## Mittal Steel BART Report September 8, 2006

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# i 

# Mittal Steel BART Report September 8, 2006

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

## Mittal Steel BART Report September 8, 2006

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# ii 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 SO 2 

# Control Technology – Availability, Applicability, and

Technical Feasibility .......................................................................................................... 24
Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness ................................................. 25
Table 5-3 SO 2 

# Control Cost Summary ................................................................................................ 26
Table 5-4 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and

Technical Feasibility .......................................................................................................... 41
Table 5-5 Indurating Furnace NO x 

# Control Technology Effectiveness................................................. 42
Table 5-6 NO x 

# Control Cost Summary................................................................................................ 43
Table 5-7 NO x 

# Control Technology Impacts Assessment .................................................................... 44
Table 5-8 Post- BART NO X 

# Control - Predicted 24-hour Maximum Emission Rates ........................... 46
Table 5-9 Post-BART NO X 

# 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

## Mittal Steel BART Report September 8, 2006

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# iii 

# 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 afederally 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 analyses 1 

# . 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.

1 

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

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# iv After completion of the streamlined analysis, the focus of the BART analysis was the SO 2 

# and NO x 

# 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 (SO 2 

# ).

According to US EPA guidance, the following impacts must be considered within the process for the selection of BART 2 

# :
(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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# v 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 standards 3



# .

 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:

 SO 2 

# 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).

 NO x 

# limitation of 1,088 lb/hr from the preheat burners (controlled by existing combustion practices for the furnace and low-NO x 

# 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 4 

# IBID

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# 1 

# 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 Title V permit amendments.

## Mittal Steel BART Report September 8, 2006

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# 2 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 2064 5 

# . 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

5 

# Federal Register 70, No. 128 (July 6, 2005): 39104-39172

## Mittal Steel BART Report September 8, 2006

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# 3 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, PM 10 

# , PM 2.5 

# , SO 2 

# , NO x 

# , 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

## Mittal Steel BART Report September 8, 2006

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# 4 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 

# Federal Register 70, No. 128 (July 6, 2005): 39164

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# 5 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 

# Federal Register 70, No. 128 (July 6, 2005): 39165 9 

# IBID 10 

# IBID

## Mittal Steel BART Report September 8, 2006

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# 6 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 protocol 12 

# , 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

11 

# IBID 12 

# MPCA. October 10, 2005. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to BART in the State of Minnesota

.

## Mittal Steel BART Report September 8, 2006

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# 7 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. 15 

# IBID

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# 8 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.

16 

# IBID

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# 9 

# 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: NO x 

# , SO 2 

# , and PM. Theindurating 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 NO x 

# and SO 2 

# 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 NO x 

# or SO 2 

# . 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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# 10 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 standardsThe 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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# 11 

# 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.Mittal Steel BART ReportSeptember 8, 2006Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Ispat BART Report\BART Rpt Mittal Steel FINAL 2006-09-08.doc12Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmission Unit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hrActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumber Actions Required3A. Indurating FurnacesEU 026Indurating Machine------51.4 0.01 014 BART Analysis for SO2 + NOxEU 026Indurating Machine------50.0 0.01 015 BART Analysis for SO2 + NOxEU 026Indurating Machine------48.9 0.01 016 BART Analysis for SO2 + NOxEU 026Indurating Machine------54.8 0.01 017 BART Analysis for SO2 + NOx3.B. PM-Only Taconite MACT Emission UnitsEU 001Primary Crusher------8.6 0.008 001NoneEU 003Drop Onto Coarse Ore Pile Conveyor------8.6 0.008 003NoneEU 003/004/005Secondary Crushing------14.5 0.008 004NoneEU 003/004/005Secondary Crushing------14.5 0.008 005NoneEU 007/008/009/010Tertiary Crushing------14.5 0.008 006NoneEU 007/008/009/010Tertiary Crushing------16.5 0.008 007NoneEU 006Outside Ore Transfer------16.7 0.008 009NoneEU 011/012Fine Ore Drop------16.7 0.008 010NoneEU 013/014/015/016/017 Fine Ore Drop, rod mill material handling------14.5 0.008 011NoneEU 018Machine Discharge and Conveyor to Spl Bin------26.9 0.008 018NoneEU 021/022/023 Pellet Hearth Layer Conveyor, Bin, and Grate Feed ------7.4 0.008 019NoneEU 024/025 Pellet Hearth Layer Screen & Conveyor to HL Bin ------13.2 0.008 020NoneEU 029/030Drop Into Spl Bin and Into Prod Spl Bin Conv------12.3 0.008 021NoneEU 032Drop onto P3 Pellet Pile Underfeed Conveyor------9.9 0.008 022NoneEU 031Drop in P1-P2 Transfer House------10.0 0.008 024None3.C. Sources of fugitive PM that are subject to MACT standardsNone--------------- ------3.D. Non-MACT Units and Fugitive Sources (PM only)EU 018Binder Transer to Storage Silo------2.1--- 012NoneEU 019/020Binder Shift Bins and Blending------7.0--- 013None3.E. Other Combustion UnitsNone--------------- ------* 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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# 13 

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

As indicated in U.S. EPA’s final BART guidance 20 

# , 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 NO x 

# , SO 2, 

# PM 2.5 

# and
PM 10 

# 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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# 14 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 NO x 

# 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 NO x 

# emissions to each stack does not reflect the actual distribution. Based on 2005 stack test data, the percent of total NO x 

# 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 NO x 

# emissions of each stack. No changes were made to the maximum 24-hour particulate matter or SO 2 

# 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 protocol 22 

# 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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# 15 • 98 th 

# Percentile: As defined by federal guidance and as stated in the MPCA’s document which identifies the Minnesota facilities that are subject to BART 23 

# , a source "contributes to visibility impairment” if the 98 th 

# percentile of any year’s modeling results (i.e. 7 th 

# 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
98 th 

# 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 DataEU #EU DescriptionSO2Maximum24-hr EmissionRate (lbs/day)NOxMaximum24-hr EmissionRate (lbs/day)PM2.5Maximum24-hr EmissionRate (lbs/day)PM10Maximum24-hr EmissionRate (lbs/day) SV #StackEasting (utm)StackNorthing(utm)Height ofOpeningfromGround (ft)BaseElevation ofGround (ft)Stack length,width, orDiameter (ft)Flow Rateat exit(acfm)ExitTemp (°F)Basis for SO224-hour ActualEmissionsBasis for NOx24-hour ActualEmissionsBasis forPM2.524-hour ActualEmissionsBasis for PM1024-hour ActualEmissionsEU 001Primary Crusher---------8.63 SV 001 535972.61 5267596.97 41.5 1,657 2.00 12,013 65n/an/an/aPTEEU 003 Drop Onto Coarse Ore Pile Conveyor ---------8.63 SV 003 535972.61 5267596.97 10.0 1,620 3.51 26,159 65n/an/an/aPTEEU003/004/005Secondary Crushing---------14.47 SV 004 535972.61 5267596.97 10.0 1,620 3.51 26,159 65n/an/an/aPTEEU003/004/005Secondary Crushing---------14.47 SV 005 535972.61 5267596.97 10.0 1,620 3.51 26,159 65n/an/an/aPTEEU007/008/009/010Tertiary Crushing---------14.47 SV 006 535972.61 5267596.97 10.0 1,620 3.51 26,159 65n/an/an/aPTEEU007/008/009/010Tertiary Crushing---------16.48 SV 007 535972.61 5267596.97 10.0 1,620 3.51 26,159 65n/an/an/aPTEEU 006Outside Ore Transfer---------16.74 SV 009 535972.61 5267596.97 10.0 1,620 3.51 26,159 65n/an/an/aPTEEU011/012Fine Ore Drop---------16.74 SV 010 535972.61 5267596.97 10.0 1,620 3.51 26,159 65n/an/an/aPTEEU013/014/015/016/017Fine Ore Drop, rod mill material handling ---------14.47 SV 011 535972.61 5267596.97 23.2 1,685 2.99 25,756 65n/an/an/aPTEEU 018 Binder Transer to Storage Silo---------2.14 SV 012 535972.61 5267596.97 56.0 1,685 1.41 8,637 65n/an/an/aPTEEU019/020Binder Shift Bins and Blending---------6.99 SV 013 535972.61 5267596.97 56.0 1,685 1.41 8,637 65n/an/an/aPTEEU 026Indurating Machine30003731---51.37 SV 014 535972.61 5267596.97 136.0 1,605 8.75 205478 124Based on engineeringestimate of 500 lbs/hrfor the furnace, whichwas equally dividedbetween the fourstacksEmissions based onPTE/Permit Limitdistributed betweenstacks based on actualpercentage duringstack test.n/aPTEEU 026Indurating Machine30004800---50.00 SV 015 535972.61 5267596.97 136.0 1,605 8.75 205478 124Based on engineeringestimate of 500 lbs/hrfor the furnace, whichwas equally dividedbetween the fourstacksEmissions based onPTE/Permit Limitdistributed betweenstacks based on actualpercentage duringstack test.n/aPTEEU 026Indurating Machine30007398---48.86 SV 016 535972.61 5267596.97 136.0 1,605 8.75 205478 124Based on engineeringestimate of 500 lbs/hrfor the furnace, whichwas equally dividedbetween the fourstacksEmissions based onPTE/Permit Limitdistributed betweenstacks based on actualpercentage duringstack test.n/aPTEEU 026Indurating Machine300010183---54.79 SV 017 535972.61 5267596.97 136.0 1,605 8.75 205478 124Based on engineeringestimate of 500 lbs/hrfor the furnace, whichwas equally dividedbetween the fourstacksEmissions based onPTE/Permit Limitdistributed betweenstacks based on actualpercentage duringstack test.n/aPTEEU 018Machine Discharge and Conveyor to SplBin---------26.94 SV 018 535972.61 5267596.97 54.0 1,651 4.99 63,669 65n/an/an/aPTEEU021/022/023Pellet Hearth Layer Conveyor, Bin, andGrate Feed---------7.42 SV 019 535972.61 5267596.97 71.0 1,670 1.84 9,576 65n/an/an/aPTEEU024/025Pellet Hearth Layer Screen & Conveyor toHL Bin---------13.24 SV 020 535972.61 5267596.97 58.0 1,647 2.82 20,123 65n/an/an/aPTEEU029/030Drop Into Spl Bin and Into Prod Spl BinConv---------12.33 SV 021 535972.61 5267596.97 23.0 1,653 2.66 20,057 65n/an/an/aPTEEU 032Drop onto P3 Pellet Pile UnderfeedConveyor---------9.93 SV 022 535972.61 5267596.97 48.0 1,595 3.90 14,540 65n/an/an/aPTEEU 031 Drop in P1-P2 Transfer House---------10.02 SV 024 535972.61 5267596.97 138.0 1,568 2.43 15,100 65n/an/an/aPTETable 4-2 Baseline Visibility Modeling Results2002200320042002 – 2004 CombinedModelingScenarioOperatingConditionsClass IArea withGreatestImpactModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciview0 BaselineBWCA 2.285972.457902.586702.381257

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# 18 

# 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 SO 2 

# and NO x 

# . 

# 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. SO 2 

# reductions also occur within the existing wet scrubbers; they are considered low efficiency SO 2 

# scrubbers and will be evaluated as such within this BART analysis. NO x 

# is controlled by low-NO x 

# 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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# 19 

# 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 SO 2 

# 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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# 20 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 SO 2 

# removal, caustic is added to the water spray system, allowing the WWESP spray system to function as an SO 2 

# absorber.

The SO 2 

# control efficiency for a WWESP is dependent upon various process specific variables, such
as SO 2 

# flue gas concentration, fuel used, and ore composition. Since Mittal Steel currently employs a low efficiency SO 2 

# wet scrubber. The addition of a WWESP would act as a polishing scrubber and would experience reduced control efficiency due to lower SO 2 

# 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 SO 2 

# reduction for this BART analysis. The technology is commercially available and
has been demonstrated to be effective for SO 2 

# removal on indurating furnaces.

Wet Scrubbing (High and Low Efficiency) Wet scrubbing, when applied to remove SO 2 

# , 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 SO 2 

# in the waste gas. Crushed limestone, lime, or caustic are used as scrubbing agents. Most SO 2 

# 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 SO 2 

# wet scrubber, the scrubber would require designs for removal efficiency up to 95% SO 2 

# . Typical high efficiency SO 2 

# wet scrubbers are packedbed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO 2 

# wet scrubber can have a control efficiency of 30% or lower. A low efficiency SO 2 

# 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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# 21 control at taconite facilities, will also remove some of the SO 2 

# 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:

CaCO 3 

# + SO 2 

# → CaSO 3 

# • 1/2 H2O + CO 2 

# CaSO 3 

# •1/2 H 2 

# O + 3H 2 

# O + O 2 

# → 2 CaSO 4 

# •2 H 2 

# O

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 

# +SO 2 

# → CaSO 3 

# • 1/2 H 2 

# O + 1/2 H 2 

# O Ca(OH) 2 

# + SO 2 

# + 1/2 O 2 

# + H 2 

# O → CaSO 4 

# •2 H 2 

# O

When caustic (sodium hydroxide solution) is the scrubbing agent, the SO 2 

# removal reactions are as
follows:

Na+ + OH- + SO 2 

# + → Na 2 

# SO 3 

# 2Na+ + 2OH- + SO 2 

# + → Na 2 

# SO 3 

# + H 2 

# O

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 SO 2 

# 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 SO 2 

# control efficiency range for SO 2 

# 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 SO 2 

# 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 SO 2 

# concentration and creates higher flow rates to control. Additionally, the varying sulfur concentration within the ore causes fluctuations of the SO 2 

# concentrations in the exhaust gas stream. This could also impact the SO 2 

# control efficiency of the
wet scrubber.

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# 22 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 SO 2 

# in the exhaust based on Barr’s experience and testing which has been completed. Taking into consideration the removal of SO 2 

# from the low-efficiency primary PM scrubber as well as a high efficiency SO 2 

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

In theory, the SO 2 

# 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 SO 2 

# 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 SO 2 

# reduction for this BART analysis.

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) Lime/limestone injection is a post-combustion SO 2 

# control technology in which pulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry sorption of SO 2 

# onto the lime or limestone particle occurs and the solid particles are collected with a fabric filter. Further SO 2 

# removal occurs as the flue gas flows through the filter cake on the bags. The normal SO 2 

# control efficiency range for dry SO 2 

# 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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# 23 Spray Dryer Absorption (SDA) Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 

# is absorbed by the slurry, forming CaSO 3 

# /CaSO 4 

# . 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 SO 2 

# , 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 SO 2 

# 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 SO 2 

# reductions at this facility.

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# 24 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 SO 2 

# 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 SO 2 

# Control Technology – Availability, Applicability, and Technical Feasibility
Step 1 Step 2

SO 2 

# Pollution Control TechnologyIs this agenerallyavailable controltechnology?Is the controltechnologyavailable toinduratingfurnaces?Is the controltechnologyapplicable to thisspecific source?Is it technicallyfeasible for thissource?



# 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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# 25 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 SO 2 

# Control Technology Effectiveness

SO 2 

# 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 manual 25 

# 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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# 26 Table 5-3 SO 2 

# 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 SO 2 

# 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 indirectmeasure 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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# 27 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 pollutant 27



# . 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 SO 2 

# 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 SO 2 

# 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 SO 2 

# are not reasonably cost effective, so visibility impacts were not modeled for SO 2 

# 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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# 28 

# 5.A.ii Nitrogen Oxide Controls

To be able to control NO x 

# it is important to understand how NO x 

# is formed. There are three mechanisms by which NO x 

# production occurs: thermal, fuel and prompt NO x 

# .



# • Fuel bound NO x 

# is formed when nitrogen compounds in the fuel are oxidized in the combustion process.



# • Thermal NO x 

# 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 NO x 

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



# • Prompt NO x 

# is a form of thermal NO x 

# 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 NO x 

# are emitted as prompt NO x 

# .
The majority of NO x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the heater, the balance
of NO 2 

# is formed in the atmosphere when NO reacts with oxygen in the air. The majority of NO x 

# emitted is thermal NO x 

# – very little fuel bound NO x 

# is emitted.



# 5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies With some understanding of how NO x 

# 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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# 29 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 NO x 

# 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 NO x 

# 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 NO x 

# emissions. For this technology to be effective, the combustion conditions must have the ability to be controlled at the burner tip.

The normal NO x 

# 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 adding combustion air instead of an inert gas.

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# 30 2. The oxidation zone of induration furnaces needs to be above 2,400 o 

# F 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- NO x 

# Burners

Low- NO x 

# burner (LNB) technology utilizes advanced burner design to reduce NO x 

# formation through the restriction of oxygen, flame temperature, and/or residence time. 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, NO x 

# formation is limited by a rich (high fuel) condition. Oxygen levels and flame temperatures are low; this results in less NO x 

# 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 (N 2 

# ) over nitric oxide (NO).

The estimated NO x 

# control efficiency for low NO x 

# burners in high temperature applications is 10%. Application of low NO x 

# 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-NO x 

# 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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# 31 It is also important to note that there are other methods being developed for low NO x 

# burners which are not yet commercially available. Some incorporate various fuel dilution techniques to reduce flame temperatures; such as mixing an inert gas like CO 2 

# 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 NO x 

# 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- NO x 

# burners, combine the benefits of flue gas recirculation and low- NO x 

# 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 NO x 

# 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 NO x 

# 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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# 32 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 NO x 

# 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 NO x 

# . Switching natural gas usage to coal or other solid fuels exchanges one visibility impairment pollutant (NO x 

# ) for another (SO 2 

# ). 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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# 33 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 NO x 

# CEMS or Other Parametric Monitoring MPCA guidance lists “NO x 

# CEMS” as a work practice/operational change for controlling NO x 

# emissions 29 

# . 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 NO x 

# emissions. The impact of the process adjustments would be measured using the NO x 

# CEMS. This approach has been used in the electric utility industry to fine tune NO x 

# emissions from boilers.

One taconite plant has installed NO x 

# CEMS to monitor emissions but not to optimize NO x 

# emissions through process fine tuning. That plant has experienced some reduction in NO x 

# emissions but these encompass multiple variables and are not attributed to process fine tuning with the NO x 

# 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 NO x 

# 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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# 34 

# • At some operations, the operating parameters which generally influence the rate of NO x 

# 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 NO x 

# formation may not be dependent upon controllable operating parameters. In the absence of controllable parameters, process optimization would not be effective at controlling NO x 

# emissions.

Based upon this information, there is no indication that further emission reductions would be achieved through the use of the process optimization, using NO x 

# 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

NO x 

# 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 NO x 

# 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 NO x 

# , unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NO x 

# 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, NO x 

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

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO x 

# removal

are:

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# 35 2CO + 2NO 

# → 2CO 2 

# + N 2 

# (1)

[UBH] + NO 

# → N 2 

# + CO 2 

# + H 2 

# O (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 NO x 

# control technology in which ammonia (NH 3 

# ) is injected into the flue gas stream in the presence of a catalyst. NO x 

# is removed through the following chemical reaction:

4 NO + 4 NH 3 

# + O 2 

# → 4 N 2 

# + 6 H 2 

# O (1)

2 NO 2 

# + 4 NH 3 

# + O 2 

# → 3 N 2 

# + 6 H 2 

# O (2)

A catalyst bed containing metals in the platinum family is used to lower the activation energy required for NO x 

# 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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# 36 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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# 37 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
NO x 

# . In the system, the NO x 

# 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-NO x 

# ® and LoTOx®.

NO + O 3 

# → NO 2 

# + O 2 

# (1)

NO 2 

# + O 3 

# → NO 3 

# + O 2 

# (2)

NO 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O 

# → 2HNO 3 

# (4)

HNO 3 

# + NaOH 

# → NaNO 3 

# + H 2 

# O (5)



# Low Temperature Oxidation (Tri-NO x ® 

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

# in a primary scrubbing stage. Then NO 2 

# is removed through caustic scrubbing in a secondary stage. The
reactions are as follows:

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# 38 O 3 

# + NO 

# → O 2 

# + NO 2 

# (1)

2NaOH + 2NO 2 

# + 1⁄2 O 2 

# → 2NaNO 3 

# + H2O (2)

Tri-NO x ® 

# 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 NO 2 

# . Subsequent stages reduce NO 2 

# to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NO x ® 

# is typically applied at small to medium sized sources with high NO x 

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

# ). NO x 

# concentrations in taconite exhaust are typically less than 200 ppm. Therefore, Tri-NO x ® 

# 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 NO 2 

# and NO 2 

# to N 2 

# O 5 

# in a wet scrubber (absorber). This can be done in the same scrubber used for particulate or sulfur dioxide removal, The N 2 

# O 5 

# is converted to HNO 3 

# 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 NO x 

# 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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# 39 205,000 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 (Fe 3 

# O 4 

# ) which would react with the ozone to form hematite (Fe 2 

# O 3 

# ); 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 SO 2 

# , converting the
material to SO 3 

# 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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# 40 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 NO x 

# 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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# 41 Table 5-4 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and Technical Feasibility
Step 1 Step 2

SO 2 

# Pollution Control TechnologyIs this agenerallyavailable controltechnology?Is the controltechnologyavailable toinduratingfurnaces?Is the controltechnologyapplicable to thisspecific source?Is it technicallyfeasible for thissource?



# External Flue Gas Recirculation (EFGR) Y Y N ---

Low- 

# NO x 

# 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 

# NO x 

# 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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# 42 

# 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 NO x 

# Control Technology Effectiveness



# NO x 

# 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 manual 30 

# 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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# 43 Table 5-6 NO x 

# 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 indirectmeasure 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 pollutant 32



# . 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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# 44 The cost of NO x 

# 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, NO x 

# controls for these stacks will not be carried forward in this analysis. However, the cost of NO x 

# 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 NO x 

# 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 NO x 

# 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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# 45 

# 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 NO x 

# 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 NOXControl - Predicted 24-hour Maximum Emission RatesScenario Control TechnologySO2NOxControlScenario SV #EmissionUnitSO2NOx%ReductionMax 24-hourlbs/day%ReductionMax 24-hourlbs/daySV 014 EU 026Base(SO2 Scrubbers)SCR w/ Reheat(SV 017 Only)--- 3,000 --- 3,730SV 015 EU 026Base(SO2 Scrubbers)SCR w/ Reheat(SV 017 Only)--- 3,000 --- 4,800SV 016 EU 026Base(SO2 Scrubbers)SCR w/ Reheat(SV 017 Only)--- 3,000 --- 7,399SV 017 EU 026Base(SO2 Scrubbers)SCR w/ Reheat(SV 017 Only)--- 3,000 80% 2,0371Table 5-9 Post-BART NOxModeling Scenarios - Visibility Modeling ResultsScenario #ControlScenarioClass IArea withGreatestImpactModeled 98thPercentileValue(deciview)No. of daysexceeding0.5 deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding0.5 deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding0.5 deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding0.5 deciview0 Baseline BWCA 2.285 97 2.457 90 2.586 70 2.381 2571SCR on StackSV 017BWCA 1.69 80 1.949 69 1.909 48 1.762 1972002200320042002 – 2004Combined

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# 48 

# 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 SO 2 

# and NO x 

# controls, and determines the resulting degree of visibility improvement.

However, since there were no SO 2 

# controls that were carried forward from the economic screening analysis, no additional modeling is required. The applicable modeling for the NO x 

# control technology is presented in section 5.A.ii.e.

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# 49 

# 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 SO 2 

# , the low-NO x 

# 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 NO x 

# 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 NO x 

# . 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 standards 33



# .



#  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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# 50 

#  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:



#  SO 2 

# 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).



#  NO x 

# limitation 1,088 lb/hr from the preheat burners (controlled by existing combustion practices for the furnace and low-NO x 

# 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 

# IbidTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmission Unit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hrActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions Required3A. Indurating FurnacesEU 026Indurating Machine------51.4 0.01 014 BART Analysis for SO2 + NOxEU 026Indurating Machine------50.0 0.01 015 BART Analysis for SO2 + NOxEU 026Indurating Machine------48.9 0.01 016 BART Analysis for SO2 + NOxEU 026Indurating Machine------54.8 0.01 017 BART Analysis for SO2 + NOx3.B. PM-Only Taconite MACT Emission UnitsEU 001Primary Crusher------8.6 0.008 001NoneEU 003Drop Onto Coarse Ore Pile Conveyor------8.6 0.008 003NoneEU 003/004/005Secondary Crushing------14.5 0.008 004NoneEU 003/004/005Secondary Crushing------14.5 0.008 005NoneEU 007/008/009/010Tertiary Crushing------14.5 0.008 006NoneEU 007/008/009/010Tertiary Crushing------16.5 0.008 007NoneEU 006Outside Ore Transfer------16.7 0.008 009NoneEU 011/012Fine Ore Drop------16.7 0.008 010NoneEU 013/014/015/016/017 Fine Ore Drop, rod mill material handling------14.5 0.008 011NoneEU 018Machine Discharge and Conveyor to Spl Bin------26.9 0.008 018NoneEU 021/022/023 Pellet Hearth Layer Conveyor, Bin, and Grate Feed ------7.4 0.008 019NoneEU 024/025 Pellet Hearth Layer Screen & Conveyor to HL Bin ------13.2 0.008 020NoneEU 029/030Drop Into Spl Bin and Into Prod Spl Bin Conv------12.3 0.008 021NoneEU 032Drop onto P3 Pellet Pile Underfeed Conveyor------9.9 0.008 022NoneEU 031Drop in P1-P2 Transfer House------10.0 0.008 024None3.C. Sources of fugitive PM that are subject to MACT standardsNone--------------- ------3.D. Non-MACT Units and Fugitive Sources (PM only)EU 018Binder Transer to Storage Silo------2.1--- 012NoneEU 019/020Binder Shift Bins and Blending------7.0--- 013None3.E. Other Combustion UnitsNone--------------- ------* 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 Company9/6/2006BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Cost SummaryNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonSV 01480% 104.0416.0 $33,429,177 $9,776,865$23,504SV 01580% 133.8535.2 $33,531,232 $9,928,660$18,552SV 01680% 206.2824.9 $33,713,372 $10,288,957$12,473SV 01780% 283.81135.4 $33,855,392 $10,668,091$9,396SO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonSV 01480% 9.035.8 $22,809,844 $4,184,373$116,801SV 01580% 9.035.8 $22,809,844 $4,184,373$116,801SV 01680% 9.035.8 $22,809,844 $4,184,373$116,801SV 01780% 9.035.8 $22,809,844 $4,184,373$116,801SV 01460% 17.926.9 $16,454,216 $2,229,797$82,989SV 01560% 17.926.9 $16,454,216 $2,229,797$82,989SV 01660% 17.926.9 $16,454,216 $2,229,797$82,989SV 01760% 17.926.9 $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 ReheatY:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control CostsCost Summary9/7/2006 Page 1 of 55Ispat Inland Mining CompanyBART Report - Attachment A: Emission Control Cost AnalysisTable A.2: Summary of Utility, Chemical and Supply CostsOperating Unit:Indurating FurnaceStudy Year2006Emission Unit NumberEU 026Stack/Vent NumberSV 014Operating Unit:Indurating FurnaceEmission Unit NumberEU 026Stack/Vent NumberSV 015Operating Unit:Indurating FurnaceEmission Unit NumberEU 026Stack/Vent NumberSV 016Operating Unit:Indurating FurnaceEmission Unit NumberEU 026Stack/Vent NumberSV 017ReferenceItemUnit Cost UnitsCost Year Data SourceNotesOperating Labor32 $/hrAverage union labor rate for MN miningindustryMaintenance Labor32 $/hrAverage union labor rate for MN miningindustryElectricity0.051 $/kwh2006Energy Information Administration. Expectedannual average industrial price of electricityin the West North Central Division for 2007 -DOEhttp://tonto.eia.doe.gov/steo_query/app/elecpage.htmNatural Gas9.2575 $/mscf2005Energy Information Administration. AverageUS Industrial Natural Gas Prices. July '05 toJune '06.http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3m.htmWater0.28 $/mgal0.20 1995EPA Air Pollution Control Cost Manual, 6thEd 2002, Section 5 Ch 1, page 1-40Annual Costs for Packed Tower Absorber Example Problem. '95 costadjusted for 3% inflation.Cooling Water0.28 $/mgal0.23 1999EPA Air Pollution Control Cost Manual, 6thed. Section 3.1 Ch 1Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and3% inflationCompressed Air0.32 $/mscf0.25 1998EPA Air Pollution Control Cost Manual 6th Ed2002, Section 6 Chapter 1Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%inflationWastewater Disposal Neutralization1.69 $/mgal1.50 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 2 Chapter 2.5.5.5Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch3 lists $1.30 - $2.15/1,000 galChemicals & SuppliesLime90.80 $/ton90.80 2006Estimate from Cutler-Magney Company.Oxygen40.00 $/ton2006BOC estimate.Ammonia (29% aqua.)0.12 $/lb0.101 2000EPA Air Pollution Control Cost Manual 6th Ed2002, Section 5 Chapter 2, page 2-50Annual costs for a retrofit SCR system example problem. '00 costsadjusted for 3% inflation.Caustic305.96 $/ton280 2003 Hawkins Chemical50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflationSCR Catalyst141.00$/ft3Cormetech, Inc.OtherSales Tax6.5% %Interest Rate7.00% %EPA Air Pollution Control Cost ManualIntroduction, Chapter 2, section 2.4.2.Social (discount) rate used as a default.Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control CostsUtility Chem$ Data9/7/2006 Page 2 of 55Operating InformationAnnual Op. Hrs7946 HoursEngineering EstimateUtilization Rate93%Equipment Life20 yrsEngineering EstimateStandardized Flow RateSV 014173,108 scfm @ 32o FCalculated.SV 015173,108 scfm @ 32o FCalculated.SV 016173,108 scfm @ 32o FCalculated.SV 017173,108 scfm @ 32o FCalculated.TemperatureSV 014124 Deg FBART spreadsheet.SV 015124 Deg FBART spreadsheet.SV 016124 Deg FBART spreadsheet.SV 017124 Deg FBART spreadsheet.Moisture ContentSV 01410.5%Assumed value.SV 01510.5%Assumed value.SV 01610.5%Assumed value.SV 01710.5%Assumed value.Actual Flow RateSV 014205,478 acfmBART spreadsheet.SV 015205,478 acfmBART spreadsheet.SV 016205,478 acfmBART spreadsheet.SV 017205,478 acfmBART spreadsheet.Standardized Flow RateSV 014185,775 scfm @ 68o FCalculated.SV 015185,775 scfm @ 68o FCalculated.SV 016185,775 scfm @ 68o FCalculated.SV 017185,775 scfm @ 68o FCalculated.Dry Std Flow RateSV 014166,268 dscfm @ 68o FCalculated.SV 015166,268 dscfm @ 68o FCalculated.SV 016166,268 dscfm @ 68o FCalculated.SV 017166,268 dscfm @ 68o FCalculated.Max Emis Future Actual Emis. lb/hr ton/yearPollutant Lb/Hrtpyppmv ppmvNitrous Oxides (NOx)SV 014155.4520.0 13099.6SV 015200.0669.0 168 128.1SV 016308.31,031.1 259 197.5SV 017424.31,419.2 356 271.8Sulfur Dioxides (SO2)SV 014125.044.8 756.2SV 015125.044.8 756.2SV 016125.044.8 756.2SV 017125.044.8 756.2Max emissions are based on the permit limitand distributed to each stack based on 2005stack test data.Future actual emissions based on 2005 stack test +10%.Max emissions are based on emissions asreported in the BART questionairreFuture actual emissions based on AP-42 factors plus a 10% safetyfactor.Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Ispat\Ispat Inland Control CostsUtility Chem$ Data9/7/2006 Page 3 of 55

# Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NO x 

# 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

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# 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

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# 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 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 185,775 scfm Vol #2 2842.2 ft 3 

### Amount Required 2,842 f t 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 H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 413.9

Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 

### 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 258,612 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu 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

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## Ispat Inland Mining Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NO x 

## 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

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## 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

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## 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 $/ft 3 

### Amount Required 39 ft 3 

### Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 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.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 T wi 

### 124 Deg F - Temperature of waste gas into heat recovery T fi 

### 750 Deg F - Temperature of Flue gas into of heat recovery T ref 

### 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 

### 562 Deg F - Temperature of waste gas out of heat recovery

T fo 

### 312 Deg F - Temperature of flue gas into of heat recovery

-h caf 

### 21502 Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 

### 0 Btu/lb Heat of combustion waste gas C p wg 

### 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air) p wg 

### 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F p af 

### 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F Q wg 

### 185,775 scfm - Flow of waste gas

Q af 

### 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.b: NO x 

# 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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# 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

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# 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 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 185,775 scfm Vol #2 2842.2 ft 3 

### Amount Required 2,842 f t 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 H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 418.1

Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 

### 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 201,004 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu 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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## Ispat Inland Mining Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b: NO x 

## 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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## 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

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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)

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 $/ft 3 

### Amount Required 39 ft 3 

### Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 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 T wi 

### 124 Deg F - Temperature of waste gas into heat recovery T fi 

### 750 Deg F - Temperature of Flue gas into of heat recovery T ref 

### 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 

### 562 Deg F - Temperature of waste gas out of heat recovery

T fo 

### 312 Deg F - Temperature of flue gas into of heat recovery

-h caf 

### 21502 Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 

### 0 Btu/lb Heat of combustion waste gas C p wg 

### 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air) p wg 

### 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F p af 

### 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F Q wg 

### 185,775 scfm - Flow of waste gas

Q af 

### 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.c: NO x 

# 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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# 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

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# 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 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 185,775 scfm Vol #2 2842.2 ft 3 

### Amount Required 2,842 f t 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 H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 428.1

Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 

### 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 130,406 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu 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

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## Ispat Inland Mining Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c: NO x 

## 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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## 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

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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 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 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 T wi 124 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 562 Deg F - Temperature of waste gas out of heat recovery

T fo 312 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air) p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F Q wg 185,775 scfm - Flow of waste gas

Q af 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: NO x 

# 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 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 185,775 scfm Vol #2 2842.2 ft 3 

### Amount Required 2,842 f t 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 H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 438.9

Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 

### 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 94,746 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu 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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## Ispat Inland Mining Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d: NO x 

## 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

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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 $/ft 3 

### Amount Required 39 ft 3 

### Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 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 T wi 

### 124 Deg F - Temperature of waste gas into heat recovery T fi 

### 750 Deg F - Temperature of Flue gas into of heat recovery T ref 

### 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 

### 562 Deg F - Temperature of waste gas out of heat recovery

T fo 

### 312 Deg F - Temperature of flue gas into of heat recovery

-h caf 

### 21502 Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 

### 0 Btu/lb Heat of combustion waste gas C p wg 

### 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air) p wg 

### 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F p af 

### 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F Q wg 

### 185,775 scfm - Flow of waste gas

Q af 

### 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: SO 2 

## 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 (SO 2 ) 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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## 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 multiplier 3 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

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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

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

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## Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis Table A.4.b: SO 2 

## 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 (SO 2 ) 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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## 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 multiplier 3 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

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## 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

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## Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis Table A.4.c: SO 2 

## 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 (SO 2 ) 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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## 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 multiplier 3 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

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## 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

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## Ispat Inland Mining Company

BART Report - Attachment A: Emission Control Cost Analysis Table A.4.d: SO 2 

## 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 (SO 2 ) 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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## 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 multiplier 3 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

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## 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

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## Ispat Inland Mining Company BART Report - Attachment A: Emission Control Cost Analysis Table A.5.a: SO 2 

## 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 (SO 2 ) 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 Equipment 1 (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 multiplier 5 60% 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 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 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 Rate 2 7,808 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 193 gpm Evaporation Loss 4 = 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 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 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: SO 2 

## 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 (SO 2 ) 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 multiplier 5 60% 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 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 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 Rate 2 7,808 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 193 gpm Evaporation Loss 4 = 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 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 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 (SO 2 ) 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 multiplier 5 60% 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 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 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 Rate 2 7,808 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 193 gpm Evaporation Loss 4 = 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 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 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 (SO 2 ) 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 multiplier 5 60% 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 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 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 Rate 2 7,808 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 193 gpm Evaporation Loss 4 = 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 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 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

# ! ; NBarr 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 VoyageursTERRELVariableDescriptionValueDefaultCommentsGTOPO30 GTOPO 30-sec data- n/a 1 degree DEM files will be usedXREFKM Reference point coordinates for grid168 n/aYREFKM Reference point coordinates for grid720 n/aNX Number of X grid cells40 n/aNYNumber of Y grid cells30n/aCTGPROCVariableDescriptionValueDefaultCommentsXREFKM Reference point coordinates for grid168 n/aYREFKM Reference point coordinates for grid720 n/aNX Number of X grid cells40 n/aNYNumber of Y grid cells30n/aCALMETVariableDescriptionValueDefaultCommentsNUSTA Number of upper air stations4 14898, 14918, 94983, 4837NX Number of X grid cells40 n/aNY Number of Y grid cells30 n/aXORIGKM Reference point coordinates for grid168 n/aYORIGKM Reference point coordinates for grid720 n/aNOOBS No Observation Mode0 Y Include Surface, Upper Air and Precipitation ObservationsNSSTA Number of Surface Stations74 n/a 74 surface weather stationsNPSTA Number of Precipitation Stations68 n/a 68 precipitation stationsRMAX2 Maximum radius of influence over land aloft50 n/a Similar to PSD with ObservationsRMAX3 Maximum radius of influence over water500 n/a Similar to PSD with ObservationsR1 Relative weighting of the first guess field and observations in the surface layer (km) 10 n/a Similar to PSD with ObservationsR2 Relative weighting of the first guess field and observations in the layers aloft (km)20 n/a Similar to PSD with ObservationsISURFT Surface met. Stations to use for the surface temperature- n/a Hibbing Met stationIUPT Upper air station to use for the domain scale lapse rate- n/a International Falls Upper Air stationITPROG 3D temperature from observations or from prognostic data?0 Y Inclusion of Surface and Upper AirTRADKM Radius of influence for temperature interpolation500 Y Similar to PSD with ObservationsJWAT1 Beginning land use category for temperature interpolation over water99 n/a CALMET may fail when using 55 with no overwater dataJWAT2 Ending land use category for temperature interpolation over water99 n/a CALMET may fail when using 55 with no overwater dataSIGMAPRadius of influence (km)100YPrecipitation Observations are includedInput Group 0bInput Group 2Input Group 2Input Group 2Input Group 4Input Group 5Input Group 6CALPUFFVariableDescriptionValueDefaultCommentsNX Number of X grid cells in met grid40 n/aNY Number of Y grid cells in met grid30 n/aXORIGKM Reference point coordinates for met grid168 n/aYORIGKM Reference point coordinates for met grid720 n/aIBCOMP X index of LL corner1 n/aJBCOMP Y index of LL corner1 n/aIECOMP X index of UR corner40 n/aJECOMP Y index of UR corner30 n/aMOZ Ozone data input option1 N OZONE.DAT from MN, WI, and MI observation stationsNRECNumber of non-gridded receptors1222n/aUsing only BWCA and Voyageurs from MPCA protocolInput 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, Final 1 

# , 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 guidance 2 

# , 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 protocol 3 

# 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 guidance 4 

# 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

Barr Footer: Date: 7/5/2006 1:39:55 PM File: I:\projects\23\00\Minntac.mxd User: ams100MetersIspat Inland Aerial PhotoTaconite BART AnalysisNOx ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology 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?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic PrincipleCombustion Controls1 Overfire Air (OFA) Y N --- ------xNOx formation front is not stationary inan indurating furnaceCombustion air is separated into primary and secondary flow sections toachieve complete burnout and to encourage the formation of N2ratherthan NOx2External Flue GasRecirculation (EFGR)Y Y N ------xxMixes flue gas with combustion air which reduces oxygen content andtherefore reduces flame temperature3 Low-NOx BurnersYYY(preheatburners)Y(preheatburners)10-20%x x xHigher control efficiency at the burner,but the listed control efficiency is forthe entire furnace.Burners are designed to reduce NOx formation through restriction ofoxygen, flame temperature, and/or residence time4Induced Flue GasRecirculation BurnersYYN------x x xNeed to be upfired. Need convectiveloop to get gas recirculatedDraws flue gas to dilute the fuel in order to reduce the flame temperature5 Low Excess AirYN---------xNeed high O2for process requirementsand product qualityReduces oxygen content in flue gas and reduces flame temperature6Burners out of Service(BOOS)YN---------xNeed capacity of all burners for worstcase scenarioShut off the fuel flow from one burner or more to create fuel rich and fuellean zones7 Fuel BiasingYN---------xPower plant technologyCombustion is staged by diverting fuel from the upper level burners to thelower ones or from the center to the side burners to create fuel-rich andfuel-lean zones8 ReburningYN---------xKiln configuration not correct for thistechnology.Part of the total fuel heat input is injected into the furnace in a regionabove the primary (main burners) flames to create a reducing atmosphere(re-burn zone), where hydrocarbon radicals react with NOx to produceelemental nitrogen9 Load ReductionN------------xPower plant technology -productdemand side solutionThis is a strategy to reduce load on a power plant by reducing theelectrical demand throught efficiency projects.10 Energy Efficiency Projects YYY(for largeprojects likeheat-recoup)Y(for largeprojects likeheat-recoup)Site-specificxdecrease amount of fuel required to make an acceptable product11 Coal DryingYN---------xApplies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel isrequired to be burned. Specific energy efficiency project12Coal Addition to Pellets withLow Excess Air in theInduration FurnaceN------------xCheck on status of researchReduce flame temperature and energy requirements13 Ported KilnsYYY(grate-kilnsonly)N(Metso saysno NOximprovement)---x xApplicable to grate kilns.Provides additional oxygen for pellet oxidation which reduces the overallenergy use of the kiln14 Combustion Zone Cooling YN---------xBoiler technologyCooling of the primary flame zone by heat transfer to surroundingsurfaces15 Alternate FuelsYYY(for furnacescapable ofmultiple fuels)Y(not requiredby BART)Site-specificx xRequires case by case analysis.Typically, facilities experience lowerNOx when burning solid fuels.Lower combustion temps with solid fuels vs gas. May also reduce fuelNOx by using a fuel with less nitrogen.16Oxygen EnhancedCombustionN------------xResearch levelA small fraction of the combustion air is replaced with oxygen.Taconite BART AnalysisNOx ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology 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?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle17 Preheat Combustion N------------xResearch levelPulverized coal preheated and volatiles and fuel-bound nitrogencompounds are released in a controlled reducing atmosphere where thenitrogen compounds are reduced to N2.18 ROFA-ROTAMIX Y N --- ------xCan't achieve correct temperaturewindow (1400-1800F). Too hot in kilntoo cold in reheatCombination of OFA and SCR. Wall-fired or tangentially-fired furnace thatutilizes high velocity overfire air. Additional NOx reductions are achievedwith ammonia injection (Rotamix)19 NOx CEMSYN---------x xOptimization of combustion20 Parametric Monitoring YN---------x xOptimization of combustion38Catalyst Injection(EPS Technologies)N------------xResearch LevelA combustion catalyst is directly injected into the air intake stream anddelivered to the combustion site, initiating chemical reactions that changethe dynamics of the flame.Post Combustion Controls21Non-Selective CatalyticReduction (NSCR)Y N --- ------xxFor clean services. Too much stuff influe gas would poison catalystUnder near stoichiometric conditions, in the presence of a catalyst, NOx isreduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2).22Low Temperature Oxidation(LTO) - Tri-NOx®YN---------xxUsed for higher flue gas concentrationsUtilizes an oxidizing agent such as ozone to oxidize various pollutantsincluding NOx23Low Temperature Oxidation(LTO) - LoTOxYN---------x x xHas been included as an "applicableand available" technology in recentBACT analyses from multiple facilities.Utilizes an oxidizing agent such as ozone to oxidize various pollutantsincluding NOx24Selective CatalyticReduction (SCR)YYYY80%x x xNeed to inject at appropriatetemperature (reheat will be required).Applicable on clean side only.Although this hasn't beendemonstrated on an induratingfurnace, the stream characteristicsappear to make this technologyfeasible.Ammonia (NH3) is injected into the flue gas stream in the presence of acatalyst to convert NOx into N2and water25 Regenerative SCRYN---------xClean side only26Selective Non-CatalyticReduction (SNCR)YN---------xxCan't achieve correct temperaturewindow (1400-1800F). Too hot in kilntoo cold in reheatUrea or ammonia-based chemicals are injected into the flue gas stream toconvert NO to molecular nitrogen, N2, and water27 AdsorptionN------------xStill in research stages.Use of char (activated carbon) to adsorb oxides of nitrogen28 AbsorptionYN---------xSimilar to TriNOxUse of water, hydroxide and carbonate solutions, sulfuric acid, organicsolutions, molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.29 OxidizerYN---------xRedundant to regenerative SCRGas stream is sent through the regenerative, recuperative, catalytic ordirect fired oxidizer where pollutants are heated to a combustion point anddestroyed.Taconite BART AnalysisNOx ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology 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?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle30SNOXN------------xEarly commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converterpasses through a novel glass-tube condenser in which the SO3ishydrated to H2SO4vapor and then condensed to a concentrated liquidsulfuric acid (H2SO4).31 SOx-NOx-Rox-BoxN------------xTechnology has not beendemonstratedDry sorbent injection upstream of the baghouse for removal of SOx andammonia injection upstream of a zeolitic selective catalytic reduction(SCR) catalyst incorporated in the baghouse to reduce NOx emissions.32 Electron (E-Beam) Process N------------xNo operating commercial applicationson coalElectron beam irradiation in the presence of ammonia to initiate chemicalconversion of sulfur and nitrogen oxides into components which can beeasily collected by conventional methods such as an ESP or baghouse.33 Electrocatalytic Oxidation N------------xSimilar to cold plasma. Will keepwatch for availability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using nonthermal plasma.On recent project, the vender was doing final trials on full-scaleapplications.34NOXSON------------Commercial version of adsorption.Limited experience (proof-of-concepttests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx fromflue gas from coal-fired utility and industrial boilers. In the process, theSO2is converted to a saleable sulfur by-product (liquid SO2, elementalsulfur, or sulfuric acid) and the NOx is converted to nitrogen and oxygen.35 Copper-OxideN------------xAbsorption and SCR. Experiencelimited to pilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheresof alumina, to form copper sulfate. Ammonia is injected into the flue gasbefore the absorption reactor and a selective catalytic reduction-typereaction occurs that reduces the nitric oxides in the flue gas. In theregeneration step, the copper sulfate is reduced in a regenerator with areducing agent, such as natural gas, producing a concentrated stream ofSO2.36 Cold PlasmaN------------xResearch Level37 BiofiltersYN---------xNot applicable to furnaces.Gas stream is passed through a filter medium of soil and microbes.Pollutants are adsorbed and degraded by microbial metabolism formingthe products carbon dioxide and water.38 Pahlman ProcessN------------xResearch LevelGas stream is passed through a filter baghouse in which speciallydeveloped, small-particle, high-surface area metal oxide sorbent havebeen deployed. Pollutants are removed from the gases by adsorption.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 ReportsTaconite BART AnalysisSO2 ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1SO2Pollution ControlTechnology 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?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle1Wet Scrubbing (HighEfficiency)YYYY 90-95%x x xAbsorption and reaction using an alkaline reagent to produce a solid compound2Wet Scrubbing (LowEfficiency)YYYY<50%x x xAbsorption and reaction using an alkaline reagent to produce a solid compound3Wet Walled ElectrostaticPrecipitator (WWESP)YYYY80%xxSuspended particles are separated from the flue gas stream, attracted to plates, andcollected in hoppers4 Dry sorbent injectionYYYN---x x xPulverized lime or limestone is directly injected into the duct upstream of the fabricfilter. Dry sorption of SO2onto the lime or limestone particle occurs and the solidparticles are collected with a fabric filter5 Spray Dryer Absorption (SDA)Y Y Y N ---x xLime slurry is sprayed into an absorption tower where SO2is absorbed by theslurry, forming CaSO3/CaSO46 Alternative FuelsY YY(for furnacescapable ofmultiple fuels)Y(not requiredby BART)Site-specificx xNatural gas is base caseUse a fuel with lower sulfur content.7 Load ReductionN------------xPower plant technologyThis is a strategy to reduce load on a power plant by reducing the electricaldemand throught efficiency projects.8 Energy Efficiency ProjectsYYY(for largeprojects likeheat-recoup)Y(for largeprojects likeheat-recoup)Site-specificxdecrease amount of fuel required to make an acceptable product9 Coal DryingY N --- ------xApplies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is requiredto be burned. Specific energy efficiency project10Bio FiltersN------------xResearch levelGas stream passes through a packed bed of specially engineered biomedia whichsupports the growth of active bacterial species. The pollutants in the gas stream arebiodegraded or biotransformed into innocuous products, such as carbon dioxide,water, chloride ion in water, sulfate or nitrate ions in water.11CANSOLV Regenerable SO2N------------xResearch levelAn aqueous solution of proprietary diamine captures SO2from the feed gas in acountercurrent absorption tower. The rich solvent is regenerated by steamstripping, giving a byproduct of pure, water saturated SO2gas and lean solvent forrecycling to the absorber.12 Pahlman ProcessN ------------xResearch levelGas stream is passed through a filter baghouse in which specially-developed, smallparticle, high-surface area metal oxide sorbent have been deployed. Pollutants areremoved from the gases by adsorption.13 SOx-NOx-Rox-BoxN------------xTechnology has not been demonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammoniainjection upstream of a zeolitic selective catalytic reduction (SCR) catalystincorporated in the baghouse to reduce NOx emissions.14 Electron (E-Beam) ProcessN------------xNo operating commercial applications oncoalElectron beam irradiation in the presence of ammonia to initiate chemicalconversion of sulfur and nitrogen oxides into components which can be easilycollected by conventional methods such as an ESP or baghouse.Taconite BART AnalysisSO2 ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1SO2Pollution ControlTechnology 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?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle15 Electrocatalytic OxidationN ------------xSimilar to cold plasma. Will keep watch foravailability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-thermalplasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSON------------Commercial version of adsorption. Limitedexperience (proof-of-concept tests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gasfrom coal-fired utility and industrial boilers. In the process, the SO2is converted toa saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) and theNOx is converted to nitrogen and oxygen.17 Copper-OxideN ------------xAbsorption and SCR. Experience limited topilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheres ofalumina, to form copper sulfate. Ammonia is injected into the flue gas before theabsorption reactor and a selective catalytic reduction-type reaction occurs thatreduces the nitric oxides in the flue gas. In the regeneration step, the copper sulfateis reduced in a regenerator with a reducing agent, such as natural gas, producing aconcentrated stream of SO2.18 SNOXN ------------xEarly commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converter passesthrough a novel glass-tube condenser in which the SO3is hydrated to H2SO4vaporand then condensed to a concentrated liquid sulfuric acid (H2SO4).19 Cold PlasmaN ------------xResearch level1) 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 ReportsSummary of Relevant Economic Feasibility ($/ton) Control CostsAvg. Expected Values($/ton)Limiting/Marginal values($/ton)ReferenceRegulatory Body/RuleSO2NOxSO2NOxCommentsBART100 - 1000 100 - 100070 FR 39135BART281 - 129670 FR 39135 Table 3BART91970 FR 39133FR Notice 6JULY05 Final RuleBARTGuidelines disparagingly reference "thousands of dollars per ton"in commenting on the need to exceed MACT and its generalunreasonableness.70 FR 25210 CAIRCAIR1300Estimated Marginal cost 2009BART(proposed rule) 200-1000BART proposed lists this as values for 90-95% SO2 control,which is still assumed, or .1 to .15 lb/MMBtu. Dropped fromfinal to give states flexibility to require more. Says for scrubbers,bypasses aren't BART, only 100% scrubbing is BART.FR Notice 5MAY04 Proposed RuleBART(proposed rule)0.2 lb/MMBtu for NOx is assumed reasonable. Recognizes thatsome sources may need SCR to get this level. For those, statediscretion of the cost vs. visibility value is necessary.CAIR(using IPM)1000 1500CAIR ( 2009 in 1999$)9002400CAIR ( 2015 in 1999$)18003000Midwest RPO Report ReferencingCAIRCAIR (depending onNat'l emissions)1200 - 3000 1400- 2100This was modeled with TRUM (Technology RetrofittingUpdating Model) to develop the marginal values.Kammer EPA DecisionKammer Decision> 1000 > 1000LADCO Midwest RPO BoilerAnalysisLADCO/Midwest RPO 1240 - 3822 607 - 4493MANE-VU BART ControlAssessmentMANE-VU200 - 500 200 - 1500Bowers vs. SWAPCABowers vs. SWAPCA 300 300 1000 1000954-1134 was ruled too much, in favor of 256-310 for SO2. Thisdid consider incremental value. Sections XVII to XIXWRAP3000WRAP Trading ProgramMethodologyEPA - Referenced byWrapReferences EPA-600S\7-90-018. Low is <$500/ton, Moderate is$500-3000/ton, High is over $3000/tonThe dollars per ton estimates cited above were obtained from BART guidance, documentation of similar regulatory programs such as CAIR,and relevant court decisions. These materials indicate that most EPA sanctioned documents, including the final BART ruling, concretelysupport an average expected reasonable cost range of $1,300 to $1,800 per ton of NOx removed and a range of $1,000 to $1,300 per ton ofSO2removed. The BART presumptive limits were set based on cost effective controls that were on average less than these ranges. As anexample, the presumptive SO2limit was established based on an average cost effectiveness of less than $1,000/ton. As the cost analysisextends into RPO, WRAP and other regional planning documentation, the cost ranges become more variable and difficult to predict. Forease of comparison, the federally established ranges for NOx and SO2were used as a BART cost threshold basis.