent Use & Other Operating Costs

Caustic Use 125.00 lb/hr SO2 2.50 lb NaOH/lb SO2 312.50 lb/hr Caustic

Lime Use 125.00 lb/hr SO2 0.96 lb Lime/lb SO2 120.31 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio 

Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf

Circulating Water Rate2

7,808 gpm

Water Makeup Rate/WW Disch3

 = 2.0% of circulating water rate + evap. loss = 193 gpm

Evaporation Loss4 = 36.64 gpm

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 2,384

Maintenance

Maint Labor 32.00 $/Hr 0.5 hr/8 hr shift 497 15,892 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 15,892 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 422.6 kW-hr 3,122,678 159,257 $/kwh, 423 kW-hr, 7946 hr/yr, 93% utilization

Water 0.28 $/kgal 192.8 gpm 85,486 23,667 $/kgal, 193 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 156.2 gpm 69,241 116,897 $/kgal, 156 gpm, 7946 hr/yr, 93% utilization

Lime 90.8 $/ton 120.3 lb/hr 445 40,364 $/ton, 120 lb/hr, 7946 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

SV017 Wet Scrubber
Memorandum 

To: Margaret McCourtney 

From: Andrew Skoglund 

Subject: Revisions per your comments 

Date: May 16, 2006 

Project: Taconite Industry BART Clients 

c: Mary Jean Fenske, Barr Taconite BART Project Team, Taconite BART Industry Reps. 

Attached is a revised version of our proposed changes to the BART-analysis modeling protocol. They are 

set up in the format described in Appendix G to the modeling protocol. The proposed OZONE.DAT files 

and a figure depicting the proposed modeling domain are also included, as requested. 

The PSD modeling protocols referenced for the CALMET parameters are based on PSD modeling 

protocols submitted for Mesabi Nugget LLC, Northshore Mining Line 5 Restart, and Minnesota Steel 

Industries LLC. Each of these facilities has submitted a modeling protocol using MM4/MM5 data with 

observations for review. The values noted are representative of those that were used after receiving 

comment from the FLMs. The Minnesota Steel Industries modeling protocol was submitted in May 2005, 

with FLM response on June 14, 2005. FLMs approved of the submitted values. 

 

The comments section regarding receptors has been revised to indicate that we will be using a subset of the 

original MPCA receptor group, using only BWCA and Voyageurs receptors. 

Thank you, 

Andrew J. Skoglund 

Barr Engineering Co. 

(952) 832 - 2685 

askoglund@barr.com 

Barr Engineering Company Appendix B 

4700 West 77th Street • Minneapolis, MN 55435-4803 

Phone: 952-832-2600 • Fax: 952-832-2601 • www.barr.com An EEO Employer

Minneapolis, MN • Hibbing, MN • Duluth, MN • Ann Arbor, MI • Jefferson City, MO 
!;

N

Barr Footer: Date: 6/3/2004 4:10:56 PM File: C:\Temp\Test.mxd User: bal

0 100

Kilometers

MODELING DOMAIN

Taconite BART Modeling

Taconite Industry Group

Minnesota

0 100

Miles

Legend

Modeling Domain

Class I Area

BWCA

Voyageurs
TERREL

Variable Description Value Default Comments

GTOPO30 GTOPO 30-sec data - n/a 1 degree DEM files will be used

XREFKM Reference point coordinates for grid 168 n/aYREFKM Reference point coordinates for grid 720 n/a

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

CTGPROC

Variable Description Value Default Comments

XREFKM Reference point coordinates for grid 168 n/aYREFKM Reference point coordinates for grid 720 n/a

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

CALMET

Variable Description Value Default Comments

NUSTA Number of upper air stations 4 14898, 14918, 94983, 4837

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

XORIGKM Reference point coordinates for grid 168 n/a

YORIGKM Reference point coordinates for grid 720 n/a

NOOBS No Observation Mode 0 Y Include Surface, Upper Air and 

NSSTA Number of Surface Stations 74 n/a 74 surface weather stationsNPSTA Number of Precipitation Stations 68 n/a 68 precipitation stations

RMAX2 Maximum radius of influence over land aloft 50 n/a Similar to PSD with ObservatioRMAX3 Maximum radius of influence over water 500 n/a Similar to PSD with Observatio

R1 Relative weighting of the first guess field and observations in the surface layer (km) 10 n/a Similar to PSD with ObservatioR2 Relative weighting of the first guess field and observations in the layers aloft (km) 20 n/a Similar to PSD with Observatio

ISURFT Surface met. Stations to use for the surface temperature - n/a Hibbing Met station

IUPT Upper air station to use for the domain scale lapse rate - n/a International Falls Upper Air sta

ITPROG 3D temperature from observations or from prognostic data? 0 Y Inclusion of Surface and Upper 

TRADKM Radius of influence for temperature interpolation 500 Y Similar to PSD with Observatio

JWAT1 Beginning land use category for temperature interpolation over water 99 n/a CALMET may fail when using 5JWAT2 Ending land use category for temperature interpolation over water 99 n/a CALMET may fail when using 5

SIGMAP Radius of influence (km) 100 Y Precipitation Observations are 

Input Group 0bInput Group 2Input Group 2Input Group 2Input Group 4Input Group 5Input Group 6
CALPUFF

Variable Description Value Default Comments

NX Number of X grid cells in met grid 40 n/a

NY Number of Y grid cells in met grid 30 n/a

XORIGKM Reference point coordinates for met grid 168 n/a

YORIGKM Reference point coordinates for met grid 720 n/a

IBCOMP X index of LL corner 1 n/a

JBCOMP Y index of LL corner 1 n/a

IECOMP X index of UR corner 40 n/a

JECOMP Y index of UR corner 30 n/a

MOZ Ozone data input option 1 N OZONE.DAT from MN, WI, an

NREC Number of non-gridded receptors 1222 n/a Using only BWCA and Voyage

Input Group 11Input Group 17Input Group 4
Appendix C 

1. CALPUFF Modeling System 

The CALPUFF Modeling System is the required model for determining visual impacts at long distances 

from sources. This model was used in accordance with the guidelines found in the Best Available 

Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of 

Minnesota, Final1

, with the modifications found in Appendix B. 

The CALPUFF system consists of three main components (CALMET, CALPUFF and CALPOST) and a 

number of pre-processing programs. These pre-processing programs are designed to prepare available 

meteorological and geophysical data for input into CALMET. Each of these modeling components are 

described below: 

• CALMET is a meteorological model that develops hourly wind and temperature fields on a threedimensional gridded modeling domain. Associated two-dimensional fields such as mixing 

heights, terrain elevations, land use categories and dispersion properties are also included in the 

file produced by CALMET. 

• CALPUFF is a transport and dispersion model that follows the “puffs” of material emitted from 

one or more sources as they travel downwind. CALPUFF simulates dispersion and chemical 

transformations as each puff moves away from the source, using the multi-dimensional grids 

generated by CALMET. 

• CALPUFF produces an output file containing hourly concentrations of pollutants which are 

processed by CALPOST to yield estimates of ambient air extinction coefficients and related 

measures of visibility impairment at selected averaging times and locations. 

Lambert conformal coordinates (LCC) were used in the modeling. To accommodate this coordinate 

system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets 

and overcome other size limitations, CALPUFF was recompiled with several size parameters increased. 

 

1

 MPCA, Final March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources 

Subject to BART in the State of Minnesota. 
CALMET 

Three years (2002-2004) of MM5 prognostic mesoscale meteorological data, surface weather data, 

precipitation data, and upper air data were used to generate the CALMET data set for use in the 

CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells 

(north-south) with a grid spacing of 12 km. This grid encompasses the facility sources, the BWCAW and 

Voyageurs National Park. USGS digital elevation maps (DEMs) and land use land cover (LULC) files 

required by CALMET were obtained from the MPCA. 

CALPUFF 

CALPUFF model input files were set up for each year of CALMET data. Model parameters were set to 

the values specified in the revised modeling protocol (Appendix B). 

The CALPUFF modeling considered the emission of SO2, NOx, PM10 (coarse particulate matter, 2.5μ to 

10μ), and PM2.5 (fine particulate matter, under 2.5μ). 

The CALPUFF modeling also tracked SO4, NO3, and HNO3, which are generated by the chemical 

transformation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates 

of transformation. The MESOPUFF-generated transformation rates are a function of the background 

ozone and ammonia concentrations, the former set by observations, the latter using monthly average 

values provided by MPCA. 

The CALPUFF modeling used the receptors for the Boundary Water Canoe Area Wilderness and 

Voyageurs National Park provided by the MPCA in the original subject-to-BART modeling files. 

CALPOST 

CALPOST converted the hourly concentration and monthly average relative humidity files generated by 

CALPUFF into 24-hour time-averaged extinction coefficients. These emissions-based extinction 

coefficients were compared to the 20% best days background extinction coefficients designated in the 

modeling protocol. 
2. Visibility Impacts Analysis 

As indicated in EPA’s final BART guidance2, states are required to consider the degree of visibility 

improvement resulting from the retrofit technology in combination with other factors, such as economics 

and technical feasibility, when determining BART for an individual source. 

The CALPUFF program models how a pollutant contributes to visibility impairment with consideration 

for the background atmospheric ammonia, ozone and meteorological data. Additionally, the interactions 

between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part in predicting 

impairment. It is therefore important to take a multi-pollutant approach when assessing visibility impacts. 

Assessing Visibility Impairment 

The visibility impairment contribution for different emission rate scenarios can be determined using the 

CALMET, CALPUFF, and CALPOST modeling templates provided by the Minnesota Pollution Control 

Agency (MPCA). The Minnesota BART modeling protocol3 describes the CALPUFF model inputs 

including the meteorological data set and background atmospheric ammonia and ozone concentrations 

along with the functions of the CALPOST post processing. There are two criteria with which to assess the 

expected post-BART visibility improvement: the 98th percentile delta deciview and the number of days 

on which a source exceeds an impairment threshold. 

As defined by federal guidance4

 a source "contributes to visibility impairment” if the 98th percentile of 

any year’s modeling results meets or exceeds the threshold of five-tenths of a deciview (dV) at a federally 

protected Class I area receptor. The pre-BART evaluation of this criterion conducted by the Minnesota 

Pollution Control Agency identified this facility as having BART eligible source(s)5

 that could cause or 

contribute to visibility impairment at Minnesota Class I areas. In addition to establishing whether or not a 

source contributes to impairment on the 98th percentile, the severity of the visibility impairment 

contribution or reasonably attributed visibility impairment can be gauged by assessing the number of days 

on which a source exceeds 0.5 dV. 

 

2

 40 CFR 51, Appendix Y. 

3

 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota. 

4

 40 CFR 51, Appendix Y. 

5

 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota. 
Predicting 24-Hour Maximum Emission Rates 

Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for preBART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should 

reflect a maximum 24-hour average basis. 

Table 4-1 & Table 6-2 within this report describe the pre and post-BART model input parameters, 

respectively. 

Modeled Results 

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for 

the predicted post-BART emission scenario(s). Results for the 98th percentile and number of days above 

0.5 dV at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are 

included in Table 6-3. 
N

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100

Meters

Ispat Inland Aerial Photo
Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

Combustion Controls

1 Overfire Air (OFA) Y N --- --- --- x NOx formation front is not stationary in an indurating furnace Combustion air is separated into p

achieve complete burnout and to e

than NOx

2 External Flue Gas Recirculation (EFGR) Y Y N --- --- x x Mixes flue gas with combustion ai

therefore reduces flame temperatu

3 Low-NOx Burners Y Y

Y 

(preheat 

burners)

Y 

(preheat 

burners)

10-20% x x x

Higher control efficiency at the burner, but the listed control efficiency is for 

the entire furnace.

Burners are designed to reduce Noxygen, flame temperature, and/o

4 Induced Flue Gas Recirculation Burners Y Y N --- --- x x x Need to be upfired. Need convective loop to get gas recirculated Draws flue gas to dilute the fuel in 5 Low Excess Air Y N --- --- --- x Need high O2 for process requirements and product quality Reduces oxygen content in flue g

6 Burners out of Service (BOOS) Y N --- --- --- x Need capacity of all burners for worst case scenario Shut off the fuel flow from one bur

lean zones

7 Fuel Biasing Y N --- --- --- x Power plant technology

Combustion is staged by diverting lower ones or from the center to th

fuel-lean zones 

8 Reburning Y N --- --- --- x Kiln configuration not correct for this technology.

Part of the total fuel heat input is iabove the primary (main burners) (re-burn zone), where hydrocarbo

elemental nitrogen

9 Load Reduction N --- --- --- --- x Power plant technology -product demand side solution This is a strategy to reduce load o

electrical demand throught efficien

10 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

Site-specific x decrease amount of fuel required 

11 Coal Drying Y N --- --- --- x Applies only to facilities that burn coal Dry coal will increase the as-burn

required to be burned. Specific e

12

Coal Addition to Pellets with 

Low Excess Air in the 

Induration Furnace

N --- --- --- --- x Check on status of research Reduce flame temperature and en

13 Ported Kilns Y Y

Y

(grate-kilns 

only)

N

(Metso says 

no NOx 

improvement) --- x x Applicable to grate kilns. Provides additional oxygen for pe

energy use of the kiln 

14 Combustion Zone Cooling Y N --- --- --- x Boiler technology Cooling of the primary flame zone 

surfaces

15 Alternate Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Site-specific x x

Requires case by case analysis. Typically, facilities experience lower NOx when burning solid fuels.

Lower combustion temps with soliNOx by using a fuel with less nitro

16 Oxygen Enhanced Combustion N --- --- --- --- x Research level A small fraction of the combustion 
Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

17 Preheat Combustion N --- --- --- --- x Research level

Pulverized coal preheated and vocompounds are released in a contnitrogen compounds are reduced 

18 ROFA-ROTAMIX Y N --- --- --- x

Can't achieve correct temperature window (1400-1800F). Too hot in kiln 

too cold in reheat

Combination of OFA and SCR. Wutilizes high velocity overfire air. Awith ammonia injection (Rotamix)

19 NOx CEMS Y N --- --- --- x x Optimization of combustion

20 Parametric Monitoring Y N --- --- --- x x Optimization of combustion

38 Catalyst Injection (EPS Technologies) N --- --- --- --- x Research Level A combustion catalyst is directly in

delivered to the combustion site, i

the dynamics of the flame.

Post Combustion Controls

21 Non-Selective Catalytic Reduction (NSCR) Y N --- --- --- x x For clean services. Too much stuff in flue gas would poison catalyst Under near stoichiometric conditio

reduced by CO, resulting in nitrog

22 Low Temperature Oxidation (LTO) - Tri-NOx® Y N --- --- --- x x Used for higher flue gas concentrations Utilizes an oxidizing agent such a

including NOx

23 Low Temperature Oxidation (LTO) - LoTOx Y N --- --- --- x x x Has been included as an "applicable and available" technology in recent BACT analyses from multiple facilities. Utilizes an oxidizing agent such a

including NOx

24 Selective Catalytic Reduction (SCR) Y Y Y Y 80% x x x

Need to inject at appropriate temperature (reheat will be required). Applicable on clean side only.Although this hasn't been demonstrated on an indurating furnace, the stream characteristics appear to make this technology feasible.

Ammonia (NH3) is injected into the 

catalyst to convert NOx into N2 an

25 Regenerative SCR Y N --- --- --- x Clean side only

26 Selective Non-Catalytic Reduction (SNCR) Y N --- --- --- x x Can't achieve correct temperature window (1400-1800F). Too hot in kiln too cold in reheat Urea or ammonia-based chemical

convert NO to molecular nitrogen, 

27 Adsorption N --- --- --- --- x Still in research stages. Use of char (activated carbon) to 

28 Absorption Y N --- --- --- x Similar to TriNOx

Use of water, hydroxide and carbosolutions, molten alkali carbonate

nitrogen.

29 Oxidizer Y N --- --- --- x Redundant to regenerative SCR

Gas stream is sent through the re

direct fired oxidizer where pollutandestroyed.
Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

30 SNOX N --- --- --- --- x Early commercial development stage

Catalytic reduction of NOx in the p

catalytic oxidation of SO2 to SO3. 

passes through a novel glass-tube 

hydrated to H2SO4 vapor and then 

sulfuric acid (H2SO4).

31 SOx-NOx-Rox-Box N --- --- --- --- x Technology has not been demonstrated Dry sorbent injection upstream of 

ammonia injection upstream of a z(SCR) catalyst incorporated in the 

32 Electron (E-Beam) Process N --- --- --- --- x No operating commercial applications on coal Electron beam irradiation in the pr

conversion of sulfur and nitrogen easily collected by conventional m

33 Electrocatalytic Oxidation N --- --- --- --- x Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NO

dioxide (NO2), sulfuric acid, and m

thermal plasma.On recent project, the vender was applications.

34 NOXSO N --- --- --- --- Commercial version of adsorption. Limited experience (proof-of-concept 

tests).

Uses a regenerable sorbent to sim

flue gas from coal-fired utility and SO2 is converted to a saleable su

sulfur, or sulfuric acid) and the NO

35 Copper-Oxide N --- --- --- --- x Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with cop

of alumina, to form copper sulfatebefore the absorption reactor and reaction occurs that reduces the nregeneration step, the copper sulfreducing agent, such as natural gSO2.

36 Cold Plasma N --- --- --- --- x Research Level

37 Biofilters Y N --- --- --- x Not applicable to furnaces.

Gas stream is passed through a fiPollutants are adsorbed and degr

the products carbon dioxide and w

38 Pahlman Process N --- --- --- --- x Research Level

Gas stream is passed through a fideveloped, small-particle, high-subeen deployed. Pollutants are rem

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports
Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Tacondistributed without the full texnot taken out of context.

Reference No.1 SO2 Pollution Control Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency

MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other2 Comments B

1 Wet Scrubbing (High Efficiency) Y Y Y Y 90-95% x x x Absorption and reaction using an al

2 Wet Scrubbing (Low Efficiency) Y Y Y Y <50% x x x Absorption and reaction using an al3 Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y 80% x x Suspended particles are separated f

collected in hoppers

4 Dry sorbent injection Y Y Y N --- x x x

Pulverized lime or limestone is direfilter. Dry sorption of SO2 onto the 

particles are collected with a fabric 

5 Spray Dryer Absorption (SDA) Y Y Y N --- x x Lime slurry is sprayed into an absor

slurry, forming CaSO3/CaSO4

6 Alternative Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Site-specific x x Natural gas is base case Use a fuel with lower sulfur conten

7 Load Reduction N --- --- --- --- x Power plant technology This is a strategy to reduce load on 

demand throught efficiency project

8 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

Site-specific x decrease amount of fuel required to 

9 Coal Drying Y N --- --- --- x Applies only to facilities that burn coal Dry coal will increase the as-burned 

to be burned. Specific energy effici

10 Bio Filters N --- --- --- --- x Research level

Gas stream passes through a packe

supports the growth of active bactebiodegraded or biotransformed into water, chloride ion in water, sulfate 

11 CANSOLV Regenerable SO2 N --- --- --- --- x Research level

An aqueous solution of proprietary 

countercurrent absorption tower. Tstripping, giving a byproduct of pur

recycling to the absorber.

12 Pahlman Process N --- --- --- --- x Research level

Gas stream is passed through a filteparticle, high-surface area metal oxremoved from the gases by adsorpt

13 SOx-NOx-Rox-Box N --- --- --- --- x Technology has not been demonstrated

Dry sorbent injection upstream of tinjection upstream of a zeolitic seleincorporated in the baghouse to red

14 Electron (E-Beam) Process N --- --- --- --- x No operating commercial applications on coal Electron beam irradiation in the pre

conversion of sulfur and nitrogen ocollected by conventional methods 
Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Tacondistributed without the full texnot taken out of context.

Reference No.1 SO2 Pollution Control Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency

MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other2 Comments B

15 Electrocatalytic Oxidation N --- --- --- --- x Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NO

dioxide (NO2), sulfuric acid, and m

plasma.On recent project, the vender was d

16 NOXSO N --- --- --- --- Commercial version of adsorption. Limited experience (proof-of-concept tests).

Uses a regenerable sorbent to simul

from coal-fired utility and industria

a saleable sulfur by-product (liquid 

NOx is converted to nitrogen and o

17 Copper-Oxide N --- --- --- --- x Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with copp

alumina, to form copper sulfate. Amabsorption reactor and a selective c

reduces the nitric oxides in the flue is reduced in a regenerator with a rconcentrated stream of SO2.

18 SNOX N --- --- --- --- x Early commercial development stage

Catalytic reduction of NOx in the p

catalytic oxidation of SO2 to SO3. T

through a novel glass-tube condens

and then condensed to a concentrat

19 Cold Plasma N --- --- --- --- x Research level

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports
Summary of Relevant Economic Feasibility ($/ton) Control Costs 

Avg. Expected Values 

($/ton) 

Limiting/Marginal values 

($/ton) 

Reference Regulatory Body/Rule SO2 NOx SO2 NOx Comments 

BART 100 - 1000 100 - 1000 70 FR 39135 BART 281 - 1296 70 FR 39135 Table 3 BART 919 70 FR 39133 FR Notice 6JULY05 Final Rule 

BART 

Guidelines disparagingly reference "thin commenting on the need to exceed Munreasonableness. 

70 FR 25210 CAIR CAIR 1300 Estimated Marginal cost 2009 

BART(proposed rule) 200-1000 

BART proposed lists this as values for which is still assumed, or .1 to .15 lb/Mfinal to give states flexibility to require 

FR Notice 5MAY04 Proposed Rule bypasses aren't BART, only 100% scru

BART(proposed rule) 

0.2 lb/MMBtu for NOx is assumed reasome sources may need SCR to get thidiscretion of the cost vs. visibility valu

CAIR(using IPM) 1000 1500 CAIR ( 2009 in 1999$) 900 2400 CAIR ( 2015 in 1999$) 1800 3000 

Midwest RPO Report Referencing CAIR 

CAIR (depending on Nat'l emissions) 1200 - 3000 1400- 2100 This was modeled with TRUM (Techn

Updating Model) to develop the margi

Kammer EPA Decision Kammer Decision > 1000 > 1000 LADCO Midwest RPO Boiler Analysis LADCO/Midwest RPO 1240 - 3822 607 - 4493 MANE-VU BART Control Assessment MANE-VU 200 - 500 200 - 1500 Bowers vs. SWAPCA Bowers vs. SWAPCA 300 300 1000 1000 954-1134 was ruled too much, in favor 

did consider incremental value. Section

WRAP 3000 WRAP Trading Program 

Methodology EPA - Referenced by 

Wrap 

References EPA-600S\7-90-018. Low $500-3000/ton, High is over $3000/ton 

The dollars per ton estimates cited above were obtained from BART guidance, documentation of similar regulatory 

and relevant court decisions. These materials indicate that most EPA sanctioned documents, including the final BAR

support an average expected reasonable cost range of $1,300 to $1,800 per ton of NOx removed and a range of $1,0SO2 removed. The BART presumptive limits were set based on cost effective controls that were on average less tha

example, the presumptive SO2 limit was established based on an average cost effectiveness of less than $1,000/ton. 

extends into RPO, WRAP and other regional planning documentation, the cost ranges become more variable and di

ease of comparison, the federally established ranges for NOx and SO2 were used as a BART cost threshold basis.