## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# i 

# Northshore Mining Company Analysis of Best Available Retrofit Technology (BART)

Table of Contents

1. Executive Summary.............................................................................................................................iv
2. Introduction...........................................................................................................................................1 2.A BART Eligibility.........................................................................................................................3 2.B BART Determinations ................................................................................................................4
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 ...........................................................................................................10 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 ..........................................................................................19
5. Full BART Analysis for BART Eligible Emission Units...................................................................21 5.A Indurating Furnace....................................................................................................................21 5.A.i Sulfur Dioxide Controls............................................................................................... 22 5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 22 5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 22 5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies................................................................................................ 27 5.A.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 28 5.A.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 30 5.A.ii Nitrogen Oxide Controls.............................................................................................. 30 5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 31 5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 31 5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies................................................................................................ 43 5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results............................... 44 5.A.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 45 5.B External Combustion Sources...................................................................................................47 5.B.i Sulfur Dioxide controls................................................................................................ 47 5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 47 5.B.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 47

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# ii 5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies................................................................................................ 51 5.B.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 51 5.B.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 53 5.B.ii Nitrogen Oxide Controls.............................................................................................. 54 5.B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 54 5.B.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 54 5.B.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies................................................................................................ 61 5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results............................... 62 5.B.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 64
6. Visibility Impacts................................................................................................................................67 6.A Post-BART Modeling Scenarios...............................................................................................67 6.B Post-BART Modeling Results ..................................................................................................67
7. Select BART.......................................................................................................................................71

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..15 Table 4-2 Baseline Visibility Modeling Results..........................................................................20 Table 5-1 Indurating Furnace SO 2 

# Control Technology – Availability, Applicability, and

Technical Feasibility ..................................................................................................27 Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness.........................................27 Table 5-3 Indurating Furnace SO 2 

# Control Cost Summary ..........................................................29 Table 5-4 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and

Technical Feasibility ..................................................................................................43 Table 5-5 Indurating Furnace NO x 

# Control Technology Effectiveness ........................................43 Table 5-6 Indurating Furnace NO x 

# Control Cost Summary .........................................................44 Table 5-7 Backup Process Boiler SO 2 

# Control Technology – Availability, Applicability, and

Technical Feasibility ..................................................................................................51 Table 5-8 Backup Process Boiler SO 2 

# Control Technology Effectiveness ...................................51 Table 5-9 Backup Process Boiler SO2 Control Cost Summary....................................................52 Table 5-10 Backup Process Boiler NO x 

# Control Technology – Availability, Applicability and

Technical Feasibility ..................................................................................................61 Table 5-11 Backup Process Boiler NOx Control Technology Effectiveness ..................................61 Table 5-12 Backup Process Boiler NO x 

# Control Cost Summary....................................................62 Table 5-13 Backup Process Boiler NO x 

# Control Technology – Other Impacts Assessment............63 Table 5-14 Backup Process Boiler NO x 

# Post- BART Emission Rates for Emission Unit EU003 and

EU004........................................................................................................................64 Table 5-15 Backup Process Boiler Post-BART Modeling Scenarios .............................................65 Table 5-16 Backup process Boiler Post-BART NO x 

# Modeling Scenarios - Modeling Input Data ..66

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# iii Table 5-17 Backup Process Boiler Post-BART NO x 

# Modeling Scenarios - Visibility Modeling

Results .......................................................................................................................66 Table 5-18 Backup Process Boiler Post-BART NO x 

# Modeling Scenarios – Comparison of

Visibility Modeling Results to Baseline Modeling Results..........................................66 Table 6-1 Post-BART Modeling Scenarios .................................................................................69 Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results ...................................70 Table 6-3 Post-BART Modeling Scenarios – Comparison of Visibility Modeling Results to

Baseline Modeling Results .........................................................................................70

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 for Indurating Furnaces Appendix E Clean Air Interstate Rule (CAIR), Cost-Effective Air Pollution Controls Appendix F Applicable and Available Retrofit Technologies for Process Boilers

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# iv 

# 1. Executive Summary

Northshore Mining Company (NMC) is located in northern Minnesota, with mining facilities located at Babbit and a taconite processing plant located at Silver Bay. This report describes the background and methods for the selection of the Best Available Retrofit Technology (BART) as proposed by NMC for its taconite processing plant.

Minnesota Pollution Control Agency MPCA identified 36 pieces of equipment at NMC that were installed within the time window (1962-1977) that makes them subject to BART. The equipment includes two straight-grate indurating furnace lines (Furnaces 11 and 12) and two backup steam process boilers ( Process Boilers 1 and 2) that use natural gas and oil for fuel, as well 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 NMC “cause or contribute to visibility impairment” in a federally protected Class I area, therefore making the facility subject to BART.

Guidelines included in 40 CFR §51 Appendix Y and MPCA Attachments 2 and 3 were used to propose BART. The existing pollution control equipment on the furnace lines includes a wet walled electrostatic precipitator (WWESP) designed to control of particulate matter (PM) and sulfur dioxide (SO 2 

# ). A dispersion modeling sequence of CALMET, CALPUFF, and CALPOST 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. Other criteria that the BART rules require to be considered include the availability of technology, costs of compliance, energy and environmental impacts of compliance, existing pollution control technology in use at the source, and the remaining useful life of the source.

Based on consideration of all of the above criteria, NMC proposes the following as BART:

• SO 2 

# emissions will be controlled by the existing WWESPs on the taconite furnaces. The process boilers will have no additional controls. NO x 

# emissions will be controlled by good combustion practices for the taconite mining process for the furnaces and process boilers.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# v • PM emissions at the furnaces will be controlled as prescribed by the taconite maximum achievable control technology (MACT) standard 1 

# . The existing WWESPs adequately control PM emissions from the furnaces to meet the MACT standard. The process boilers will have
no additional controls.

The CALPUFF model is conservative, resulting in an over prediction of impacts 2 

# . This modeled high impact from the BART eligible sources is 1.1 deciviews (dV), slightly above perceptible levels of one to two dV. The modeling also shows that these sources do affect Class I area visibility at less than 10 percent of the time based on the model predicting an impact greater than 0.5dV only 34 to 38 days per year. Real impacts to the Class I areas from NMC are expected to be even less than these modeled impacts. NMC will continue to evaluate energy efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission rates.

1 

# 40 CFR 63 Subpart RRRRR-and DDDDD NESHAPS: Taconite Iron Ore Processing and Industrial Commercial and Institutional Boilers and Process Heaters 2 

# Federal Register 70, 128 (July 6, 2005): 39123

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 1 

# 2. Introduction

Northshore Mining Company (NMC) is located in northern Minnesota, with mining facilities located at Babbit and a taconite processing plant located at Silver Bay.. This report describes the background and methods for the selection of the Best Available Retrofit Technology (BART) as proposed by NMC for its taconite processing plant.

To meet the Clean Air Act’s requirements, the U.S. Environmental Protection Agency (U.S. EPA) published regulations to address visibility impairment in our nation’s largest national parks and wilderness (“Class I”) areas in July 1999. 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 is found in 40 CFR part 51, in 300 through 309.

Within its boundary, Minnesota has two Class I areas – the Boundary Waters 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 enforceable through rules, administrative orders or Title V permit amendments.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 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. Facilities indicated in yellow are future facilities. (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 than the 20 worst days under natural conditions by 2064 3 

# . 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.

3 

# See the preamble to the final BART and Regional Haze Rules, 70 FR No. 178, pp. 39104-39172

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 3 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 state may rely upon in making ‘reasonable progress” towards regional haze improvement goals.


# 2.A BART Eligibility BART eligibility is established on the basis on 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) will be required to conduct visibility analyses. 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.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 4 

# 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 for each source. The BART analysis takes into account six criteria and is analyzed using five steps. The six 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. 4 

# The five steps of a BART analysis are:

Step 1 - Identify all Available Retrofit Control Technologies

The first step in the analysis is to identify all retrofit control technologies which are generally available for each applicable emission unit. Available retrofit control technologies are defined by U.S. EPA in Appendix Y to Part 51 (Guidelines for BART Determinations Under the Regional Haze Rule) 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. 5



# Step 2 - Eliminate Technically Infeasible Options

In the second step, the source-specific technical feasibility of each control option identified in step one is evaluated by answering three specific questions:

4 

# 40 CFR 51 Appendix Y 5 

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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 5 1. Is the control technology “available” to the specific source which is undergoing the BART analysis?

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. 6 

# ” 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. 7 

# ”

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. 8 

# ” 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 10 

# .” 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 11



# .

6 

# Federal Register 70, No. 128 (July 6, 2005): 39165 7 

# IBID 8 

# IBID 9 

# IBID 10 

# IBID 11 

# IBID

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 6 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 as “sufficient justification 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 12



# .
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 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 13 

# , including receptor grid, meteorological data, and other factors used for this part of the analysis were provided by the Minnesota

12 

# IBID 13 

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

.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 7 Pollution Control Agency. The model outputs, including the 98th percentile dV value and the number of days the facility contributes more than a 0.5 deciview (dV) of 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. In addition, 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. 14



# 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 15 

# .” 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 16 

# .” which could include the incorporation of other regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR

14 

# MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis . Page 20. 15 

# MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis . Page 23. 16 

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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 8 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 infeasible, the BART limit can “instead prescribe a design, equipment, work practice, operation standard, or combination of these types of standards 17 

# .”

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

17 

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

## Y :\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 9 

# 3. Streamlined BART Analysis

Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include a streamlined approach for BART analyses 18 

# . 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.


# 3.A Indurating Furnaces The indurating furnaces are sources of three visibility impairing pollutants: NO x 

# , SO 2 

# , and PM. The indurating furnaces is subject to the taconite MACT standard 19 

# 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.” [Attachment 2, March 2006, page 2]. 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 [FR, December 18, 2002, page 77570]. Therefore, the emissions from the pellet coolers are considered to have a negligible impact on visibility impairment, and no control requirements under the MACT standard is consistent with the intention of the BART analysis.

18 

# Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116 19 

# 40 CFR 63 Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing

## Y :\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 10 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 at NMC as potentially BART-eligible equipment, so these sources are not required to be addressed. Therefore, no further analysis will be required to establish BART for these 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. They include units such as:

• Bentonite storage and handling

• Additive storage and handling

• Concentrate storage and handling
Considering all PM emissions which are subject to the BART standard, the PM emissions from the above units typically represent less than 2.5% of PM emissions from the facility, which are subject to
BART.

The point source emission units are controlled by baghouses, which is a technology that achieves a high level 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. Existing controls will be considered BART consistent with direction from MPCA in the May 18, 2006 meeting.

No equipment that emits fugitive PM has been identified at NMC as potentially BART-eligible equipment, so these sources are not required to be addressed. No further analysis will be required to
establish BART for these sources.



# 3.E Other Combustion Units The combustion units are sources of three visibility impairing pollutants: NO x 

# , SO 2 

# , and PM.

## Y :\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 11 NMC facility has two process boilers that are subject to the boiler MACT 20 

# . Since the boiler MACTstandards were established recently and become effective in 2007, the technology analysis is up-todate. For the units subject to the boiler MACT standard, BART will be presumed to be equivalent to MACT for PM according to MPCA guidance. A full BART analysis will be conducted for NO x 

# and
SO 2 

# .
The Northshore facility also has a powerhouse which will require a full BART analysis. That analysis is provided in a separate report.


# 3.F Visibility Impact Modeling for Negligible Impacts The streamlined BART approach allows for a screening modeling demonstration of negligible visibility impacts for fugitive sources and combustion units other than indurating furnaces and process boilers. NMC does not have any potentially BART eligible sources that require screening modeling.

20 

# 40 CFR 63 Subpart DDDDD-NESHAPS: ICI Boilers and Process Heaters

## Y :\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

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

Emission Unit # Emission Unit Description VisibilityImpairing Pollutant Applicable

Limit 1 

# gr/dscf Maximum Daily

lbs/day 2 

# 3.A Indurating Furnaces EU 100 Furnace 11 Hood Exhaust PM 0.01 272 EU 100 Furnace 11 Hood Exhaust PM 0.01 272 EU 100 Furnace 11 Hood Exhaust PM 0.01 272 EU 104 Furnace 11 Waste Gas PM 0.01 255 EU 104 Furnace 11 Waste Gas PM 0.01 255 EU 110 Furnace 12 Hood Exhaust PM 0.01 272 EU 110 Furnace 12 Hood Exhaust PM 0.01 272 EU 110 Furnace 12 Hood Exhaust PM 0.01 272 EU 114 Furnace 12 Waste Gas PM 0.01 255 EU 114 Furnace 12 Waste Gas PM 0.01 255 3.B PM-Only Taconite MACT Emission Units EU 008 East Car Dump PM 0.008 32 EU 010 Fine Crusher Bin Storage – East PM 0.008 45 EU 016 Crushed Ore Conveyors – East PM 0.008 12 EU 017 Fine Crushing Line 101 PM 0.008 8 EU 018 Fine Crushing Line 102 PM 0.008 8 EU 019 Fine Crushing Line 103 PM 0.008 8 EU 020 Fine Crushing Line 104 PM 0.008 8 EU 031 Concentrator Transfer Bin – East PM 0.008 8 EU 044 Concentrator Bin - Section 101 PM 0.008 18 EU 045 Concentrator Bin - Section 102 PM 0.008 18 EU 046 Concentrator Bin - Section 103 PM 0.008 18 EU 047 Concentrator Bin - Section 104 PM 0.008 18 EU 048 Concentrator Bin - Section 105 PM 0.008 18 EU 049 Concentrator Bin - Section 106 PM 0.008 18 EU 050 Concentrator Bin - Section 107 PM 0.008 18 EU 051 Concentrator Bin - Section 108 PM 0.008 18 EU 052 Concentrator Bin - Section 109 PM 0.008 18 EU 053 Concentrator Bin - Section 110 PM 0.008 18 EU 120 Furnace 11 Discharge PM 0.008 95 EU 121 Furnace 12 Discharge PM 0.008 95 EU 122 Furnace 11 Screening PM 0.008 95 EU 124 Furnace 12 Screening PM 0.008 95 3.D Non-MACT Emission Units and Fugitive Sources (PM-Only) EU 077 Furnace 11 Day Bin Collector PM 0.01 4 EU 078 Furnace 11 Air Slide Collector PM 0.01 4 EU 079 Furnace 12 Day Bin Collector PM 0.01 4 EU 080 Furnace 12 Air Slide Collector PM 0.01 4 EU 081 East Pelletizer Bentonite Storage - Bin 3,4 PM 0.01 4 EU 082 East Pelletizer Bentonite Storage - Bin 5,6 PM 0.01 4 EU 083 Bentonite Unloading Collector PM 0.01 4 EU 084 Supplemental Bentonite Unloading Collector PM 0.01 10 3.E Other Combustion Units lb/mmBtu EU 003 Process Boiler #1 PM 0.6 45 EU 004 Process Boiler #2 PM 0.6 45 1 

# PM – Filterable PM only as measured by U.S. EPA Method 5 including the applicable averaging and grouping provisions, as presented in the MACT regulation, effective October 26, 2006. 2 

# Based on baseline flow rates.

## Y :\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 13 

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

As indicated in U.S. EPA’s final BART guidance 21 

# , 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 estimated using CALPUFF, an U.S. EPA approved model recommended for comparing the visibility improvements of different retrofit control
alternatives 22 

# (REFERNECE FED. GUIDANCE PREAMBLE pages 39127 – 39129 as appropriate). However it is important to note that CALPUFF is a conservative model that over estimates real impacts. Therefore, although the CALPUFF baseline modeling results are important to comparing control alternatives on a relative basis they are do not accurately predict real impacts.

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.

In order to estimatedetermine 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 23



# . 

# 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

21 

# Federal Register 70, no. 128 (July 6, 2005): 39106. 22 

# Federal Register 70, no. 128 (July 6, 2005): 39125 23 

# MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota. Page 8.

## Y :\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 14 reported in units of pounds per hour (lbs/hr) and were 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 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 NMC 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.

In addition, the maximum 24-hour emission rates were re-evaluated internally within NMC to confirm that the emission rates represent the maximum steady-state operating conditions during periods of high capacity utilization. The maximum 24-hour emission rates were not adjusted.

The facility baseline data is summarized in the Table 4-1. The full modeling analysis is presented in Appendix C.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc15Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions DataEU #EUDescriptionSO2Maximum24-hrEmissionRate(lbs/day)Basis forSO2 24-hourActualEmissionNOxMaximum24-hrEmissionRate(lbs/day)Basis forNOx 24-hourActualEmissionPM2.5Maximum24-hrEmissionRate(lbs/day)Basis forPM2.524-hourActualEmissionPM10Maximum24-hrEmissionRate(lbs/day)Basis forPM1024-hourActualEmissionSV #StackEasting(utm)StackNorthing(utm)Height ofOpeningfromGround(ft)BaseElevationof Ground(ft)Stacklength,width, orDiameter(ft)FlowRate atexit(acfm)ExitTemp(oF)EU003ProcessBoiler #1402 27945 SV003 631471.5 5238482.8 131 611 6.5 59900 450EU004ProcessBoiler #2402 27945 SV003 631471.5 5238482.8 131 611 6.5 59900 450EU008East CarDumpNA NA NA NA 32 SV008 631224.7 5238953.7 83 870 5.0 62600 77EU010FineCrusherBinStorage -EastNA NA NA NA 45 SV010 631316.0 5238925.9 101 767 6.0 90100 77EU016CrushedOreConveyors - EastNA NA NA NA 12 SV016 631314.1 5238884.6 69 767 3.3 22400 77EU017FineCrushingLine 101NA NA NA NA 8 SV017 631322.8 5238896.8 69 767 2.7 15,000 77EU018FineCrushingLine 102NA NA NA NA 8 SV018 631328.6 5238905.9 69 767 2.7 15,000 77EU019FineCrushingLine 103NA NA NA NA 8 SV019 631334.4 5238915.1 69 767 2.7 15,000 77EU020FineCrushingLine 104NA NA NA NA 8 SV020 631341.2 5238924.2 69 767 2.7 15,000 77EU031ConcentratorTransferBin -EastNA NA NA NA 8 SV031 631455.6 5238785.1 83 696 2.7 18000 77EU044Concentrator Bin -Section101NA NA NA NA 18 SV044 631473.1 5238808.5 93 716 3.3 29200 77EU045Concentrator Bin -Section102NA NA NA NA 18 SV045 631486.7 5238828.7 93 716 3.3 29200 77Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc16EU #EUDescriptionSO2Maximum24-hrEmissionRate(lbs/day)Basis forSO2 24-hourActualEmissionNOxMaximum24-hrEmissionRate(lbs/day)Basis forNOx 24-hourActualEmissionPM2.5Maximum24-hrEmissionRate(lbs/day)Basis forPM2.524-hourActualEmissionPM10Maximum24-hrEmissionRate(lbs/day)Basis forPM1024-hourActualEmissionSV #StackEasting(utm)StackNorthing(utm)Height ofOpeningfromGround(ft)BaseElevationof Ground(ft)Stacklength,width, orDiameter(ft)FlowRate atexit(acfm)ExitTemp(oF)EU046Concentrator Bin -Section103NA NA NA NA 18 SV046 631501.3 5238849.0 93 716 3.3 29200 77EU047Concentrator Bin -Section104NA NA NA NA 18 SV047 631514.8 5238870.3 93 716 3.3 29200 77EU048Concentrator Bin -Section105NA NA NA NA 18 SV048 631529.4 5238890.7 93 716 3.3 29200 77EU049Concentrator Bin -Section106NA NA NA NA 18 SV049 631544.0 5238911.0 93 716 3.3 29200 77EU050Concentrator Bin -Section107NA NA NA NA 18 SV050 631557.6 5238932.3 93 716 3.3 29200 77EU051Concentrator Bin -Section108NA NA NA NA 18 SV051 631572.1 5238952.6 93 716 3.3 29200 77EU052Concentrator Bin -Section109NA NA NA NA 18 SV276 631590.6 5238980.0 93 716 3.3 29200 77EU053Concentrator Bin -Section110NA NA NA NA 18 SV053 631605.2 5239000.3 93 716 3.3 29200 77EU077Furnace11 DayBinCollectorNA NA NA NA 4 SV077 631274.7 5238341.3 97 670 0.8 1,800 77EU078Furnace11 AirSlideCollectorNA NA NA NA 4 SV078 631315.5 5238399.2 97 670 0.8 1,800 77EU079Furnace12 DayBinCollectorNA NA NA NA 4 SV079 631276.6 5238344.4 97 670 0.7 1,800 77Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc17EU #EUDescriptionSO2Maximum24-hrEmissionRate(lbs/day)Basis forSO2 24-hourActualEmissionNOxMaximum24-hrEmissionRate(lbs/day)Basis forNOx 24-hourActualEmissionPM2.5Maximum24-hrEmissionRate(lbs/day)Basis forPM2.524-hourActualEmissionPM10Maximum24-hrEmissionRate(lbs/day)Basis forPM1024-hourActualEmissionSV #StackEasting(utm)StackNorthing(utm)Height ofOpeningfromGround(ft)BaseElevationof Ground(ft)Stacklength,width, orDiameter(ft)FlowRate atexit(acfm)ExitTemp(oF)EU080Furnace12 AirSlideCollectorNA NA NA NA 4 SV080 631318.4 5238402.2 97 670 0.8 1,800 77EU081EastPelletizerBentoniteStorage -Bin 3,4NA NA NA NA 4 SV081 631311.2 5238408.2 129 670 0.7 1,800 77EU082EastPelletizerBentoniteStorage -Bin 5,6NA NA NA NA 4 SV082 631318.0 5238419.3 130 670 0.7 1,800 77EU083BentoniteUnloadingCollectorNA NA NA NA 4 SV083 631320.9 5238422.4 127 670 0.7 1,300 77EU084SupplementalBentoniteUnloadingCollectorNA NA NA NA 10 SV084 631331.9 5238426.5 117 670 1.7 4,900 77EU100Furnace11 HoodExhaust284 410272 SV101 631339.1 5238341.2 121 636 6.0 70700 142EU100Furnace11 HoodExhaust284 410272 SV102 631344.3 5238338.3 121 636 6.0 74300 142EU100Furnace11 HoodExhaust284 410272 SV103 631348.4 5238335.3 121 636 6.0 77400 142EU104Furnace11 WasteGas142 1498255 SV105 631343.4 5238298.9 134 636 6.0 93,000 140EU104Furnace11 WasteGas142 1498255 SV104 631334.2 5238298.9 134 636 6.0 93,000 140EU110Furnace12 HoodExhaust284 410272 SV111 631361.5 5238372.7 121 636 6.0 70700 142Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc18EU #EUDescriptionSO2Maximum24-hrEmissionRate(lbs/day)Basis forSO2 24-hourActualEmissionNOxMaximum24-hrEmissionRate(lbs/day)Basis forNOx 24-hourActualEmissionPM2.5Maximum24-hrEmissionRate(lbs/day)Basis forPM2.524-hourActualEmissionPM10Maximum24-hrEmissionRate(lbs/day)Basis forPM1024-hourActualEmissionSV #StackEasting(utm)StackNorthing(utm)Height ofOpeningfromGround(ft)BaseElevationof Ground(ft)Stacklength,width, orDiameter(ft)FlowRate atexit(acfm)ExitTemp(oF)EU110Furnace12 HoodExhaust284 410272 SV112 631365.6 5238369.7 121 636 6.0 74300 142EU110Furnace12 HoodExhaust284 410272 SV113 631370.7 5238366.8 121 636 6.0 77400 142EU114Furnace12 WasteGas142 1498255 SV114 631354.5 5238331.4 134 636 6.0 93,000 140EU114Furnace12 WasteGas142 1498255 SV115 631362.7 5238325.5 134 636 6.0 93,000 140EU120Furnace11DischargeNA NA NA NA 95 SV120 631383.5 5238300.6 91 636 3.8 48000 150EU121Furnace12DischargeNA NA NA NA 95 SV121 631405.9 5238332.1 91 636 3.8 48000 150EU122Furnace11ScreeningNA NA NA NA 95 SV122 631387.6 5238297.7 91 636 3.8 48000 150EU124Furnace12ScreeningNA NA NA NA 95 SV124 631380.9 5238282.5 91 636 3.8 48000 130

## Y :\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 19 

# 4.C Facility Baseline Modeling Results The Minnesota BART modeling protocol 24 

# describes the CALPUFF model inputs, including the meteorological data set and background atmospheric ammonia and ozone concentrations, along with the functions of CALPOST post processing.. The CALPOST output files provide the following two methods to assess the expected post-BART visibility improvement:

• 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 25 

# , 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 However, the results also indicate that the highest modeled impact may not exceed human perceptibility which is on the order of one to two dV. In addition, the modeling shows that these emission sources cause or contribute to visibility impairment less than 10 % of the time, based on the modeling results predicting 34 to 38 days annually above 0.5dV. 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.

24 

# MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota. Page 8. 25 

# MPCA. March 2006. Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the State of Minnesota.

## Y :\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 20 Table 4-2 Baseline Visibility Modeling Results

2002 2003 2004 2002 – 2004 Combined

Class I Area with Greatest Impact Modeled

98 th 

### Percentile Value (deciview) No. of

days exceeding 0.5 deciview Modeled

98 th 

### Percentile Value (deciview) No. of

days exceeding 0.5 deciview Modeled

98 th 

### Percentile Value (deciview) No. of

days exceeding 0.5 deciview Modeled

98 th 

### Percentile Value (deciview) No. of

days exceeding 0.5 deciview 

# BWCA 1.1 34 1.1 34 1.3 38 1.1 106

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 21 

# 5. Full BART Analysis for BART Eligible Emission Units

BART eligible sources at NMC can be divided into groups based upon type of process.


# 5.A Indurating Furnace The primary function of taconite indurating furnaces is to convert magnetic iron concentrate to a more highly oxidized iron in the form of a pellet that is sold to metallic iron and steel production facilities. “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. The process requires large amounts of air for pellet oxidation and cooling. Process temperature control in all parts of the furnace is critical to minimize product breakage in the initial process stages, allow required oxidation reactions to occur, and adequately cool the product prior to subsequent handling steps. Directed air flow, heat recovery and fuel combustion are critical to controlling temperature and product quality in all parts of the furnace. NMC 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. Direct-fired fuel combustion in the induration furnace is carried out at 300 % to 400 % excess air required 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, induration furnaces have 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 is directed to the process instead of heating ambient air to combustion temperatures.

NMC process has two straight-grate furnaces, Line 11 and Line 12 that are subject to BART. Line 11 and 12 are permitted to burn natural gas and fuel oil. Both line’s emissions are controlled by wet walled electrostatic precipitators (WWESP) using caustic reagent. The existing WWESP already provides excellent control and removal of PM and SO 2 

# .

Emissions of SO 2 

# result from low amounts of sulfur present in the ore and potentially from fuel oil use. Stack testing using natural gas fuel has demonstrated the WWESP effectively removes SO 2 

# to

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 22 one to two parts per million in the exhaust from the WWESPs. A recent BACT analysis for a similar furnace at NMC established an emissions limit of 10 parts per million SO2 using existing WWESPs.

NO x 

# is controlled through furnace design. The NMC furnaces emit the lowest tons of NO x 

# /long ton product of any taconite producer making similar pellets. NMCs furnaces are of an early vintage. Furnaces 11 and 12 have numerous burners critically located to supply heat to the various furnace sections. The burner layout limits production capability for the size of the furnace. This furnace design is not used by any other taconite producer.

The primary source of SO2 emissions in taconite production is from trace amounts of sulfur in the iron concentrate and binding agents present in the green balls. Sulfur is also present in distillate fuel oil that is one of the permitted fuels.



# 5.A.i Sulfur Dioxide Controls

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies See Appendix D for a comprehensive list of all potential retrofit control technologies that were evaluated. Many emerging technologies have been 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. As work on this evaluation progressed, new information became apparent of 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.

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options Step 1 identified the available and applicable technologies for SO 2 

# emission reduction. Within Step 2, the technical feasibility of the control option is discussed and determined. The following
section describes retrofit SO 2 

# control technologies that were identified as available and applicable in the original submittal and discusses aspects of those technologies that determine whether or not the technology is technically feasible for indurating furnaces.

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.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 23 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. WWESPs are designed to remove emissions to levels less than 10 parts per million SO2 .

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. NMC currently employs a WWESP designed for removal of particulate matter and SO 2 

# . The addition of a secondary 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 polishing WWESP is considered an available technology for SO 2 

# reduction for this BART analysis. The existing WWESP already removes SO 2 

# to a very low concentration. No other improvements are available to enhance the removal efficiency of the existing controls. Installation of a secondary WWESP is carried forward in this analysis.

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 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 packed-bed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO 2 

# wet scrubber could be as low as 30% control efficiency. 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 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:

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 24 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 a more reactive 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 minimal equipment is needed 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 excess oxygen of 2-3% 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 as well as creates higher flow rates to control. Additionally, the varying sulfur concentration within the pellet 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.

As stated in the beginning of this section, WWESPs are currently in place on the furnace exhausts
and are believed to remove 80 to 95% of the SO 2 

# in the exhaust. Taking into consideration of the
removal of SO 2 

# from the existing primary WWESP as well as a high efficiency SO 2 

# polishing wet scrubber, an overall efficiency of the control train would then be well over 90%.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 25 Based on the information contained within this report, a secondary 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 WWESP. 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.

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.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 26 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 pollution emissions. An example of an energy efficiency project could be to preheat incoming make-up air or pellet feed. 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, the facilities have already implemented energy efficiency projects. Each project carries its own fuel usage reductions and potentially 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 facilities 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 use fuels with lower sulfur content. NMC has the capability to only burn natural gas and distillate fuel oil in its furnaces. Therefore this option is not applicable for SO 2 

# reductions at NMC.

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. 26



# However, NMC will continue to evaluate and implement alternate fuel usage as the feasibility arises.

26 

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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 27 Coal Processing Since NMC does not burn coal in Furnaces 11 and 12, this option is not applicable for SO 2 

# reductions
at NMC.

Step 2 Conclusion Based upon the determination within Step 2, the remaining SO 2 

# control technologies that are available and applicable as secondary controls to the existing indurating furnace WWESPs 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



# SO 2 

# Pollution Control Technology Available? Applicable? Technically Feasible? 

# Secondary Wet Scrubbing (High

Efficiency) Yes Yes Yes
Secondary Wet Scrubbing (Low

Efficiency) Yes Yes Yes
Secondary Wet Walled Electrostatic Precipitator (WWESP) Yes Yes Yes
Dry sorbent injection Yes Yes No Spray Dryer Absorption (SDA) Yes Yes No Alternative Fuels Yes No No Energy Efficiency Projects Yes Yes No Coal Processing Yes No No

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. The WWESP and high efficiency wet scrubbing control options listed in Table 5-2 would be considered a polishing scrubber since a highly effective SO2 control WWESP currently exists.

Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness

SO 2 

# Pollution Control Technology Approximate Control Efficiency Secondary Wet Walled Electrostatic Precipitator (WWESP) 80

Secondary Wet Scrubber 60

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 28 5.A.i.d STEP 4 – Evaluate Impacts and Document the Results As illustrated in Table 5-2 above, the technically feasible control 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 WWESP after the existing WWESP 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 a recent vendor quotation. 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 8339 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 27 

# and engineering experience, and were adjusted for the specific flow rates and pollutant concentrations.

Due to space considerations, 60% 28 

# of the total capital investment was included in the costs to account for a retrofit installation. After a tour of the facility and discussions with facility staff, it was determined the space surrounding the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to transport materials to and from the building. 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.

27 

# U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition

. 28 

# U.S. EPA, CUE Cost Workbook Version 1.0 . Page 2.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 29

Table 5-3 Indurating Furnace SO 2 

# Control Cost Summary

Control Technology Installed

Capital Cost (MM$) Operating Cost

(MM$/yr) Annualized

Pollution Control Cost ($/ton) Incremental

Control Cost ($/ton) Secondary Wet Scrubber Furnace 11 Hood Exhaust $16,952,864 $2,401,349 $139,872 NA
Furnace 11 Waste Gas $15,859,420 $2,201,975 $384,034 NA
Furnace 12 Hood Exhaust $16,952,864 $2,401,349 $152,149 NA
Furnace 12 Waste Gas $15,859,420 $2,201,975 $417,742 NA Secondary Wet Walled Electrostatic Precipitator (WWESP) Furnace 11 Hood Exhaust $23,617,556 $4,188,875 $182,993 NA
Furnace 11 Waste Gas $21,846,389 $3,799,211 $496,949 NA
Furnace 12 Hood Exhaust $23,617,556 $4,294,171 $204,058 NA
Furnace 12 Waste Gas $21,846,389 $3,764,113 $535,575 NA



# 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 USEPA 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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 30 impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant 29



# . Therefore, all air pollution controls with annualized costs less than this screening threshold will be evaluated for visibility improvement, energy and other impacts.

The incremental control cost column in Table 5-3 is intended to present the incremental value of each technology as compared to the next most effective alternative. Since none of the secondary SO 2 

# control technologies are cost effective, the incremental cost is not applicable.

Energy and Environmental Impacts

Because the cost of SO 2 

# controls for the NMC furnaces is so high and does not meet a reasonable definition of cost effective technology, these technologies 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. The economic impacts of additional, secondary controls for SO 2 

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

# controls. Refer to Table 4-2 for a summary of the modeled 24-hour maximum emission rates and their computational basis for the existing
controls for SO 2 

# .
Visibility impacts with NO x 

# controls are presented in section 6. Table 6-1 provides a summary of the
SO 2 

# , NO x 

# , and PM 10 

# emissions for each modeling scenario.


# 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 in the furnaces: thermal, fuel and prompt NO x 

# .

• Fuel bound NO x 

# is formed as nitrogen compounds in the fuel is oxidized from fuel
combustion.

29 

# Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 31 • 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. In taconite furnaces, thermal NO x 

# production is a function of the residence time, free oxygen, and temperature, primarily in the flame area of the furnace.

• 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 furnaces.

The NMC furnaces are first and second generation straight-grate furnaces that were built with lower grade steel and less refractory lining than the newer generations. As a result, the furnaces cannot survive the higher temperature conditions (both flame temperature and roof air conditions) achieved in newer indurating furnaces. Consequently, the ambient air in the ignition and combustion zone is much cooler, leading to lower thermal NO x 

# generation.

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

# is formed, available and applicable control technologies were evaluated. See Appendix D for the current status of the availability and applicability of retrofit control technologies.

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options Step 1 identified the available and applicable technologies for NO x 

# emission reduction. Within Step 1, the technical feasibility of the control option was also discussed and determined. The following describes retrofit NO x 

# control technologies that were identified as available and applicable in the original submittal and discusses aspects of those technologies that determine whether or not the technology is technically feasible for indurating furnaces.

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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 32 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 waste gas in an induration furnace typically has near atmospheric oxygen vs. 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.

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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 33 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%. Low NO x 

# burners have been installed to the preheating section of a straight grate furnace at another taconite plant. 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. Low NO x 

# burners have not been applied to the indurating section of any straight grate taconite furnace.

However, NMC has a completely different combustion design compared to other furnaces. NMCs furnace design does not separate the preheat zone from the combustion zone and temperature control becomes a controlling variable for operation. Because the temperature in the indurating zone is critical to product quality, and because this is dependent on the preheat zone operation, it is not practical to control the furnace conditions in the preheat zone adequately to make low NOx burners a feasible option at NMC.

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 the Netherlands. 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 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 required to operate at high oxygen levels.. 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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 34 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. Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency project could be preheat incoming make-up air or pellet feed. 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, the facilities have already implemented energy efficiency projects. Each project carries its own fuel usage reductions and potentially 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 facilities 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 NMC. Therefore, the ported kilns are not an applicable technology for this facility.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 35 Alternate Fuels As described within the energy efficiency description, increased price of fuel has moved companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas.
Reduction of NO x 

# emissions through alternative fuel usage has been achieved at taconite grate kilns through the use of solid fuel. In these cases the reduction resulted due to changes from pulverized solid fuel dispersal in the kiln that results in lower flame temperature compared to other fuels. Switching from natural gas or oil to solid fuel has a potential drawback in that it can exchange one visibility impairment pollutant (NO x 

# ) for another (SO 2 

# ). More importantly, the design of the straight grate furnaces at NMC does not allow the use of solid fuels. Therefore, this option will not be further evaluated in this report.

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. 30



# However, similar to energy efficiency, facilities 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 31 

# . 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 NOx
emissions from boilers.

One taconite plant has installed NOx CEMS to monitor emissions but not to optimize NOx emissions through process fine tuning. That plant has experienced some reduction in NOx emissions but these encompass multiple variables and are not directly attributed to process fine tuning with the NOx CEMS. Therefore, this alternative has not been demonstrated in the taconite industry.

30 

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

31 

# MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis . Page 4.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 36 There are several concerns with utilizing process optimization as an available, applicable and technically feasible control option for the taconite industry:

• Taconite furnaces are designed and operated to convert magnetite to hematite in the presence of excess oxygen and require heat input to initiate the reaction which is exothermic and releases heat once initiated. Fuel combustion is only part of the process and therefore this process is different from a boiler.

• The quality of the process feed materials to the furnace is variable at some taconite operations and product quality may be compromised by attempting to fine tune heat input to
minimize NOx formation.

• 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.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 37 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:

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.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 38 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 alternates between vessels. Each of the vessels alternates between preheating/treating and heat

recovery.

The benefits of RSCR are:

• Its high energy efficiency allows it to be used after SO 2 

# and particulate controls.

• RSCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a thermal efficiency of 60% to 70%.

• Application of RSCR after SO 2 

# and PM controls significantly reduces the potential for problems associated with plugging and catalyst poisoning and deactivation.

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;

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 39 • 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 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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 40 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:

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 at HTC 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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 41 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 over 400,000 acfm. Therefore, the application of LTO would be more than an order of magnitude larger than the biggest current installation. 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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 42 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 SO3 which could result in the generation of sulfuric acid mist from the scrubber;

• Since LTO has not been installed at a taconite plant, it is likely that the application of LTO to an indurating furnace waste gas could present technical problems which were not encountered, or even considered, in the existing LTO applications;

• An LTO system at a taconite facility would also be a source of nitrate discharge to the tailings basin which would change the facility water chemistry which could cause operational problems and would likely cause additional problems with National Pollutant Discharge Elimination System (NPDES) discharge limits and requirements.

Application of this technology has not been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high moisture content. Using LTO at a taconite plant would require research, test runs, and extended trials to identify potential issues related to design for high airflows and impacts on plant systems, including the furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of 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.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 43 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.

Table 5-4 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and Technical Feasibility



# NO x 

# Pollution Control Technology Available? Applicable? Technically Feasible? External Flue Gas Recirculation (EFGR) Yes Yes No

Low- NO x 

# Burners Yes Yes No Induced Flue Gas Recirculation Burners Yes Yes No Energy Efficiency Projects Yes Yes No Ported Kilns Yes No No

Alternative Fuels Yes Yes No Process Optimization using 

# NO x 

# CEMS Yes No No
Non-Selective Catalytic Reduction (NSCR) Yes No No Selective Catalytic Reduction (SCR) with conventional reheat Yes Yes Yes

Regenerative SCR Yes No No Selective Non-Catalytic Reduction (SNCR) Yes No No Low Temperature Oxidation (LTO) Yes No No



# 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%

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 44 5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results Table 5-6 details the expected costs associated with installation of Low NO x 

# burners. Capital costs were calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates. Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate using the 6/10 power law to account for the economy of scale. Operating costs were based on 93% utilization and 8339 operating house per year. Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant concentrations.

After a tour of the facility and discussions with facility staff, it was determined the space surrounding the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to transport materials to and from the building. A site-specific estimate for site-work, foundations, and structural steel was added based upon the facility site 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 a site plan of the facility. Additionally, the structural design of the existing building would not support additional equipment on the roof. The detailed cost analysis is provided in Appendix A.

Table 5-6 Indurating Furnace NO x 

# Control Cost Summary

Control Technology Installed Capital Cost (MM$) Total Annual Cost (MM$/yr) Annualized

Pollution Control Cost ($/ton) Incremental

Control Cost ($/ton) Selective Catalytic Reduction (SCR) With Reheat Furnace 11 Hood Exhaust $25,735,488 $11,314,358 $155,784 NA

Furnace 11 Waste Gas $23,344,084 $8,274,322 $46,771 NA

Furnace 12 Hood Exhaust $25,912,320 $11,387,084 $162,309 NA

Furnace 12 Waste Gas $24,026,527 $10,442,659 $61,107 NA



# Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective air pollution controls in the electric utility industry for large power plants are in the range $1,000 to $1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect measure of affordability for the electric utility industry used by USEPA to support the BART rule-

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 45 making process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 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.

The incremental control cost column in Table 5-6 is intended to present the incremental value of each technology as compared to the technology with the next most effective alternative. Since none of the
NO x 

# reduction technologies are cost effective, the incremental cost is not applicable.

Energy and Environmental Impacts

Because the cost of NO x 

# controls for NMC furnaces is so high and does not meet a reasonable definition of cost effective technology, this technology is removed from further consideration in this analysis.

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. The economic impacts of controls for NO x 

# are not reasonably cost effective, so visibility impacts were not modeled for NO x 

# controls. Refer to Table 4-2 for a summary of the modeled 24- hour maximum emission rates and their computational basis for the existing controls for NO x 

# .

32 

# Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 46 Visibility impacts with SO 2 

# controls are presented in section 6. Table 6-1 provides a summary of the
SO 2 

# , NO x 

# , and PM 10 

# emissions for each modeling scenario,

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 47 

# 5.B External Combustion Sources Two natural gas and fuel oil fired process boilers require BART analysis. These boilers are back-up boilers to the main NMC Power House boilers to provide steam required to operate the taconite plant during Power House outages. These boilers are only permitted to use gas and distillate oil for fuel.



# 5.B.i Sulfur Dioxide controls
Sulfur in the fuel is the only source of SO 2 

# emissions from these boilers. The boilers only have low
emissions of SO 2 

# due to the low sulfur content of the permitted fuels.

5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies See Appendix F for a comprehensive list of all potential retrofit control technologies that were
evaluated.

5.B.i.b STEP 2 – Eliminate Technically Infeasible Options Step 1 identified the available and applicable technologies for SO 2 

# emission reduction. Within Step 2, the technical feasibility of the control option is discussed and determined. The following
section describes retrofit SO 2 

# control technologies that were identified as available and applicable and discusses aspects of those technologies that determine whether or not the technology is technically feasible for the process boilers.

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 and fuel used. Based on the definitions contained within this report, a WWESP is considered an available technology for SO 2 

# reduction for this BART analysis.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 48 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 is used as scrubbing agents.

Limestone scrubbing introduces limestone slurry with the flue gas in a spray tower. The sulfur dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in the following equations:

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 a more reactive 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 that 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 minimal equipment is needed 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 is 80% to 90% for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control
efficiencies can be achieved when SO 2 

# concentrations are the highest. The process boiler exhaust would not have a high SO 2 

# concentration, so the low end of the efficiency range would be expected.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 49 Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) Dry sorbent injection involves the injection of a lime or limestone powder into the exhaust gas stream. The stream is then passed through a baghouse or ESP to remove the sorbent and entrained
SO 2 

# . The process was developed as a lower cost FGD option because the mixing occurs directly in the exhaust gas stream instead of in a separate tower. Depending on the residence time and gas stream temperature, sorbent injection control efficiency is approximately 55%. Therefore DSI is technically feasible.

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. The normal SO2 control efficiency range for SDA is up to 90%.

Based on the information contained with this report, SDA is considered an available technology for
SO 2 

# reduction for this BART analysis.

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 pollution emissions. Due to the increased price of fuel, the facilities have already implemented energy efficiency projects. Each project carries its own fuel usage reductions and potentially 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 facilities will continue to evaluate and implement energy efficiency projects as they arise.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 50 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 use fuels with lower sulfur content. NMC has the capability to only burn low sulfur fuels, natural gas and distillate oil, in these process boilers. Therefore this option is not applicable to the process boilers.

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. 33



# Therefore, due to the limited fuel burning capabilities of the boilers and the fact that BART is not intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not be further evaluated in this report.

However, similar to energy efficiency, facilities will continue to evaluate and implement alternate fuel usage as the feasibility arises.

Coal Processing Since NMC process boilers are not capable of burning solid fuel, this option is not applicable for SO 2 

# reductions at NMC.

STEP 2 Conclusion Based upon the determination within Step 2, the remaining SO 2 

# control technologies that are available and applicable to the process boilers are identified in Table 5-7. The technical feasibility as determined in Step 2 is also included in Table 5-7.

33 

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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 51 Table 5-7 Backup Process Boiler SO 2 

# Control Technology – Availability, Applicability, and Technical Feasibility

SO 2 

# Pollution Control Technology Available? Applicable? Technically Feasible? WWESP Yes Yes Yes Wet Scrubber Yes Yes Yes Spray Dry Absorption (SDA) Yes Yes Yes Dry Sorbent Injection (DSI) Yes Yes Yes Energy Efficiency Projects Yes Yes No Alternative Fuels Yes Yes No



# 5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies Table 5-8 describes the expected control efficiency from each of the remaining feasible control options when burning liquid fuels.

Table 5-8 Backup Process Boiler SO 2 

# Control Technology Effectiveness

SO 2 

# Pollution Control Technology Approximate Control Efficiency Wet Walled Electrostatic Precipitator (WWESP) 80% Wet Scrubbing (High Efficiency) 80% Dry Sorbent Injection 55% Spray Dryer Absorption 90%



# 5.B.i.d STEP 4 – Evaluate Impacts and Document the Results As illustrated in Table 5-8 above, the technically feasible control 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 5-9 details the expected costs associated with installation of a WWESP, wet scrubber, DSI and SDA 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 a recent vendor quotation. The

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 52 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 7650 operating hours per year, which is very conservative, considering these are backup boilers. Operating costs of consumable materials, such as electricity, water, and chemicals were established based on the U.S.
EPA control cost manual 34 

# and engineering experience, and were adjusted for the specific flow rates and pollutant concentrations.

See Appendix C for an aerial photo of the facility. The detailed cost analysis is provided in Appendix
A.

Table 5-9 Backup Process Boiler SO2 Control Cost Summary

Control Technology Installed Capital Cost ($) Total

Annual Cost ($/yr) Annualized

Pollution Control Cost ($/ton) Incremental

Control Cost ($/ton) Wet ESP $11,808,857 $2,247,725 $36,558 NA
Wet Scrubber $13,618,522 $1,869,933 $31,845 NA Dry Sorbent Injection and Baghouse $4,890,063 $1,409,010 $22,917 NA Spray Dryer and Baghouse $16,134,577 $2,751,525 $44,752 NA



# 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 USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 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

34 

# U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition

.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 53 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 35



# . Therefore, all air pollution controls with annualized costs less than this screening threshold will be evaluated for visibility improvement, energy and other impacts.

The incremental control cost column in Table 5-9 is intended to present the incremental value of each technology as compared to the next most effective alternative. Since none of the technologies are cost effective, the incremental control cost is not applicable.

Energy and Environmental Impacts

Because the cost of SO 2 

# controls for the NMC process boilers is so high and does not meet a reasonable definition of cost effective technology, these technologies are removed from further consideration in this analysis.

5.B.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. The economic impacts of controls for SO 2 

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

# controls. Refer to Table 4-2 for a summary of the modeled 24- hour maximum emission rates and their computational basis for the existing controls for SO 2 

# .
Visibility impacts with NO x 

# controls are presented in Section 6. Table 6-1 provides a summary of
the SO 2 

# , NO x 

# , and PM 10 

# emissions for each modeling scenario.

35 

# Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 54 

# 5.B.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 as nitrogen compounds in the fuel is 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.

5.B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies With the understanding of how NO x 

# is formed, available and applicable control technologies were evaluated. See Appendix F for the current status of the availability and applicability of retrofit control technologies.

5.B.ii.b STEP 2 – Eliminate Technically Infeasible Options Step 1 identified the available and applicable technologies for NO x 

# emission reduction. Within Step 2, the technical feasibility of the control option was discussed and determined. The following
describes retrofit NO x 

# control technologies that were identified as available and applicable and discusses aspects of those technologies that determine whether or not the technology is technically feasible for the process boilers.

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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 55 this technology to be effective, the combustion conditions must have the ability to be controlled at the burner tip. Process boilers 1 and 2 do not have the capability of control at the burner tip. Therefore, this option is not technically feasible and will not be further evaluated in this report.

Low NOx Burners (LNB)

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 a staged combustion process that is designed to split fuel combustion into two zones. In the primary zone, NOx formation is limited by either one of two methods. Under staged air rich (high fuel) condition, low oxygen levels limit flame temperatures resulting in less NOx formation. The primary zone is then followed by a secondary zone in which the incomplete combustion products formed in the primary zone act as reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, excess air will reduce flame temperature to reduce NO x 

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

# formation. Low NO x 

# burners typically achieve NO x 

# emission reductions of 25% - 50% for process boilers.

Overfire Air (OFA)

Overfire air diverts a portion of the total combustion air from the burners and injects it through separate air ports above the top level of burners. OFA is a NO x 

# control technology typically used in boilers and is primarily geared to reduce thermal NO x 

# . Staging of the combustion air creates an initial fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the production of
thermal NO x 

# by lowering combustion temperature and limiting the availability of oxygen in the combustion zone where NOx is most likely to be formed. OFA is considered compatible with the LNB and is a technically feasible option for further NO x 

# reduction. However, due to the small size and number of burners, OFA is not desirable alternative for NMC process boilers and will not be considered for further BART analysis.

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 50-75%.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 56 Energy Efficiency Projects Energy efficiency projects provide opportunities for a company to reduce their fuel consumption. Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency project could be preheat incoming make-up air or pellet feed. 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, the facilities have already implemented energy efficiency projects. Each project carries its own fuel usage reductions and potentially 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 facilities 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 NO x 

# emissions through alternative fuel usage, the source must be currently burning a high NOx emitting fuel relative to other fuels. The boilers are only capable of burning natural gas and distillate oil. Therefore the use of alternate fuels is not a viable option for the process boilers and will not be considered further in this analysis.

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. 36



# Therefore, due to the limited boiler fuel capabilities and the fact that BART is not intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not be further evaluated in this report

However, similar to energy efficiency, facilities will continue to evaluate and implement alternate fuel usage as the feasibility arises.

36 

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

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 57 Post Combustion Controls

NO x 

# can be controlled using add-on systems located downstream 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:

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 liquid fuels. 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:

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 58 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 alternates between vessels. Each of the vessels alternates between preheating/treating and heat

recovery.

The benefits of RSCR are:

• Its high energy efficiency allows it to be used after SO 2 

# and particulate controls.

• RSCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a thermal efficiency of 60% to 70%.

• Application of RSCR after SO 2 

# and PM controls significantly reduces the potential for problems associated with plugging and catalyst poisoning and deactivation.

To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not been applied to liquid and natural gas fired boilers. Using RSCR would require research, test runs,

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 59 and extended trials to identify potential issues related to catalyst selection, and impacts on plant 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 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.

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

# , and water. SNCR control efficiency is typically 25% - 60%. Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The
relevant reactions are as follows:



# NO + NH 3 

# + 1⁄4O 2 

# → N 2 

# + 3/2 

# H 2 

# O (1)

NH 3 

# + 1⁄4O 2 

# → NO + 3/2H 2 

# O (2)

At temperature ranges of 1470 to 1830 ° F reaction (1) dominates. At temperatures above 2000 ° F, reaction (2) will dominate. This control option is considered 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®.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 60 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:

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 

# ).

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.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 61 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. Consequently, the technical feasibility of LTO as 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 process boilers are identified in Table 5-10. The technical feasibility as determined in Step 2 is also included in Table 5-10.

Table 5-10 Backup Process Boiler NO x 

# Control Technology – Availability, Applicability and Technical Feasibility

NOx Pollution Control Technology Available? Applicable? Technically Feasible? External Flue Gas Recirculation (EFGR) Yes Yes No Low-NOx Burners Yes Yes Yes Overfired Air Yes Yes No Induced Flue Gas Recirculation (IFGR) Yes Yes Yes Energy Efficiency Projects Yes Yes No Alternative Fuels Yes Yes Not required Non-Selective Catalytic Reduction (NSCR) Yes Yes No Selective Catalytic Reduction (SCR) Yes Yes Yes Regenerative SCR Yes Yes No Selective Non-Catalytic Reduction (SNCR) Yes Yes Yes Low Temperature Oxidation (LTO) Yes No No



# 5.B.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies Table 5-11 describes the expected control efficiency from each of the remaining technically feasible control options as identified in Step 2.

Table 5-11 Backup Process Boiler NOx Control Technology Effectiveness

NOx Pollution Control Technology Approximate Control Efficiency Low-NOx Burners 50%
Low-NOx Burners with IFGR 75%
SCR 90% Selective Non-Catalytic Reduction (SNCR) 50%

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 62 5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results Table 5-12 details the expected costs associated with installation of NO x 

# controls. Capital costs were calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates. Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate using the 6/10 power law to account for the economy of scale. Operating costs were based on 93% utilization and 7650 operating hours per year, which is extremely conservative, since they are backup boilers. Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant
concentrations.

After a tour of the facility and discussions with facility management, it was determined the space surrounding the boilers is congested and the area surrounding the building supports vehicle and rail traffic to transport materials to and from the building. A site-specific estimate for site-work, foundations, and structural steel was added based upon the facility site to arrive at the total retrofit installed cost of the control technology. See Appendix C for a site plan of the facility. Additionally, the structural design of the existing building would not support additional equipment on the roof. The detailed cost analysis is provided in Appendix A.

Table 5-12 Backup Process Boiler NO x 

# Control Cost Summary

Control Technology Installed

Capital Cost ($) Operating Cost

($/yr) Annualized

Pollution Control Cost ($/ton) Incremental

Control Cost ($/ton) Low NOx Burner $90,775 $14,915 $723 NA Low NOx Burner / IFGR $518,713 $330,367 $10,675 $30,626 Selective Catalytic Reduction (SCR) $5,563,529 $1,120,061 $30,160 NA
Selective NonCatalytic Reduction (SNCR) $925,876 $250,181 $12,126 NA



# 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 USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 63 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 37



# . Therefore, all air pollution controls with annualized costs less than this screening threshold will be evaluated for visibility improvement, energy and other impacts.

The incremental control cost listed in Table 5-12 represents the incremental value of each technology as compared to the technology with the next highest level of control.

Energy and Environmental Impacts The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-13. Because the cost of the remaining NO x 

# control technologies for the NMC process boilers is so high and does not meet a reasonable definition of cost effective technology, these technologies are removed from further consideration in this analysis.

Table 5-13 Backup Process Boiler NO x 

# Control Technology – Other Impacts Assessment



# Control Option Energy Impacts Other Impacts
LNB - Minimal energy impacts - Increase in CO emissions

- Potential for steam tube wastage due to longer combustion flame IFGR/LNB - Minimal energy impacts. - Increase in CO emissions

- Potential for steam tube wastage due to longer combustion flame.

37 

# Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 64 5.B.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.

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. In the visibility impacts NO X 

# modeling analysis, the emissions from the sources undergoing a full BART NO X 

# analysis were adjusted to reflect the projected 24-hour maximum NO X 

# emission rate when applying the control technologies that met the threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were not changed. Table 5-14 provides a summary of the modeled 24-hour maximum emission rates and their computational basis for the evaluated NO X 

# control technologies. Table 5-15 provides a summary of the SO 2 

# , NO X 

# , and PM 10 

# emissions for each modeling scenario, and Table 5-16 provides a summary of the modeling input data.

Table 5-14 Backup Process Boiler NO x 

# Post- BART Emission Rates for Emission Unit EU003 and EU004

Control Scenario 

## SV # Emission Unit Description NO x 

## Control Technology % NO x



## Reduction NO x



## Annual Emission Rate (tons/year) NO x



## 24-hour Maximum Emission Rate (lb/day)


# 1 SV003 Process Boiler 1 Low Nox Burners 50% 25.5 279

1 SV003 Process Boiler 2 Low Nox Burners 50% 25.5 279Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc65Table 5-15 Backup Process Boiler Post-BART Modeling ScenariosScenarioControl Scenario TechnologyModeling Emission Rate InputSO2NOxPM2.5/PM10SO2NOxPM%Reduced24-hr Maxlb/hr%Reduced24-hr Maxlb/hr%ReducedPM2.5 24-hr Max.lb/hr%ReducedPM2.5-1024-hr Max.lb/hr0Base Base BaseSV003ProcessBoilers1 & 20 33.5 0 23.3 0 0 1.91BaseLNBwithIFGRBaseSV003ProcessBoilers1 & 20.0% 33.5 50.0% 11.6 0 0 1.9

## Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-

2006.doc 

# 66 Table 5-16 Backup process Boiler Post-BART NO x 

# Modeling Scenarios - Modeling Input Data

Control Scenario SV # Emission Unit Stack Easting LCC (km) Stack Northing

LCC (km) Height of

Opening from Ground (m) Base

Elevation of Ground (m) Stack

Diameter (m) Flow Rate

at exit (acfm) Exit

Temp ( o 

### F)


# 1 SV003 Process

Boilers 1 & 2 631471.5 5238482.8 131 611 6.5 59900 450



# Post-BART Visibility Impacts Modeling Results Results of the post-BART visibility impacts modeling for NO X 

# for the process boilers are presented in Table 5-17. The results summarize 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. The comparison of the post-BART modeling scenarios to the baseline conditions is presented in Table 5-18.

Visibility impacts with SO 2 

# controls are presented in section 6.

Table 5-17 Backup Process Boiler Post-BART NO x 

# Modeling Scenarios - Visibility Modeling Results

2002 2003 2004 2002 – 2004 Combined

Scenario # Class I

Area with Greatest Impact Modeled

98 th 

### Percentile Value (deciview) No. of

days exceeding 0.5 deciview Modeled 98 th



### Percentile Value (deciview) No. of days

exceeding 0.5 deciview Modeled 98 th



### Percentile Value (deciview) No. of days

exceeding 0.5 deciview Modeled 98 th



### Percentile Value (deciview) No. of days

exceeding 0.5 deciview 

# 0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106 1 BWCA 1.1 33 1.1 34 1.3 38 1.1 105

Table 5-18 Backup Process Boiler Post-BART NO x 

# Modeling Scenarios – Comparison of Visibility Modeling Results to Baseline Modeling Results

2002 2003 2004 2002 – 2004 Combined

Scenario # Class I

Area with Greatest Impact Improved

Modeled 98 th 

### Percentile Value ( ∆ -dV ) Decreased

No. of days exceeding 0.5 deciview Improved

Modeled 98 th 

### Percentile Value ( ∆ -dV ) Decreased

No. of days exceeding 0.5 deciview Improved

Modeled 98 th 

### Percentile Value ( ∆ -dV ) Decreased

No. of days exceeding 0.5 deciview Improved

Modeled 98 th 

### Percentile Value ( ∆ -dV ) Decreased

No. of days exceeding 0.5 deciview 

# 0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106 1 BWCA 0.0 1 0.0 0 0.0 0 0.0 1

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 67 

# 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 section 5 of this document. This section of the report evaluates the various BART control scenarios utilizing both
SO 2 

# and NO x 

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

# 6.A Post-BART Modeling Scenarios Steps 1-4 of the BART analysis identified the control technologies that were:

• Available and applicable;

• Technically feasible; and

• Below the screening cost threshold for further BART analysis.

Step 5 of the BART analysis evaluated the visibility impacts of each of the control technologies that met the requirements of the screening analysis of steps 1-4.

However, because there are limited control options available that meet the above criteria, there are limited available control combinations, or control scenarios, that must be considered. Additionally, the interactions between the visibility impairing pollutants NO x 

# , SO 2 

# 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. Accordingly, this visibility improvement analysis evaluates several operating
control scenarios that account for the various combinations of available SO 2 

# and NO x 

# controls. In addition, two site-specific scenarios were developed so that the evaluation includes other operating scenarios and conditions that would improve visibility impairment. The post-BART modeling scenarios, including those presented in Step 5 of section 5, are presented in Table 6-1.


# 6.B Post-BART Modeling Results Results of the post-BART modeling scenarios are presented in Table 6-2. The results summarize 98th percentile dV value and the number of days the facility contributes more than a 0.5 dV of

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 68 visibility impairment at each of the Class I areas. The comparison of the post-BART modeling scenarios to the baseline conditions is presented in Table 6-3.

While the cost per ton of low NO x 

# burners is $723, and is below the threshold of $1,000 to $1,300 per ton, they result in essentially no visibility improvement to the Class I areas. In the three years, additional controls would result in only one fewer day with a visibility impact of greater than 0.5 dV and the change in the modeled worst day (98 th 

# percentile) is 0.007 deciviews, which is less than 1% of the total modeled BART impact. The cost of this marginal improvement is $4.3 million per deciview, considering the capital cost of $91,000 and the total annual cost of $15,000.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc69Table 6-1 Post-BART Modeling ScenariosScenario Control TechnologySO2NOxParticulate MatterControlScenarioSV #Emission UnitSO2NOx%ReductionMax24-hour lbs/hr% ReductionMax24-hourlbs/hrPM10Max 24-hrlbs/hrPM2.5Max 24-hrlbs/hrPMcoarseMax 24-hrlbs/hr0Base(existingdesign)Base(existingdesign)SV101Furnace 11 Hood Exh--- 11.8--- 17.1 11.3SV102Furnace 11 Hood Exh11.817.1 11.3SV103Furnace 11 Hood Exh11.817.1 11.3SV104Furnace 11 Waste Gas--- 5.9--- 62.4 10.6SV105Furnace 11 Waste Gas5.962.4 10.6SV111Furnace 12 Hood Exh--- 11.8--- 17.1 11.3SV112Furnace 12 Hood Exh11.817.1 11.3SV113Furnace 12 Hood Exh11.817.1 11.3SV114Furnace 12 Waste Gas--- 5.9--- 62.4 10.6SV115Furnace 12 Waste Gas5.962.4 1.6SV003Process Boilers 1 & 233.523.3 1.91BaseBase oninduratingfurnace andLow NOxBurners onthe backupprocessboilersSV101Furnace 11 Hood Exh11.8--- 17.1 11.3SV102Furnace 11 Hood Exh11.817.1 11.3SV103Furnace 11 Hood Exh11.817.1 11.3SV104Furnace 11 Waste Gas5.9--- 62.4 10.6SV105Furnace 11 Waste Gas5.962.4 10.6SV111Furnace 12 Hood Exh11.8--- 17.1 11.3SV112Furnace 12 Hood Exh11.817.1 11.3SV113Furnace 12 Hood Exh11.817.1 11.3SV114Furnace 12 Waste Gas5.9--- 62.4 10.6SV115Furnace 12 Waste Gas5.962.4 1.6SV003Process Boilers 1 & 233.5 50.0% 11.6 1.9Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc70Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004CombinedScenario #Class I AreawithGreatestImpactModeled98thPercentileValue(deciview)No. of daysexceeding0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview0 BWCA 1.1 34 1.1 34 1.3 38 1.1 1061 BWCA 1.1 33 1.1 34 1.3 38 1.1 105Table 6-3 Post-BART Modeling Scenarios – Comparison of Visibility Modeling Results to Baseline Modeling ResultsModeling Results02002200320042002-2004ScenarioLimiting Class I AreaImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding 0.5dVImprovedModeled 98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled 98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dV0 BWCA 1.1 34 1.1 34 1.3 38 1.1 1061 BWCA 0.0 1 0.0 0 0.0 0 0.0 1

## Y:\23\00 MN Taconite BART (2006)\Facility BART Repor ts\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc 

# 71 

# 7. Select BART

BART for NMC is proposed to be as follows:

Indurating Furnaces
For SO 2 

# , polishing add-on controls are not cost effective. Therefore, BART is proposed to be existing controls. The corresponding SO 2 

# emissions limit would be 2.0 lbs/mmBtu, which equates to 300 lb/hr per furnace based upon each furnace heat input rating of 150 mmBtu.

For NO x 

# , add on control are not cost effective. Therefore, BART is proposed to be the existing furnace design and permitted fuels. The corresponding NO x 

# limit would be 176 lb/hr for each
furnace.

For PM, requirements compelled by the upcoming MACT standard constitute BART. The corresponding emissions limit would be 0.01 grains per dscf for the furnaces.

Process Boilers The process boilers are backup boilers for steam production normally supplied to the taconite plant from the power boilers. For SO 2 

# , add-on controls are not cost effective. Therefore, BART is proposed to be existing design and permitted fuels. The corresponding SO 2 

# emissions limit would be
0.6 lb/mmBtu for each boiler.

For NO x 

# , add-on controls would not accomplish a meaningful improvement in visibility. Therefore, BART is proposed to be existing design and permitted fuels. The corresponding NO x 

# limit would be
0.17 lb/mmBtu for each boiler.

Other Taconite Sources

For PM, requirements compelled by the upcoming MACT standard constitute BART. The corresponding emissions limit would be equivalent to the MACT limit.

The schedule for implementation of these limits is within the 5-year time-frame required for BART implementation.Cleveland Cliffs Incorporated: Northshore MiningBART Report - Appendix A Emission Control Cost AnalysisTable 1: Cost SummaryNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $Total Annual Cost$/yrPollution ControlCost $/tonFurnace 11 Hood Exhaust80%5.7 106.7$46,019,283 $11,628,024 $108,969Furnace 11 Waste Gas80%17.8255.9$43,197,692 $8,239,261$32,199Furnace 12 Hood Exhaust80%5.6104.4$46,284,809 $11,688,411 $112,008Furnace 12 Waste Gas80%17.4250.3$43,455,895 $10,383,373$41,488SO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $Total Annual Cost$/yrPollution ControlCost $/tonWet Walled Electrostatic Precipitator (WWESP)Furnace 11 Hood Exhaust80% 5.722.9$23,617,556$4,188,875$182,993Furnace 11 Waste Gas80% 1.97.6$21,846,389$3,799,211$496,949Furnace 12 Hood Exhaust80% 5.321.0$23,617,556$4,294,171$204,058Furnace 12 Waste Gas80% 1.87.0$21,846,389$3,764,113$535,575Wet ScrubberFurnace 11 Hood Exhaust60% 11.417.2$16,952,864$2,401,349$139,872Furnace 11 Waste Gas60% 3.85.7$15,859,420$2,201,975$384,034Furnace 12 Hood Exhaust60% 10.515.8$16,952,864$2,401,349$152,149Furnace 12 Waste Gas60% 3.55.3$15,859,420$2,201,975$417,742Selective Catalytic Reduction with ReheatY:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsCost Summary9/6/2006 Page 1 of 56Cleveland Cliffs Incorporated: Northshore MiningBART Report - Appendix A Emission Control Cost AnalysisTable 2: - Summary of Utility, Chemical and Supply CostsOperating Unit:Furnace 11 Hood ExhaustStudy Year2006Emission Unit NumberEU 100Stack/Vent NumberSV 101, 102, & 103Operating Unit:Furnace 11 Waste GasEmission Unit NumberEU 104Stack/Vent NumberSV 104 & 105Operating Unit:Furnace 12 Hood ExhaustEmission Unit NumberEU 110Stack/Vent NumberSV 111, 112, & 113Operating Unit:Furnace 12 Waste GasEmission Unit NumberEU 114Stack/Vent NumberSV 114 & 115ReferenceItem Unit Cost UnitsCost Year Data SourceNotesOperating Labor50 $/hr2006Site Specific - Northshore Mining .Maintenance Labor60 $/hr2006Site Specific - Northshore Mining .Construction Labor Rate.Electricity0.060 $/kwh2006Site Specific - Northshore Mining.Purchased.Natural Gas10.0204 $/mscf2006Site Specific - Northshore Mining .$9.40/MMBtu @ 1066 Btu/scf.Water0.28 $/mgal0.20 1995EPA Air Pollution Control Cost Manual, 6thEd 2002, Section 5 Ch 1, page 1-40.Annual 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 1.Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and3% inflation.Compressed Air0.32 $/mscf0.25 1998EPA Air Pollution Control Cost Manual 6th Ed2002, Section 6 Chapter 1 .Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%inflation.Wastewater Disposal Neutralization1.69 $/mgal1.50 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 2 Chapter 2.5.5.5.Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch3 lists $1.30 - $2.15/1,000 gal.Chemicals & SuppliesLime88.98 $/ton88.98 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 2-50.Annual costs for a retrofit SCR system example problem. '00 costsadjusted for 3% inflation.Caustic305.96 $/ton280 2003 Hawkins Chemical50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflationOtherSales Tax6.5% %Interest Rate7.00% %EPA Air Pollution Control Cost ManualIntroduction, Chapter 2, section 2.4.2.Social (discount) rate used as a default.Operating InformationAnnual Op. Hrs8339.1 Hours2006Site Specific - Northshore Mining .Maximum hours of operation 2004-2005 with a 10% safety factor.Utilization Rate93%Equipment Life20 yrsEngineering Estimate.Standardized Flow RateSV 101, 102, & 103181,762 scfm @ 32o FCalculated.SV 104 & 105152,520 scfm @ 32o FCalculated.SV 111, 112, & 113181,762 scfm @ 32o FCalculated.SV 114 & 115152,520 scfm @ 32o FCalculated.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsUtility Chem$ Data9/6/2006 Page 2 of 56ReferenceItem Unit Cost UnitsCost Year Data SourceNotesTemperatureSV 101, 102, & 103142 Deg FBART spreadsheet.SV 104 & 105140 Deg FBART spreadsheet.SV 111, 112, & 113142 Deg FBART spreadsheet.SV 114 & 115140 Deg FBART spreadsheet.Moisture ContentSV 101, 102, & 10311.3%2006Y:\23\38\126 NSM 2006 Stack Testing\WK4Fce 11+\Data.Average from test results in:Test 1-3 Fce 11 HE 1101-1103 - 6-13-06.SV 104 & 10518.3%2006Y:\23\38\126 NSM 2006 Stack Testing\WK4Fce 11+\Data.Average from test results in: Test 4-5 Fce 11 WG 1104-1105 - 6-14-06.SV 111, 112, & 1139.5%2006Y:\23\38\126 NSM 2006 Stack Testing\WK2Fce 12\Data.Average from test results in: Fce 12 HE 1201-1203 4-18-06.SV 114 & 11516.4%2006Y:\23\38\126 NSM 2006 Stack Testing\WK2Fce 12\Data.Average from test results in: Fce 12 WG 1204-1205 4-19-06.Actual Flow RateSV 101, 102, & 103222,400 acfmBART spreadsheet.SV 104 & 105186,000 acfmBART spreadsheet.SV 111, 112, & 113222,400 acfmBART spreadsheet.SV 114 & 115186,000 acfmBART spreadsheet.Standardized Flow RateSV 101, 102, & 103195,062 scfm @ 68o FCalculated.SV 104 & 105163,680 scfm @ 68o FCalculated.SV 111, 112, & 113195,062 scfm @ 68o FCalculated.SV 114 & 115163,680 scfm @ 68o FCalculated.Dry Std Flow RateSV 101, 102, & 103172,951 dscfm @ 68o FCalculated.SV 104 & 105133,792 dscfm @ 68o FCalculated.SV 111, 112, & 113176,529 dscfm @ 68o FCalculated.SV 114 & 115136,902 dscfm @ 68o FCalculated.Max Emis Actual Emissionslb/hr ton/yearPollutantLb/Hr Ton/year ('04&'05 Max) ppmv ppmvNitrous Oxides (NOx)SV 101, 102, & 10351.3112.4 4120.72005 plus 10%SV 104 & 105124.8273.7 13065.12004 plus 10%SV 111, 112, & 11351.3109.9 4019.82004 plus 10%SV 114 & 115124.8267.7 12762.32004 plus 10%Sulfur Dioxides (SO2)SV 101, 102, & 10335.528.6 213.82004 plus 10%SV 104 & 10511.89.6 91.62004 plus 10%SV 111, 112, & 11335.526.3 203.42004 plus 10%SV 114 & 11511.88.8 91.52004 plus 10%guesscalculated valueknown or assumed datarequired dataY:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsUtility Chem$ Data9/6/2006 Page 3 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 3: SO x 

## Control - Wet Scrubber

Operating Unit: Furnace 11 Hood Exhaust

Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103 Standardized Flow Rate 181,762 scfm @ 32o F Expected Utilization Rate 93% Temperature 142 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3% Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F Dry Std Flow Rate 172,951 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 2,765,654 Purchased Equipment Total (B) 22% of control device cost (A) 3,360,270

Installation - Standard Costs 85% of purchased equip cost (B) 2,856,229 Installation - Site Specific Costs 6,200,000 Installation Total 2,856,229 Total Direct Capital Cost, DC 6,216,499 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040 Total Capital Investment (TCI) = DC + IC 16,952,864
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 476,790 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349

Actual 

### Emission Control Cost Calculation Emis Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 51.3 112.4 0% 112.4 - NA Sulfur Dioxide (SO 2 ) 35.5 28.6

60% 11.4 17.2 139,872

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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU100 Wet Scrubber 9/6/2006 Page 4 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 3: SOx Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,765,654 Instrumentation 10% of control device cost (A) 276,565 MN Sales Taxes 7% of control device cost (A) 179,768 Freight 5% of control device cost (A) 138,283 Purchased Equipment Total (B) 22% 3,360,270

Installation Foundations & supports 12% of purchased equip cost (B) 403,232 Handling & erection 40% of purchased equip cost (B) 1,344,108 Electrical 1% of purchased equip cost (B) 33,603 Piping 30% of purchased equip cost (B) 1,008,081 Insulation 1% of purchased equip cost (B) 33,603 Painting 1% of purchased equip cost (B) 33,603 Installation Subtotal Standard Expenses 85% 2,856,229
Total Direct Capital Cost, DC 6,216,499
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 168,013 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 168,013 Start-up 1% of purchased equip cost (B) 33,603 Performance test 1% of purchased equip cost (B) 33,603 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 100,808 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040
Total Capital Investment (TCI) = DC + IC 6,720,540 Retrofit multiplier 5 60% of TCI 4,032,324

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 16,952,864



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060 Supervisor 15% 15% of Operator Costs 3,909 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272 Maintenance Materials 100% of maintenance labor costs 31,272 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization 212,823 Water 0.28 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization 26,883 WW Treat Neutralization 1.69 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization 132,783 Lime 88.98 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization 11,789 Total Annual Direct Operating Costs 476,790
Indirect Operating Costs Overhead 60% of total labor and material costs 55,507 Administration (2% total capital costs) 2% of total capital costs (TCI) 134,411 Property tax (1% total capital costs) 1% of total capital costs (TCI) 67,205 Insurance (1% total capital costs) 1% of total capital costs (TCI) 67,205 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,600,230 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU100 Wet Scrubber 9/6/2006 Page 5 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 3: SOx 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 222,400 8.55 0.7

- 317.8 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 8,451 gpm 1 60 0.7

- 136.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 209 gpm 1 60 0.7

- 3.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 457.4

Reagent Use & Other Operating Costs Caustic Use 35.50 lb/hr SO2 2.50 lb NaOH/lb SO2 88.75 lb/hr Caustic Lime Use 35.50 lb/hr SO2 0.96 lb Lime/lb SO2 34.17 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 8,451 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 209 gpm Evaporation Loss 4 = 39.66 gpm

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Supervisor 15% of Op. NA 3,909 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 457.4 kW-hr 3,547,050 212,823 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization Water 0.28 $/kgal 208.7 gpm 97,104 26,883 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 1.69 $/kgal 169.0 gpm 78,651 132,783 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization Lime 89.0 $/ton 34.2 lb/hr 132 11,789 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU100 Wet Scrubber 9/6/2006 Page 6 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 4: SO x 

## Control - Wet Scrubber

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Standardized Flow Rate 152,520 scfm @ 32o F Expected Utilization Rate 93% Temperature 140 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 2,484,419 Purchased Equipment Total (B) 22% of control device cost (A) 3,018,569

Installation - Standard Costs 85% of purchased equip cost (B) 2,565,783 Installation - Site Specific Costs 6,200,000 Installation Total 2,565,783 Total Direct Capital Cost, DC 5,584,352 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785 Total Capital Investment (TCI) = DC + IC 15,859,420
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 407,966 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975

Actual 

### Emission Control Cost Calculation Emis Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 124.8 273.7 0% 273.7 - NA Sulfur Dioxide (SO 2 ) 11.8 9.6

60% 3.8 5.7 384,034

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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU104 Wet Scrubber 9/6/2006 Page 7 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 4: SOx Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,484,419 Instrumentation 10% of control device cost (A) 248,442 MN Sales Taxes 7% of control device cost (A) 161,487 Freight 5% of control device cost (A) 124,221 Purchased Equipment Total (B) 22% 3,018,569

Installation Foundations & supports 12% of purchased equip cost (B) 362,228 Handling & erection 40% of purchased equip cost (B) 1,207,427 Electrical 1% of purchased equip cost (B) 30,186 Piping 30% of purchased equip cost (B) 905,571 Insulation 1% of purchased equip cost (B) 30,186 Painting 1% of purchased equip cost (B) 30,186 Installation Subtotal Standard Expenses 85% 2,565,783
Total Direct Capital Cost, DC 5,584,352
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 150,928 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 150,928 Start-up 1% of purchased equip cost (B) 30,186 Performance test 1% of purchased equip cost (B) 30,186 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 90,557 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785
Total Capital Investment (TCI) = DC + IC 6,037,137 Retrofit multiplier 5 60% of TCI 3,622,282

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 15,859,420



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060 Supervisor 15% 15% of Operator Costs 3,909 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272 Maintenance Materials 100% of maintenance labor costs 31,272 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization 177,990 Water 0.28 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization 22,483 WW Treat Neutralization 1.69 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization 111,050 Lime 88.98 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization 3,930 Total Annual Direct Operating Costs 407,966
Indirect Operating Costs Overhead 60% of total labor and material costs 55,507 Administration (2% total capital costs) 2% of total capital costs (TCI) 120,743 Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,371 Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,371 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,497,017 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU104 Wet Scrubber 9/6/2006 Page 8 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 4: SOx 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 186,000 8.55 0.7

- 265.8 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 7,068 gpm 1 60 0.7

- 113.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 175 gpm 1 60 0.7

- 2.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 382.5

Reagent Use & Other Operating Costs Caustic Use 11.83 lb/hr SO2 2.50 lb NaOH/lb SO2 29.58 lb/hr Caustic Lime Use 11.83 lb/hr SO2 0.96 lb Lime/lb SO2 11.39 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 7,068 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 175 gpm Evaporation Loss 4 = 33.17 gpm

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Supervisor 15% of Op. NA 3,909 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 382.5 kW-hr 2,966,507 177,990 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization Water 0.28 $/kgal 174.5 gpm 81,211 22,483 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 1.69 $/kgal 141.4 gpm 65,778 111,050 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization Lime 89.0 $/ton 11.4 lb/hr 44 3,930 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU104 Wet Scrubber 9/6/2006 Page 9 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 5 SO x 

## Control - Wet Scrubber

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113 Standardized Flow Rate 181,762 scfm @ 32o F Expected Utilization Rate 93% Temperature 142 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5% Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F Dry Std Flow Rate 176,529 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 2,765,654 Purchased Equipment Total (B) 22% of control device cost (A) 3,360,270

Installation - Standard Costs 85% of purchased equip cost (B) 2,856,229 Installation - Site Specific Costs 6,200,000 Installation Total 2,856,229 Total Direct Capital Cost, DC 6,216,499 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040 Total Capital Investment (TCI) = DC + IC 16,952,864
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 476,790 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349

Actual 

### Emission Control Cost Calculation Emis Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 51.3 109.9 0% 109.9 - NA Sulfur Dioxide (SO 2 ) 35.5 26.3

60% 10.5 15.8 152,149

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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU110 Wet Scrubber 9/6/2006 Page 10 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 5 SOx Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,765,654 Instrumentation 10% of control device cost (A) 276,565 MN Sales Taxes 7% of control device cost (A) 179,768 Freight 5% of control device cost (A) 138,283 Purchased Equipment Total (B) 22% 3,360,270

Installation Foundations & supports 12% of purchased equip cost (B) 403,232 Handling & erection 40% of purchased equip cost (B) 1,344,108 Electrical 1% of purchased equip cost (B) 33,603 Piping 30% of purchased equip cost (B) 1,008,081 Insulation 1% of purchased equip cost (B) 33,603 Painting 1% of purchased equip cost (B) 33,603 Installation Subtotal Standard Expenses 85% 2,856,229
Total Direct Capital Cost, DC 6,216,499
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 168,013 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 168,013 Start-up 1% of purchased equip cost (B) 33,603 Performance test 1% of purchased equip cost (B) 33,603 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 100,808 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040
Total Capital Investment (TCI) = DC + IC 6,720,540 Retrofit multiplier 5 60% of TCI 4,032,324

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 16,952,864



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060 Supervisor 15% 15% of Operator Costs 3,909 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272 Maintenance Materials 100% of maintenance labor costs 31,272 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization 212,823 Water 0.28 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization 26,883 WW Treat Neutralization 1.69 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization 132,783 Lime 88.98 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization 11,789 Total Annual Direct Operating Costs 476,790
Indirect Operating Costs Overhead 60% of total labor and material costs 55,507 Administration (2% total capital costs) 2% of total capital costs (TCI) 134,411 Property tax (1% total capital costs) 1% of total capital costs (TCI) 67,205 Insurance (1% total capital costs) 1% of total capital costs (TCI) 67,205 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,600,230 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU110 Wet Scrubber 9/6/2006 Page 11 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 5 SOx 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 222,400 8.55 0.7

- 317.8 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 8,451 gpm 1 60 0.7

- 136.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 209 gpm 1 60 0.7

- 3.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 457.4

Reagent Use & Other Operating Costs Caustic Use 35.50 lb/hr SO2 2.50 lb NaOH/lb SO2 88.75 lb/hr Caustic Lime Use 35.50 lb/hr SO2 0.96 lb Lime/lb SO2 34.17 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 8,451 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 209 gpm Evaporation Loss 4 = 39.66 gpm

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Supervisor 15% of Op. NA 3,909 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 457.4 kW-hr 3,547,050 212,823 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization Water 0.28 $/kgal 208.7 gpm 97,104 26,883 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 1.69 $/kgal 169.0 gpm 78,651 132,783 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization Lime 89.0 $/ton 34.2 lb/hr 132 11,789 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU110 Wet Scrubber 9/6/2006 Page 12 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 6: SO x 

## Control - Wet Scrubber

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115 Standardized Flow Rate 152,520 scfm @ 32o F Expected Utilization Rate 93% Temperature 140 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4% Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F Dry Std Flow Rate 136,902 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 2,484,419 Purchased Equipment Total (B) 22% of control device cost (A) 3,018,569

Installation - Standard Costs 85% of purchased equip cost (B) 2,565,783 Installation - Site Specific Costs 6,200,000 Installation Total 2,565,783 Total Direct Capital Cost, DC 5,584,352 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785 Total Capital Investment (TCI) = DC + IC 15,859,420
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 407,966 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975

Actual 

### Emission Control Cost Calculation Emis Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 124.8 267.7 0% 267.7 - NA Sulfur Dioxide (SO 2 ) 11.8 8.8

60% 3.5 5.3 417,742

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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU114 Wet Scrubber 9/6/2006 Page 13 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 6: SOx Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,484,419 Instrumentation 10% of control device cost (A) 248,442 MN Sales Taxes 7% of control device cost (A) 161,487 Freight 5% of control device cost (A) 124,221 Purchased Equipment Total (B) 22% 3,018,569

Installation Foundations & supports 12% of purchased equip cost (B) 362,228 Handling & erection 40% of purchased equip cost (B) 1,207,427 Electrical 1% of purchased equip cost (B) 30,186 Piping 30% of purchased equip cost (B) 905,571 Insulation 1% of purchased equip cost (B) 30,186 Painting 1% of purchased equip cost (B) 30,186 Installation Subtotal Standard Expenses 85% 2,565,783
Total Direct Capital Cost, DC 5,584,352
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 150,928 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 150,928 Start-up 1% of purchased equip cost (B) 30,186 Performance test 1% of purchased equip cost (B) 30,186 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 90,557 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785
Total Capital Investment (TCI) = DC + IC 6,037,137 Retrofit multiplier 5 60% of TCI 3,622,282

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 15,859,420



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060 Supervisor 15% 15% of Operator Costs 3,909 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272 Maintenance Materials 100% of maintenance labor costs 31,272 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization 177,990 Water 0.28 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization 22,483 WW Treat Neutralization 1.69 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization 111,050 Lime 88.98 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization 3,930 Total Annual Direct Operating Costs 407,966
Indirect Operating Costs Overhead 60% of total labor and material costs 55,507 Administration (2% total capital costs) 2% of total capital costs (TCI) 120,743 Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,371 Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,371 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,497,017 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU114 Wet Scrubber 9/6/2006 Page 14 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 6: SOx 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 186,000 8.55 0.7

- 265.8 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 7,068 gpm 1 60 0.7

- 113.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 175 gpm 1 60 0.7

- 2.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 382.5

Reagent Use & Other Operating Costs Caustic Use 11.83 lb/hr SO2 2.50 lb NaOH/lb SO2 29.58 lb/hr Caustic Lime Use 11.83 lb/hr SO2 0.96 lb Lime/lb SO2 11.39 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 7,068 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 175 gpm Evaporation Loss 4 = 33.17 gpm

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Supervisor 15% of Op. NA 3,909 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 382.5 kW-hr 2,966,507 177,990 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization Water 0.28 $/kgal 174.5 gpm 81,211 22,483 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 1.69 $/kgal 141.4 gpm 65,778 111,050 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization Lime 89.0 $/ton 11.4 lb/hr 44 3,930 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU114 Wet Scrubber 9/6/2006 Page 15 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 7: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Furnace 11 Hood Exhaust

Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103 Standardized Flow Rate 181,762 scfm @ 32o F Expected Utilization Rate 93% Temperature 142 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3% Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F Dry Std Flow Rate 172,951 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 3,999,843 Purchased Equipment Total (B) 22% of control device cost (A) 4,859,809

Installation - Standard Costs 67% of purchased equip cost (B) 3,256,072 Installation - Site Specific Costs 6,200,000 Installation Total 3,256,072 Total Direct Capital Cost, DC 8,115,881 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091 Total Capital Investment (TCI) = DC + IC 23,617,556
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,425,578 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,188,875

Actual 

### Emission Control Cost Calculation Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 51.3 112.4 0% 112.4 - NA Sulfur Dioxide (SO 2 ) 35.5 28.6

80% 5.7 22.9 182,993

Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm. 3 CUECost Workbook Version 1.0, USEPA Document Page 2.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU100 WWESP 9/6/2006 Page 16 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 7: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 3,999,843 Instrumentation 10% of control device cost (A) 399,984 MN Sales Taxes 6.5% of control device cost (A) 259,990 Freight 5% of control device cost (A) 199,992 Purchased Equipment Total (B) 22% 4,859,809

Installation Foundations & supports 4% of purchased equip cost (B) 194,392 Handling & erection 50% of purchased equip cost (B) 2,429,905 Electrical 8% of purchased equip cost (B) 388,785 Piping 1% of purchased equip cost (B) 48,598 Insulation 2% of purchased equip cost (B) 97,196 Painting 2% of purchased equip cost (B) 97,196 Installation Subtotal Standard Expenses 67% 3,256,072
Total Direct Capital Cost, DC 8,115,881
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 971,962 Construction & field expenses 20% of purchased equip cost (B) 971,962 Contractor fees 10% of purchased equip cost (B) 485,981 Start-up 1% of purchased equip cost (B) 48,598 Performance test 1% of purchased equip cost (B) 48,598 Model Studies 2% of purchased equip cost (B) 97,196 Contingencies 3% of purchased equip cost (B) 145,794 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091
Total Capital Investment (TCI) = DC + IC 10,885,972 Retrofit multiplier 3 60% of TCI 6,531,583

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 23,617,556



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2 hr/8 hr shift, Annual Operating Hours, 0% utilization 104,239 Supervisor 15% of Op., 0 , Annual Operating Hours, 0% utilization 15,636 Maintenance Maintenance Labor 60.00 $/Hr, 15 hr/wk, Annual Operating Hours, 0% utilization 4,340 Maintenance Materials 1.00 % of Maintenance Labor 39,998 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization 244,544 Water 0.28 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 143,251 WW Treat Neutralization 1.69 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 873,571 Caustic 305.96 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization 105,296 Total Annual Direct Operating Costs 1,425,578
Indirect Operating Costs Overhead 60% of total labor and material costs 98,528 Administration (2% total capital costs) 2% of total capital costs (TCI) 217,719 Property tax (1% total capital costs) 1% of total capital costs (TCI) 108,860 Insurance (1% total capital costs) 1% of total capital costs (TCI) 108,860 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,229,330 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,188,875

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU100 WWESP 9/6/2006 Page 17 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 7: 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 222,400 10 402.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 20.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area ESP Power 52,600 102.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 525.5

Reagent Use & Other Operating Costs
gpm Water 5.00 gal/min-kacfm 1112.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 88.75 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor , 0 , Annual Operating Hours, 0% utilization Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2 hr/8 hr shift, Annual Operating Hours, 0% utilization Supervisor 15% of Op. NA 15,636 of Op., 0 , Annual Operating Hours, 0% utilization Maintenance , 0 , Annual Operating Hours, 0% utilization Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,340 $/Hr, 15 hr/wk, Annual Operating Hours, 0% utilization Maint Mtls 1 % of Purchase Cost NA 39,998 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 525.5 kW-hr 4,075,729 244,544 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization Water 0.28 $/mgal 1,112.0 gpm 517,438 143,251 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 1.69 $/mgal 1,112.0 gpm 517,438 873,571 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization Caustic 305.96 $/ton 88.8 lb/hr 344 105,296 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU100 WWESP 9/6/2006 Page 18 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 8: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Standardized Flow Rate 152,520 scfm @ 32o F Expected Utilization Rate 93% Temperature 140 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 3,593,104 Purchased Equipment Total (B) 22% of control device cost (A) 4,365,622

Installation - Standard Costs 67% of purchased equip cost (B) 2,924,967 Installation - Site Specific Costs 6,200,000 Installation Total 2,924,967 Total Direct Capital Cost, DC 7,290,588 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404 Total Capital Investment (TCI) = DC + IC 21,846,389
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,249,949 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,799,211

Actual 

### Emission Control Cost Calculation Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 124.8 273.7 0% 273.7 - NA Sulfur Dioxide (SO 2 ) 11.8 9.6 80% 1.9 7.6 496,949

Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm. 3 CUECost Workbook Version 1.0, USEPA Document Page 2.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU104 WWESP 9/6/2006 Page 19 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 8: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 3,593,104 Instrumentation 10% of control device cost (A) 359,310 MN Sales Taxes 6.5% of control device cost (A) 233,552 Freight 5% of control device cost (A) 179,655 Purchased Equipment Total (B) 22% 4,365,622

Installation Foundations & supports 4% of purchased equip cost (B) 174,625 Handling & erection 50% of purchased equip cost (B) 2,182,811 Electrical 8% of purchased equip cost (B) 349,250 Piping 1% of purchased equip cost (B) 43,656 Insulation 2% of purchased equip cost (B) 87,312 Painting 2% of purchased equip cost (B) 87,312 Installation Subtotal Standard Expenses 67% 2,924,967
Total Direct Capital Cost, DC 7,290,588
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 873,124 Construction & field expenses 20% of purchased equip cost (B) 873,124 Contractor fees 10% of purchased equip cost (B) 436,562 Start-up 1% of purchased equip cost (B) 43,656 Performance test 1% of purchased equip cost (B) 43,656 Model Studies 2% of purchased equip cost (B) 87,312 Contingencies 3% of purchased equip cost (B) 130,969 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404
Total Capital Investment (TCI) = DC + IC 9,778,993 Retrofit multiplier 3 60% of TCI 5,867,396

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 21,846,389



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239 Supervisor 15% 15% of Operator Costs 15,636 Maintenance Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,125 Maintenance Materials 1.00 % of Maintenance Labor 35,931 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization 204,519 Water 0.28 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 119,805 WW Treat Neutralization 1.69 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 730,595 Caustic 305.96 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization 35,099 Total Annual Direct Operating Costs 1,249,949
Indirect Operating Costs Overhead 60% of total labor and material costs 95,958 Administration (2% total capital costs) 2% of total capital costs (TCI) 195,580 Property tax (1% total capital costs) 1% of total capital costs (TCI) 97,790 Insurance (1% total capital costs) 1% of total capital costs (TCI) 97,790 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,062,145 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,799,211

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU104 WWESP 9/6/2006 Page 20 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 8: 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 186,000 10 336.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 17.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area ESP Power 43,991 85.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 439.5

Reagent Use & Other Operating Costs
gpm Water 5.00 gal/min-kacfm 930.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 29.58 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 15,636 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 8339.1 hr/yr Maint Mtls 1 % of Purchase Cost NA 35,931 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 439.5 kW-hr 3,408,658 204,519 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization Water 0.28 $/mgal 930.0 gpm 432,749 119,805 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 1.69 $/mgal 930.0 gpm 432,749 730,595 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization Caustic 305.96 $/ton 29.6 lb/hr 115 35,099 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU104 WWESP 9/6/2006 Page 21 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 9: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113 Standardized Flow Rate 181,762 scfm @ 32o F Expected Utilization Rate 93% Temperature 142 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5% Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F Dry Std Flow Rate 176,529 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 3,999,843 Purchased Equipment Total (B) 22% of control device cost (A) 4,859,809

Installation - Standard Costs 67% of purchased equip cost (B) 3,256,072 Installation - Site Specific Costs 6,200,000 Installation Total 3,256,072 Total Direct Capital Cost, DC 8,115,881 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091 Total Capital Investment (TCI) = DC + IC 23,617,556
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,530,874 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,294,171

Actual 

### Emission Control Cost Calculation Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 51.3 109.9 0% 109.9 - NA Sulfur Dioxide (SO 2 ) 35.5 26.3

80% 5.3 21.0 204,058

Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm. 3 CUECost Workbook Version 1.0, USEPA Document Page 2.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU110 WWESP 9/6/2006 Page 22 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 9: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 3,999,843 Instrumentation 10% of control device cost (A) 399,984 MN Sales Taxes 6.5% of control device cost (A) 259,990 Freight 5% of control device cost (A) 199,992 Purchased Equipment Total (B) 22% 4,859,809

Installation Foundations & supports 4% of purchased equip cost (B) 194,392 Handling & erection 50% of purchased equip cost (B) 2,429,905 Electrical 8% of purchased equip cost (B) 388,785 Piping 1% of purchased equip cost (B) 48,598 Insulation 2% of purchased equip cost (B) 97,196 Painting 2% of purchased equip cost (B) 97,196 Installation Subtotal Standard Expenses 67% 3,256,072
Total Direct Capital Cost, DC 8,115,881
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 971,962 Construction & field expenses 20% of purchased equip cost (B) 971,962 Contractor fees 10% of purchased equip cost (B) 485,981 Start-up 1% of purchased equip cost (B) 48,598 Performance test 1% of purchased equip cost (B) 48,598 Model Studies 2% of purchased equip cost (B) 97,196 Contingencies 3% of purchased equip cost (B) 145,794 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091
Total Capital Investment (TCI) = DC + IC 10,885,972 Retrofit multiplier 3 60% of TCI 6,531,583

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 23,617,556



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239 Supervisor 15% 15% of Operator Costs 15,636 Maintenance Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,340 Maintenance Materials 1.00 % of Maintenance Labor 39,998 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization 244,544 Water 0.28 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 143,251 WW Treat Neutralization 1.69 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 873,571 Caustic 305.96 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization 105,296 Total Annual Direct Operating Costs 1,530,874
Indirect Operating Costs Overhead 60% of total labor and material costs 98,528 Administration (2% total capital costs) 2% of total capital costs (TCI) 217,719 Property tax (1% total capital costs) 1% of total capital costs (TCI) 108,860 Insurance (1% total capital costs) 1% of total capital costs (TCI) 108,860 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,229,330 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,294,171

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU110 WWESP 9/6/2006 Page 23 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 9: 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 222,400 10 402.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 20.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area ESP Power 52,600 102.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 525.5

Reagent Use & Other Operating Costs
gpm Water 5.00 gal/min-kacfm 1112.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 88.75 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 15,636 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,340 $/Hr, 15.0 hr/wk, 8339.1 hr/yr Maint Mtls 1 % of Purchase Cost NA 39,998 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 525.5 kW-hr 4,075,729 244,544 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization Water 0.28 $/mgal 1,112.0 gpm 517,438 143,251 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 1.69 $/mgal 1,112.0 gpm 517,438 873,571 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization Caustic 305.96 $/ton 88.8 lb/hr 344 105,296 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU110 WWESP 9/6/2006 Page 24 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 10: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115 Standardized Flow Rate 152,520 scfm @ 32o F Expected Utilization Rate 93% Temperature 140 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4% Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F Dry Std Flow Rate 136,902 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 3,593,104 Purchased Equipment Total (B) 22% of control device cost (A) 4,365,622

Installation - Standard Costs 67% of purchased equip cost (B) 2,924,967 Installation - Site Specific Costs 6,200,000 Installation Total 2,924,967 Total Direct Capital Cost, DC 7,290,588 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404 Total Capital Investment (TCI) = DC + IC 21,846,389
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,214,850 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,764,113

Actual 

### Emission Control Cost Calculation Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 124.8 267.7 0% 267.7 - NA Sulfur Dioxide (SO 2 ) 11.8 8.8 80% 1.8 7.0 535,575

Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm. 3 CUECost Workbook Version 1.0, USEPA Document Page 2.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU114 WWESP 9/6/2006 Page 25 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 10: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 3,593,104 Instrumentation 10% of control device cost (A) 359,310 MN Sales Taxes 6.5% of control device cost (A) 233,552 Freight 5% of control device cost (A) 179,655 Purchased Equipment Total (B) 22% 4,365,622

Installation Foundations & supports 4% of purchased equip cost (B) 174,625 Handling & erection 50% of purchased equip cost (B) 2,182,811 Electrical 8% of purchased equip cost (B) 349,250 Piping 1% of purchased equip cost (B) 43,656 Insulation 2% of purchased equip cost (B) 87,312 Painting 2% of purchased equip cost (B) 87,312 Installation Subtotal Standard Expenses 67% 2,924,967
Total Direct Capital Cost, DC 7,290,588
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 873,124 Construction & field expenses 20% of purchased equip cost (B) 873,124 Contractor fees 10% of purchased equip cost (B) 436,562 Start-up 1% of purchased equip cost (B) 43,656 Performance test 1% of purchased equip cost (B) 43,656 Model Studies 2% of purchased equip cost (B) 87,312 Contingencies 3% of purchased equip cost (B) 130,969 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404
Total Capital Investment (TCI) = DC + IC 9,778,993 Retrofit multiplier 3 60% of TCI 5,867,396

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 21,846,389



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239 Supervisor 15% 15% of Operator Costs 15,636 Maintenance Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,125 Maintenance Materials 1.00 % of Maintenance Labor 35,931 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization 204,519 Water 0.28 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 119,805 WW Treat Neutralization 1.69 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 730,595 Total Annual Direct Operating Costs 1,214,850
Indirect Operating Costs Overhead 60% of total labor and material costs 95,958 Administration (2% total capital costs) 2% of total capital costs (TCI) 195,580 Property tax (1% total capital costs) 1% of total capital costs (TCI) 97,790 Insurance (1% total capital costs) 1% of total capital costs (TCI) 97,790 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,062,145 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,764,113

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU114 WWESP 9/6/2006 Page 26 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 10: 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 186,000 10 336.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 17.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area ESP Power 43,991 85.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 439.5

Reagent Use & Other Operating Costs
gpm Water 5.00 gal/min-kacfm 930.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 29.58 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 15,636 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 8339.1 hr/yr Maint Mtls 1 % of Purchase Cost NA 35,931 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 439.5 kW-hr 3,408,658 204,519 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization Water 0.28 $/mgal 930.0 gpm 432,749 119,805 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 1.69 $/mgal 930.0 gpm 432,749 730,595 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization Caustic 305.96 $/ton 29.6 lb/hr 115 35,099 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls EU114 WWESP 9/6/2006 Page 27 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 11: - SCR + Reheat (100)

Operating Unit: Furnace 11 Hood Exhaust

Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103 Chemical Engineering Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F Dry Std Flow Rate 172,951 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment (A) 10,191,798 Purchased Equipment Total (B) SCR Only 10,854,265

Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 2,024,725 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC SCR + Reheat 46,019,283

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 7,301,482 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,326,542 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 11,628,024



### Emission Control Cost Calculation Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 112.4 1.5 0.01 5.7 106.7 108,969

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 Control Efficiency = 90% reduction which is typically the upper range of normal SCR control efficiency 12 $35/MW-hr, 140 MW 13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (100) NOx SCR+ Reheat 90% Eff (100) 28 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 11: - SCR + Reheat (100)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,191,798 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 662,467 Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 10,854,265

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 24% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 24% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 2,024,725

Total Plant Cost D A + B + C 15,522,888
Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 475,098

Inventory Capital Reagent Vol * $/gal 2,331

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 24,232,317 Retrofit multiplier 3 

### 60% of TCI 1 4,539,390 Total Retorfit Capital Investment 38,771,707



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239 Supervisor 15% 15% of Operator Costs 15,636 Maintenance Maintenance Total 1.50 % of Total Capital Investment 363,485 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 1,444 kW-hr, 8339.1 hr/yr, 93% utilization 672,157 NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Cat. Replacement [14] 35.00 Catalyst Replacement 423,178 NA NA - Ammonia 0.12 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization 64,238 NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 1,642,933

Indirect Operating Costs Overhead 60% of total labor and material costs 40,360 Administration (2% total capital costs) 2% of total capital costs (TCI) 484,646 Property tax (1% total capital costs) 1% of total capital costs (TCI) 242,323 Insurance (1% total capital costs) 1% of total capital costs (TCI) 242,323 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,287,359 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,297,011

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,939,944

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (100) NOx SCR+ Reheat 90% Eff (100) 29 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 11: - SCR + Reheat (100)

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Equivalent Duty 1,052 Plant Cap kW A 107,954 Est power platn eff 35% Unc Nox lb/mmBtu B 0.05 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 107,954 Capital Cost $/kW D $94.41 $10,191,798.18 Total SCR Equipment Uncontrolled Nox t/y 112.4 Fixed O&M E $67,265.87 Annual Operating Hrs 8000 Variable O&M F $205,606.98 Uncontrolled Nox lb/mmBtu 0.049 Ann Cap Factor G 0.82 Heat Input mmBtu/hr

H 6,000 SCR Capital Cost

Duty 1,052 MMBtu/hr Catalyst Area 

### 508 ft 2 

### 614 f (h SCR) Q flue gas 487,426 acfm Rx Area 584 83 f (h NH 3 

### ) N Ox Cont Eff 80% (as faction) Rx Height 24.2 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.05 lb/MMBtu n layer 22 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 23.5 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 23 layers 8,220,568 f (vol catalyst) Temperature 142 Deg F h SCR 131 ft f (h SCR) Catalyst Volume 34,252 ft 3 New/Retrofit 

### R N or R

Electrical Use Duty 1,052 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 1,444.5 NOx in 0.05 lb/MMBtu n catalyst layers 23 layers Press drop catalyst 

### 1 in H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O T otal 1444.5

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

### Density

20 lb/hr Neat 9.2 gal/hr 29% solution Volume 14 day inventory 3,083 gal $2,331 Inventory Cost 69 lb/hr

Design Basis Baseline Emis. Baseline Emis.

Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.01 Nitrous Oxides (NOx) 112.4 0.05 51.25

Actual 69,180 dscf/MMBtu Method 19 Factor 9,860 dscf/MMBtu Adjusted Duty 1,052 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 15,636 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 363,485 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 1444.5 kW-hr 11,202,612 672,157 $/kwh, 1,444 kW-hr, 8339.1 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 108.0 mw 112 423,178 Catalyst Replacement

7 Ammonia 0.12 $/lb 69 lb/hr 532,660 64,238 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (100) NOx SCR+ Reheat 90% Eff (100) 30 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 12: Reheat (100)

Operating Unit: Furnace 11 Hood Exhaust

Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103 Chemical Engineering Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F Dry Std Flow Rate 172,951 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 535,530 Purchased Equipment Total (B) 22% of control device cost (A) 650,668

Installation - Standard Costs 30% of purchased equip cost (B) 195,201 Installation - Site Specific Costs 6,200,000 Installation Total 6,395,201 Total Direct Capital Cost, DC 7,045,869 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,707 Total Capital Investment (TCI) = DC + IC 7,247,576
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 5,658,549 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,530 Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,688,079

Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (100) Reheat (100) 31 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 12: Reheat (100)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 535,530 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 53,553 MN Sales Taxes 6.5% of control device cost (A) 34,809 Freight 5% of control device cost (A) 26,776 Purchased Equipment Total (B) 22% 650,668

Installation Foundations & supports 8% of purchased equip cost (B) 52,053 Handling & erection 14% of purchased equip cost (B) 91,094 Electrical 4% of purchased equip cost (B) 26,027 Piping 2% of purchased equip cost (B) 13,013 Insulation 1% of purchased equip cost (B) 6,507 Painting 1% of purchased equip cost (B) 6,507 Installation Subtotal Standard Expenses 30% 195,201

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 Installation Total 6,395,201 Total Direct Capital Cost, DC 7,045,869

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 65,067 Construction & field expenses 5% of purchased equip cost (B) 32,533 Contractor fees 10% of purchased equip cost (B) 65,067 Start-up 2% of purchased equip cost (B) 13,013 Performance test 1% of purchased equip cost (B) 6,507 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 19,520 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,707
Total Capital Investment (TCI) = DC + IC 7,247,576
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,247,576



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060 Supervisor 15% 15% of Operator Costs 3,909 Maintenance Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272 Maintenance Materials 100% of maintenance labor costs 31,272 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization 383,421 Natural Gas 10.02 $/mscf, 1,112 scfm, 8339.1 hr/yr, 93% utilization 5,182,616

Total Annual Direct Operating Costs 5,658,549

Indirect Operating Costs Overhead 60% of total labor and material costs 55,507 Administration (2% total capital costs) 2% of total capital costs (TCI) 144,952 Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,476 Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,476 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 684,120 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,530

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,688,079

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (100) Reheat (100) 32 of 56

## Cleveland Cliffs Incorporated: United Taconite BART Report - <Insert attachment name> Emission Control Cost Analysis Table 12: Reheat (100)

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years CRF 0.5531 Rep part cost per unit 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 222,400 19 0.6 824.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 222,400 23 0.6 997.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 824.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 3,909 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 824.0 kW-hr 6,390,357 383,421 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization Natural Gas 10.02 $/mscf 1,112 scfm 517,206 5,182,616 $/mscf, 1,112 scfm, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (100) Reheat (100) 33 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 12: Reheat (100)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 T wi 142 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 568 Deg F - Temperature of waste gas out of heat recovery

T fo 324 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 195,062 scfm - Flow of waste gas

Q af 1,112 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 196,173 scfm Flue Gas Cost in 1989 $'s $449,154 Current Cost Using CHE Plant Cost Index $535,530 Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0 44 mw CO2 15 v % 184 22.0% 0.24 0.0528 18 mw H2O 10 v % 50 6.0% 0.46 0.0276 28 mw N2 60 v % 468 56.0% 0.27 0.1512 32 mw O2 15 v % 134 16.0% 0.23 0.0368 Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (100) Reheat (100) 34 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 13: - SCR + Reheat (104)

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Chemical Engineering Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs EPRI Correlation 1998 Purchased Equipment (A) 2005 0 Purchased Equipment Total (B) 0% of control device cost (A) SCR Only 9,372,318

Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 1,802,433 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC SCR + Reheat 43,197,692

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 4,157,530 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,081,731 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 8,239,261



### Emission Control Cost Calculation Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 273.7 4.6 0.03 17.8 255.9 32,199

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 Control Efficiency = 90% reduction which is typically the upper range of normal SCR control efficiency 12 $35/MW-hr, 140 MW 13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (104) NOx SCR+ Reheat 90% Eff (104) 35 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 13: - SCR + Reheat (104)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 8,800,299 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 572,019 Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 9,372,318

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 28% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 28% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 1,802,433

Total Plant Cost D A + B + C 13,818,649
Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 441,013

Inventory Capital Reagent Vol * $/gal 5,677

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 22,497,340 Retrofit multiplier 3 

### 60% of TCI 1 3,498,404 Total Retorfit Capital Investment 35,995,743



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239 Supervisor 15% 15% of Operator Costs 15,636 Maintenance Maintenance Total 1.50 % of Total Capital Investment 337,460 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 1,167 kW-hr, 8339.1 hr/yr, 93% utilization 543,246 NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Cat. Replacement [14] 35.00 Catalyst Replacement 327,363 NA NA - Ammonia 0.12 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization 156,470 NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 1,484,414

Indirect Operating Costs Overhead 60% of total labor and material costs 34,849 Administration (2% total capital costs) 2% of total capital costs (TCI) 449,947 Property tax (1% total capital costs) 1% of total capital costs (TCI) 224,973 Insurance (1% total capital costs) 1% of total capital costs (TCI) 224,973 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,123,590 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,058,332

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,542,746

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (104) NOx SCR+ Reheat 90% Eff (104) 36 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 13: - SCR + Reheat (104)

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Equivalent Duty 814 Plant Cap kW A 83,511 Est power platn eff 35% Unc Nox lb/mmBtu B 0.15 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 83,511 Capital Cost $/kW D $105.38 $8,800,298.76 Total SCR Equipment Uncontrolled Nox t/y 273.7 Fixed O&M E $58,081.97 Annual Operating Hrs 8000 Variable O&M F $171,504.18 Uncontrolled Nox lb/mmBtu 0.153 Ann Cap Factor G 0.82 Heat Input mmBtu/hr

H 6,000 SCR Capital Cost

Duty 814 MMBtu/hr Catalyst Area 

### 393 ft 2 

### 638 f (h SCR) Q flue gas 377,064 acfm Rx Area 452 121 f (h NH 3 

### ) N Ox Cont Eff 80% (as faction) Rx Height 21.3 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.15 lb/MMBtu n layer 23 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 24.5 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 24 layers 6,646,500 f (vol catalyst) Temperature 140 Deg F h SCR 135 ft f (h SCR) Catalyst Volume 27,694 ft 3 New/Retrofit 

### R N or R

Electrical Use Duty 814 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 1,167.5 NOx in 0.15 lb/MMBtu n catalyst layers 24 layers Press drop catalyst 

### 1 in H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O T otal 1167.5

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

### Density

49 lb/hr Neat 22.3 gal/hr 29% solution Volume 14 day inventory 7,509 gal $5,677 Inventory Cost 167 lb/hr

Design Basis Baseline Emis. Baseline Emis.

Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.03 Nitrous Oxides (NOx) 273.7 0.15 124.83

Actual 53,517 dscf/MMBtu Method 19 Factor 9,860 dscf/MMBtu Adjusted Duty 814 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 15,636 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 337,460 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 1167.5 kW-hr 9,054,097 543,246 $/kwh, 1,167 kW-hr, 8339.1 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 83.5 mw 112 327,363 Catalyst Replacement

7 Ammonia 0.12 $/lb 167 lb/hr 1,297,437 156,470 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (104) NOx SCR+ Reheat 90% Eff (104) 37 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 14: - Reheat (104)

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Chemical Engineering Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 512,205 Purchased Equipment Total (B) 22% of control device cost (A) 622,328

Installation - Standard Costs 30% of purchased equip cost (B) 186,699 Installation - Site Specific Costs 6,200,000 Installation Total 6,386,699 Total Direct Capital Cost, DC 7,009,027 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 192,922 Total Capital Investment (TCI) = DC + IC 7,201,949
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,673,116 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,398 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,696,515

Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (104) Reheat (104) 38 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 14: - Reheat (104)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 512,205 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 51,220 MN Sales Taxes 6.5% of control device cost (A) 33,293 Freight 5% of control device cost (A) 25,610 Purchased Equipment Total (B) 22% 622,328

Installation Foundations & supports 8% of purchased equip cost (B) 49,786 Handling & erection 14% of purchased equip cost (B) 87,126 Electrical 4% of purchased equip cost (B) 24,893 Piping 2% of purchased equip cost (B) 12,447 Insulation 1% of purchased equip cost (B) 6,223 Painting 1% of purchased equip cost (B) 6,223 Installation Subtotal Standard Expenses 30% 186,699

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 Installation Total 6,386,699 Total Direct Capital Cost, DC 7,009,027

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 62,233 Construction & field expenses 5% of purchased equip cost (B) 31,116 Contractor fees 10% of purchased equip cost (B) 62,233 Start-up 2% of purchased equip cost (B) 12,447 Performance test 1% of purchased equip cost (B) 6,223 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 18,670 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 192,922
Total Capital Investment (TCI) = DC + IC 7,201,949
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,201,949



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060 Supervisor 15% 15% of Operator Costs 3,909 Maintenance Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272 Maintenance Materials 100% of maintenance labor costs 31,272 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization 320,667 Natural Gas 10.02 $/mscf, 485 scfm, 8339.1 hr/yr, 93% utilization 2,259,937

Total Annual Direct Operating Costs 2,673,116

Indirect Operating Costs Overhead 60% of total labor and material costs 55,507 Administration (2% total capital costs) 2% of total capital costs (TCI) 144,039 Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,019 Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,019 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 679,813 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,398

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,696,515

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (104) Reheat (104) 39 of 56

## Cleveland Cliffs Incorporated: United Taconite BART Report - <Insert attachment name> Emission Control Cost Analysis Table 14: - Reheat (104)

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years CRF 0.5531 Rep part cost per unit 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 186,000 19 0.6 689.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 186,000 23 0.6 834.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 689.1

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 3,909 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 689.1 kW-hr 5,344,453 320,667 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization Natural Gas 10.02 $/mscf 485 scfm 225,534 2,259,937 $/mscf, 485 scfm, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (104) Reheat (104) 40 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 14: - Reheat (104)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 T wi 140 Deg F - Temperature of waste gas into heat recovery T fi 450 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 357 Deg F - Temperature of waste gas out of heat recovery

T fo 233 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 163,680 scfm - Flow of waste gas

Q af 485 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 164,165 scfm Flue Gas Cost in 1989 $'s $429,591 Current Cost Using CHE Plant Cost Index $512,205 Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0 44 mw CO2 15 v % 184 22.0% 0.24 0.0528 18 mw H2O 10 v % 50 6.0% 0.46 0.0276 28 mw N2 60 v % 468 56.0% 0.27 0.1512 32 mw O2 15 v % 134 16.0% 0.23 0.0368 Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (104) Reheat (104) 41 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 15: - SCR + Reheat (110)

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113 Chemical Engineering Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F Dry Std Flow Rate 176,529 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs EPRI Correlation 1998 Purchased Equipment (A) 2005 10,324,640 Purchased Equipment Total (B) 0% of control device cost (A) SCR Only 10,995,741

Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 2,045,946 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC SCR + Reheat 46,284,809

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 7,339,040 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,349,371 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 11,688,411



### Emission Control Cost Calculation Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 109.9 1.4 0.01 5.6 104.4 112,008

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 Control Efficiency = 90% reduction which is typically the upper range of normal SCR control efficiency 12 $35/MW-hr, 140 MW 13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (110) NOx SCR+ Reheat 90% Eff (110) 42 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 15: - SCR + Reheat (110)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,324,640 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 671,102 Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 10,995,741

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 24% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 24% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 2,045,946

Total Plant Cost D A + B + C 15,685,586
Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 478,352

Inventory Capital Reagent Vol * $/gal 2,331

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 24,398,268 Retrofit multiplier 3 

### 60% of TCI 1 4,638,961 Total Retorfit Capital Investment 39,037,230



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239 Supervisor 15% 15% of Operator Costs 15,636 Maintenance Maintenance Total 1.50 % of Total Capital Investment 365,974 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 1,474 kW-hr, 8339.1 hr/yr, 93% utilization 686,019 NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Cat. Replacement [14] 35.00 Catalyst Replacement 431,932 NA NA - Ammonia 0.12 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization 64,238 NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 1,668,038

Indirect Operating Costs Overhead 60% of total labor and material costs 40,886 Administration (2% total capital costs) 2% of total capital costs (TCI) 487,965 Property tax (1% total capital costs) 1% of total capital costs (TCI) 243,983 Insurance (1% total capital costs) 1% of total capital costs (TCI) 243,983 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,303,024 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,319,840

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,987,878

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (110) NOx SCR+ Reheat 90% Eff (110) 43 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 15: - SCR + Reheat (110)

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Equivalent Duty 1,074 Plant Cap kW A 110,187 Est power platn eff 35% Unc Nox lb/mmBtu B 0.05 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 110,187 Capital Cost $/kW D $93.70 $10,324,639.77 Total SCR Equipment Uncontrolled Nox t/y 109.9 Fixed O&M E $68,142.62 Annual Operating Hrs 8000 Variable O&M F $209,166.23 Uncontrolled Nox lb/mmBtu 0.048 Ann Cap Factor G 0.82 Heat Input mmBtu/hr

H 6,000 SCR Capital Cost

Duty 1,074 MMBtu/hr Catalyst Area 

### 518 ft 2 

### 613 f (h SCR) Q flue gas 497,508 acfm Rx Area 596 80 f (h NH 3 

### ) N Ox Cont Eff 80% (as faction) Rx Height 24.4 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.05 lb/MMBtu n layer 22 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 23.5 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 23 layers 8,387,553 f (vol catalyst) Temperature 142 Deg F h SCR 131 ft f (h SCR) Catalyst Volume 34,948 ft 3 New/Retrofit 

### R N or R

Electrical Use Duty 1,074 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 1,474.3 NOx in 0.05 lb/MMBtu n catalyst layers 23 layers Press drop catalyst 

### 1 in H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O T otal 1474.3

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

### Density

20 lb/hr Neat 9.2 gal/hr 29% solution Volume 14 day inventory 3,083 gal $2,331 Inventory Cost 69 lb/hr

Design Basis Baseline Emis. Baseline Emis.

Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.01 Nitrous Oxides (NOx) 109.9 0.05 51.25

Actual 70,611 dscf/MMBtu Method 19 Factor 9,860 dscf/MMBtu Adjusted Duty 1,074 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 15,636 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 365,974 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 1474.3 kW-hr 11,433,649 686,019 $/kwh, 1,474 kW-hr, 8339.1 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 110.2 mw 112 431,932 Catalyst Replacement

7 Ammonia 0.12 $/lb 69 lb/hr 532,660 64,238 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (110) NOx SCR+ Reheat 90% Eff (110) 44 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 16: - Reheat (110)

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113 Chemical Engineering Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F Dry Std Flow Rate 176,529 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 535,531 Purchased Equipment Total (B) 22% of control device cost (A) 650,671

Installation - Standard Costs 30% of purchased equip cost (B) 195,201 Installation - Site Specific Costs 6,200,000 Installation Total 6,395,201 Total Direct Capital Cost, DC 7,045,872 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,708 Total Capital Investment (TCI) = DC + IC 7,247,580
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 5,671,002 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,531 Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,700,533

Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (110) Reheat (110) 45 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 16: - Reheat (110)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 535,531 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 53,553 MN Sales Taxes 6.5% of control device cost (A) 34,810 Freight 5% of control device cost (A) 26,777 Purchased Equipment Total (B) 22% 650,671

Installation Foundations & supports 8% of purchased equip cost (B) 52,054 Handling & erection 14% of purchased equip cost (B) 91,094 Electrical 4% of purchased equip cost (B) 26,027 Piping 2% of purchased equip cost (B) 13,013 Insulation 1% of purchased equip cost (B) 6,507 Painting 1% of purchased equip cost (B) 6,507 Installation Subtotal Standard Expenses 30% 195,201

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 Installation Total 6,395,201 Total Direct Capital Cost, DC 7,045,872

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 65,067 Construction & field expenses 5% of purchased equip cost (B) 32,534 Contractor fees 10% of purchased equip cost (B) 65,067 Start-up 2% of purchased equip cost (B) 13,013 Performance test 1% of purchased equip cost (B) 6,507 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 19,520 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,708
Total Capital Investment (TCI) = DC + IC 7,247,580
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,247,580



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060 Supervisor 15% 15% of Operator Costs 3,909 Maintenance Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272 Maintenance Materials 100% of maintenance labor costs 31,272 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization 383,421 Natural Gas 10.02 $/mscf, 1,114 scfm, 8339.1 hr/yr, 93% utilization 5,195,069

Total Annual Direct Operating Costs 5,671,002

Indirect Operating Costs Overhead 60% of total labor and material costs 55,507 Administration (2% total capital costs) 2% of total capital costs (TCI) 144,952 Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,476 Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,476 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 684,120 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,531

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,700,533

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (110) Reheat (110) 46 of 56

## Cleveland Cliffs Incorporated: United Taconite BART Report - <Insert attachment name> Emission Control Cost Analysis Table 16: - Reheat (110)

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years CRF 0.5531 Rep part cost per unit 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 222,400 19 0.6 824.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 222,400 23 0.6 997.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 824.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 3,909 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 824.0 kW-hr 6,390,357 383,421 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization Natural Gas 10.02 $/mscf 1,114 scfm 518,449 5,195,069 $/mscf, 1,114 scfm, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (110) Reheat (110) 47 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 16: - Reheat (110)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 T wi 140 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 567 Deg F - Temperature of waste gas out of heat recovery

T fo 323 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 195,062 scfm - Flow of waste gas

Q af 1,114 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 196,176 scfm Flue Gas Cost in 1989 $'s $449,155 Current Cost Using CHE Plant Cost Index $535,531 Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0 44 mw CO2 15 v % 184 22.0% 0.24 0.0528 18 mw H2O 10 v % 50 6.0% 0.46 0.0276 28 mw N2 60 v % 468 56.0% 0.27 0.1512 32 mw O2 15 v % 134 16.0% 0.23 0.0368 Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (110) Reheat (110) 48 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 17: - SCR + Reheat (114)

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115 Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32o F Expected Utiliztion Rate 93% Temperature 140 Deg F Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4% Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F Dry Std Flow Rate 136,902 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment (A) 8,929,135 Purchased Equipment Total (B) SCR Only 9,509,529

Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 1,823,014 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC SCR + Reheat 43,455,895

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 6,279,410 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,103,963 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 10,383,373



### Emission Control Cost Calculation Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 267.7 4.5 0.03 17.4 250.3 41,488

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 Control Efficiency = 90% reduction which is typically the upper range of normal SCR control efficiency 12 $35/MW-hr, 140 MW 13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (114) NOx SCR+ Reheat 90% Eff (114) 49 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 17: - SCR + Reheat (114)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 8,929,135 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 580,394 Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 9,509,529

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 28% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 28% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 1,823,014

Total Plant Cost D A + B + C 13,976,441
Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 444,169

Inventory Capital Reagent Vol * $/gal 5,677

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 22,658,287 Retrofit multiplier 3 

### 60% of TCI 1 3,594,972 Total Retorfit Capital Investment 36,253,260



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239 Supervisor 15% 15% of Operator Costs 15,636 Maintenance Maintenance Total 1.50 % of Total Capital Investment 339,874 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 1,194 kW-hr, 8339.1 hr/yr, 93% utilization 555,760 NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Cat. Replacement [14] 35.00 Catalyst Replacement 334,973 NA NA - Ammonia 0.12 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization 156,470 NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 1,506,951

Indirect Operating Costs Overhead 60% of total labor and material costs 35,359 Administration (2% total capital costs) 2% of total capital costs (TCI) 453,166 Property tax (1% total capital costs) 1% of total capital costs (TCI) 226,583 Insurance (1% total capital costs) 1% of total capital costs (TCI) 226,583 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,138,782 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,080,473

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,587,424

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (114) NOx SCR+ Reheat 90% Eff (114) 50 of 56

## Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis Table 17: - SCR + Reheat (114)

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Equivalent Duty 833 Plant Cap kW A 85,452 Est power platn eff 35% Unc Nox lb/mmBtu B 0.15 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 85,452 Capital Cost $/kW D $104.49 $8,929,134.83 Total SCR Equipment Uncontrolled Nox t/y 267.7 Fixed O&M E $58,932.29 Annual Operating Hrs 8000 Variable O&M F $174,705.21 Uncontrolled Nox lb/mmBtu 0.150 Ann Cap Factor G 0.82 Heat Input mmBtu/hr

H 6,000 SCR Capital Cost

Duty 833 MMBtu/hr Catalyst Area 

### 402 ft 2 

### 638 f (h SCR) Q flue gas 385,829 acfm Rx Area 462 117 f (h NH 3 

### ) N Ox Cont Eff 80% (as faction) Rx Height 21.5 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.15 lb/MMBtu n layer 23 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 24.5 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 24 layers 6,792,565 f (vol catalyst) Temperature 140 Deg F h SCR 135 ft f (h SCR) Catalyst Volume 28,302 ft 3 New/Retrofit 

### R N or R

Electrical Use Duty 833 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 1,194.4 NOx in 0.15 lb/MMBtu n catalyst layers 24 layers Press drop catalyst 

### 1 in H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O T otal 1194.4

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

### Density

49 lb/hr Neat 22.3 gal/hr 29% solution Volume 14 day inventory 7,509 gal $5,677 Inventory Cost 167 lb/hr

Design Basis Baseline Emis. Baseline Emis.

Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.03 Nitrous Oxides (NOx) 267.7 0.15 124.83

Actual 54,761 dscf/MMBtu Method 19 Factor 9,860 dscf/MMBtu Adjusted Duty 833 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 15,636 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 339,874 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 1194.4 kW-hr 9,262,659 555,760 $/kwh, 1,194 kW-hr, 8339.1 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 85.5 mw 112 334,973 Catalyst Replacement

7 Ammonia 0.12 $/lb 167 lb/hr 1,297,437 156,470 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls NOx SCR+ Reheat 90% Eff (114) NOx SCR+ Reheat 90% Eff (114) 51 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 18: - Reheat (114)

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114 Stack/Vent Number SV 104 & 105 Chemical Engineering Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 512,555 Purchased Equipment Total (B) 22% of control device cost (A) 622,755

Installation - Standard Costs 30% of purchased equip cost (B) 186,826 Installation - Site Specific Costs 6,200,000 Installation Total 6,386,826 Total Direct Capital Cost, DC 7,009,581 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 193,054 Total Capital Investment (TCI) = DC + IC 7,202,635
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,772,459 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,490 Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,795,949

Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (114) Reheat (114) 52 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 18: - Reheat (114)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 512,555 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 51,256 MN Sales Taxes 6.5% of control device cost (A) 33,316 Freight 5% of control device cost (A) 25,628 Purchased Equipment Total (B) 22% 622,755

Installation Foundations & supports 8% of purchased equip cost (B) 49,820 Handling & erection 14% of purchased equip cost (B) 87,186 Electrical 4% of purchased equip cost (B) 24,910 Piping 2% of purchased equip cost (B) 12,455 Insulation 1% of purchased equip cost (B) 6,228 Painting 1% of purchased equip cost (B) 6,228 Installation Subtotal Standard Expenses 30% 186,826

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 Installation Total 6,386,826 Total Direct Capital Cost, DC 7,009,581

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 62,275 Construction & field expenses 5% of purchased equip cost (B) 31,138 Contractor fees 10% of purchased equip cost (B) 62,275 Start-up 2% of purchased equip cost (B) 12,455 Performance test 1% of purchased equip cost (B) 6,228 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 18,683 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 193,054
Total Capital Investment (TCI) = DC + IC 7,202,635
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,202,635



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060 Supervisor 15% 15% of Operator Costs 3,909 Maintenance Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272 Maintenance Materials 100% of maintenance labor costs 31,272 Utilities, Supplies, Replacements & Waste Management Electricity 0.06 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization 320,667 Natural Gas 10.02 $/mscf, 935 scfm, 8339.1 hr/yr, 93% utilization 4,359,280

Total Annual Direct Operating Costs 4,772,459

Indirect Operating Costs Overhead 60% of total labor and material costs 55,507 Administration (2% total capital costs) 2% of total capital costs (TCI) 144,053 Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,026 Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,026 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 679,878 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,490

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,795,949

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (114) Reheat (114) 53 of 56

## Cleveland Cliffs Incorporated: United Taconite BART Report - <Insert attachment name> Emission Control Cost Analysis Table 18: - Reheat (114)

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 2 years CRF 0.5531 Rep part cost per unit 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 186,000 19 0.6 689.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 186,000 23 0.6 834.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 689.1

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,339 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr Supervisor 15% of Op. NA 3,909 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.060 $/kwh 689.1 kW-hr 5,344,453 320,667 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization Natural Gas 10.02 $/mscf 935 scfm 435,040 4,359,280 $/mscf, 935 scfm, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (114) Reheat (114) 54 of 56

## Cleveland Cliffs Incorporated: Northshore Mining BART Report - Appendix A Emission Control Cost Analysis Table 18: - Reheat (114)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 T wi 140 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 567 Deg F - Temperature of waste gas out of heat recovery

T fo 323 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 163,680 scfm - Flow of waste gas

Q af 935 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 164,615 scfm Flue Gas Cost in 1989 $'s $429,885 Current Cost Using CHE Plant Cost Index $512,555 Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0 44 mw CO2 15 v % 184 22.0% 0.24 0.0528 18 mw H2O 10 v % 50 6.0% 0.46 0.0276 28 mw N2 60 v % 468 56.0% 0.27 0.1512 32 mw O2 15 v % 134 16.0% 0.23 0.0368 Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls Reheat (114) Reheat (114) 55 of 56InputsCalculated or scaled valuesEstimated value1 23 4 56789Stack No FacilityNameSO2Max. 24-hr ActualEmissionsFlow Rateat ExitSpecificCollection Area(SCA)1Surface CollectionArea2PressureDrop3Cost4lb/hr acfmft2/kacfmft2in. H20$BASEN/A291,00019868,82554,700,000SV 101, 102, & 103 Northshore Furnace 11 Hood Exhaust35.50 222,400 198 52,60010 3,999,843SV 104 & 105 Northshore Furnace 11 Waste Gas11.83 186,000 19843,99110 3,593,104SV 111, 112, & 113 Northshore Furnace 12 Hood Exhaust35.50 222,400 19852,60010 3,999,843SV 114 & 115 Northshore Furnace 12 Waste Gas11.83 186,000 19843,99110 3,593,104SV021M-SV024M Hibbtac Pellet Indurating Furnace Line No 130.00 772,000 198182,58710 8,439,806SV025M-SV028M Hibbtac Pellet Indurating Furnace Line No 238.00 795,000 198188,02710 8,589,786SV029M-SV032M Hibbtac Pellet Indurating Furnace Line No 343.00 827,000 198195,59510 8,795,598SV 014Ispat Indurating Furnace125.00 205,478 19848,59810 3,814,356SV 015Ispat Indurating Furnace125.00 205,478 19848,59810 3,814,356SV 016Ispat Indurating Furnace125.00 205,478 19848,59810 3,814,356SV 017Ispat Indurating Furnace125.00 205,478 19848,59810 3,814,356SV 046UTAC Line 1 Pellet Induration4.25 369,137 19887,30510 5,420,940SV 049UTAC Line 2 Pellet Induration286.67 380,000 19889,87510 5,516,101SV 048UTAC Line 2 Pellet Induration345.50 346,000 19881,83310 5,214,441SV051M Keetac Grate Kiln - Indurator Waste Gas, Phase II 217.2 848,000 198200,56210 8,928,933SV 151Minntac Line 7 waste gas75.0 600,000 198141,90710 7,255,257SV 127Minntac Line 5 waste gas93.7 650,000 198153,73310 7,612,198SV 144Minntac Line 6 waste gas113.5 555,650 198131,41810 6,928,558SV 118Minntac Line 4 waste gas133.1 650,000 198153,73310 7,612,198SV 103Minntac Line 3 waste gas128.9 322,000 19876,15710 4,994,311NSM Power365.0 300,000141,9079,573,3691) Estimated value from Durr. Value indpendent of stack flow.2) Original estimate from Durr. Scaled linearly using stack flow rates.3) Pressure drop is not a design driving factor, but must be maintained at an acceptably low value. 10" H2O is used as a maximum value.4) Capital price back calculated using reverse of EPA control cost manual factors from installed price estimate provided from DURR.Used 0.6 power law factor to adjust price to each stack's acfm from bid basis of 291,000 acfm.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsWWESP Scale9/6/2006 Page 56 of 56Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 19: Cost Summary - Natural gas boilerNOxControl Cost Summarybaseline:0.17 lb/mmBtu11.625 lb/hrControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $Total Annual Cost$/yrPollution ControlCost $/tonIncrementalCost $/tonSelective Catalytic Reduction(SCR)90% 4.137.1 $5,563,529 $1,119,307$30,139Low NOx Burner / Flue GasRecirculation75% 10.330.9$547,722$77,510$2,505$30,626Low Nox Burner/Over Fire Air68% 13.427.9 $1,091,532 $387,372$13,908Low NOx Burner50%20.620.6$95,851$16,766$813Selective Non-CatalyticReduction (SNCR)50% 20.620.6$925,876$250,181$12,126SO2Control Cost Summarybaseline0.24 lb/mmBtu16.75 lb/hrControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $Total Annual Cost$/yrPollution ControlCost $/tonWet ESPProcess Boiler 1 & 280%11.961.5$11,808,857$2,247,725$36,558SO2 AbsorberProcess Boiler 1 & 280%11.961.5$3,935,118$1,118,879$18,198Spray Dryer and BaghouseProcess Boiler 1 & 29011.961.5$16,134,577$2,754,704$44,804DSI BaghouseProcess Boiler 1 & 25511.961.5$4,890,063$1,412,189$22,969Wet ScrubberProcess Boiler 1 & 280%14.6858.72$13,618,522$1,869,933$31,845Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsCost Summary9/6/2006Page 1 of 42Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 20: - Summary of Utility, Chemical and Supply CostsOperating Unit:Process Boiler 1 & 2Study Year2006Emission Unit Number003 & 004Stack/Vent Number003ReferenceItemUnit Cost UnitsCost Year Data SourceNotesOperating Labor50.00 $/hrEstimated industry averageMaintenance Labor60.00 $/hrEstimated industry averageElectricity0.052 $/kwh0.049 2004DOE Average Retail Price of IndustrialElectricity, 2004http://www.eia.doe.gov/emeu/aer/txt/ptb0810.htmlNatural Gas2.31 $/mscf2005Average natural gas spot price July 04 - June05, Henry La Hub.,WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gigWater0.40 $/mgal 0.76 2004Estimated industrial costcost adjusted for 3% inflationCooling Water0.28 $/mgal 0.23 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 Neutralization3.80 $/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 galWastewater Disposal Bio-Treat4.28 $/mgal 3.80 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 5.2 Chapter 1Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Costadjusted for 3% inflationSolid Waste Disposal11.48 $/ton 25.00 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 2 Chapter 2.5.5.5Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3%inflationHazardous Waste Disposal281.38 $/ton 250.00 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 2 Chapter 2.5.5.5Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3%inflationWaste Transport0.56 $/ton-mi0.50 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 6 Chapter 3Example problem. Cost adjusted for 3% inflationInternal Waste Recycle1 $/ton1.00 2000Estimated waste costUsed $1/ton to cover cost of materials movementChemicals & SuppliesLime90.00 $/tonInfo provided by Sonnek EngineeingCaustic305.21 $/ton2005Hawkins Chemical50% solution (50 Deg Be) includes deliveryUrea405 $/ton2005Hawkins Chemical50% solution of urea in water, includes deliverySoda Ash$/tonOxygen1.49 Mscf1.40 2004Industry estimatecost adjusted for 3% inflationEPA Urea179.1 $/tonAmmonia0.92 $/lbReagent #80.00 $/tonCatalyst & Replacement PartsSCR Catalyst500$/ft3Cormetech, Inc., 1/2006 bidCO Catalyst650$/ft3Vendor quote if neededCatalyst #3Catalyst #4Catalyst #5Filter Bags37.94 $/bag33.71 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 6, Chapter 1Example problem cost for 10 ft bags. Cost adjusted for 3% inflationTower Packing100$/ft3Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsUtility Chem$ Data9/6/2006Page 2 of 42Replacement PartsReplacement PartsReplacement PartsOtherSales Tax6.5% %Interest Rate7.00% %EPA Air Pollution Control Cost ManualIntroduction, Chapter 2, section 2.4.2.Social (discount) rate used as a default.Operating InformationAnnual Op. Hrs7,650 HoursEngineering EstimateUtilization Rate93%Equipment Life20 yrsEngineering EstimateDesign Capacity70 MMBtu/hrStandardized Flow Rate64,771scfm @ 32o FTemperature450Deg FMoisture Content13.3%Actual Flow Rate119,800acfmStandardized Flow Rate69,510scfm @ 68o FBased on Table 19.2 of 40 CFR 60, Appendix A, Method 19 F factor for nDry Std Flow Rate60,265dscfm @ 68o FMax EmisPollutantLb/HrPM101.90Total Particulates1.90Nitrous Oxides (NOx)11.60Sulfur Dioxide (SO2)16.800Sulfuric Acid MistFluoridesVolatile Organic Compounds (VOC) 0.99Carbon Monoxide (CO)0.00Lead (Pb)Enter this data for each emission unitEnter data for this study (applies to all units)Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsUtility Chem$ Data9/6/2006Page 3 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 21: NOx Control - Low NOx Burner

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 49,000 Purchased Equipment Total (B) 22% of control device cost (A) 59,535

Installation - Standard Costs 30% of purchased equip cost (B) 17,861 Installation - Site Specific Costs NA Installation Total 17,861 Total Direct Capital Cost, DC 77,396 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 18,456 Total Capital Investment (TCI) = DC + IC 95,851
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,866 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 13,900 Total Annual Cost (Annualized Capital Cost + Operating Cost) 16,766



### Emission Control Cost Calculation Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem PM10 1.9 6.8 6.8

- NA Total Particulates 1.9 6.8 6.8

- NA Nitrous Oxides (NOx) 11.6 41.3 50% 20.6 20.6 813 Sulfur Dioxide (SO 2 ) 16.8 59.8 59.8

- NA Sulfuric Acid Mist - - 0.0

- NA Fluorides - - 0.0

- NA Volatile Organic Compounds (VOC) 1.0 3.5 3.5

- NA Carbon Monoxide (CO) - - 0.0

- NA Lead (Pb)

- - 0.0

- NA

Notes & Assumptions 1 Burner cost scaled from MacTec Burner Estimate, March 2005 cost estimate 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx 9/6/2006 Page 4 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 21: NOx Control - Low NOx Burner

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 49,000 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 4,900 Mn Sales Taxes 6.5% of control device cost (A) 3,185 Freight 5% of control device cost (A) 2,450 Purchased Equipment Total (B) 22% 59,535

Installation Foundations & supports 8% of purchased equip cost (B) 4,763 Handling & erection 14% of purchased equip cost (B) 8,335 Electrical 4% of purchased equip cost (B) 2,381 Piping 2% of purchased equip cost (B) 1,191 Insulation 1% of purchased equip cost (B) 595 Painting 1% of purchased equip cost (B) 595 Installation Subtotal Standard Expenses 30% 17,861
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 17,861 Total Direct Capital Cost, DC 77,396
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 5,954 Construction & field expenses 5% of purchased equip cost (B) 2,977 Contractor fees 10% of purchased equip cost (B) 5,954 Start-up 2% of purchased equip cost (B) 1,191 Performance test 1% of purchased equip cost (B) 595 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 1,786 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 18,456
Total Capital Investment (TCI) = DC + IC 95,851
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 95,851



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 478 Supervisor 15% 15% of Operator Costs 72 Maintenance Maintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574 Maintenance Materials 100% of maintenance labor costs 574 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization 1,168 NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 2,866
Indirect Operating Costs Overhead 60% of total labor and material costs 1,018 Administration (2% total capital costs) 2% of total capital costs (TCI) 1,917 Property tax (1% total capital costs) 1% of total capital costs (TCI) 959 Insurance (1% total capital costs) 1% of total capital costs (TCI) 959 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 9,048 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 13,900

Total Annual Cost (Annualized Capital Cost + Operating Cost) 16,766

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx 9/6/2006 Page 5 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 21: NOx Control - Low NOx Burner

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Catalyst Equipment Life 2 years CRF 0.5531 Rep part cost per unit 650 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.940902 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 3,239 5 0.6 3.2 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 3.2

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50 $/Hr 0.01 hr/8 hr shift 10 478 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr Supervisor 15% of Op. NA 72 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr Maint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 3.2 kW-hr 22,465 1,168 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 5 Oxygen 1.49 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization 2 CO Catalyst 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 1 Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx 9/6/2006 Page 6 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 280,000 Purchased Equipment Total (B) 22% of control device cost (A) 340,200

Installation - Standard Costs 30% of purchased equip cost (B) 102,060 Installation - Site Specific Costs NA Installation Total 102,060 Total Direct Capital Cost, DC 442,260 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 105,462 Total Capital Investment (TCI) = DC + IC 547,722
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,881 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 74,628 Total Annual Cost (Annualized Capital Cost + Operating Cost) 77,510



### Emission Control Cost Calculation Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem PM10 1.9 6.8 6.8

- NA Total Particulates 1.9 6.8 6.8

- NA Nitrous Oxides (NOx) 11.6 41.3 75% 10.3 30.9 2,505 Sulfur Dioxide (SO 2 ) 16.8 59.8 59.8

- NA Sulfuric Acid Mist - - 0.0

- NA Fluorides - - 0.0

- NA Volatile Organic Compounds (VOC) 1.0 3.5 3.5

- NA Carbon Monoxide (CO) - - 0.0

- NA Lead (Pb)

- - 0.0

- NA

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx FGR 9/6/2006 Page 7 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 280,000 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 28,000 MN Sales Taxes 6.5% of control device cost (A) 18,200 Freight 5% of control device cost (A) 14,000 Purchased Equipment Total (B) 22% 340,200

Installation Foundations & supports 8% of purchased equip cost (B) 27,216 Handling & erection 14% of purchased equip cost (B) 47,628 Electrical 4% of purchased equip cost (B) 13,608 Piping 2% of purchased equip cost (B) 6,804 Insulation 1% of purchased equip cost (B) 3,402 Painting 1% of purchased equip cost (B) 3,402 Installation Subtotal Standard Expenses 30% 102,060
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 102,060 Total Direct Capital Cost, DC 442,260
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 34,020 Construction & field expenses 5% of purchased equip cost (B) 17,010 Contractor fees 10% of purchased equip cost (B) 34,020 Start-up 2% of purchased equip cost (B) 6,804 Performance test 1% of purchased equip cost (B) 3,402 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 10,206 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 105,462
Total Capital Investment (TCI) = DC + IC 547,722
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 547,722



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 478 Supervisor 15% 15% of Operator Costs 72 Maintenance Maintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574 Maintenance Materials 100% of maintenance labor costs 574 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization 1,184 NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 2,881
Indirect Operating Costs Overhead 60% of total labor and material costs 1,018 Administration (2% total capital costs) 2% of total capital costs (TCI) 10,954 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,477 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,477 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 51,701 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 74,628

Total Annual Cost (Annualized Capital Cost + Operating Cost) 77,510

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx FGR 9/6/2006 Page 8 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Catalyst Equipment Life 2 years CRF 0.5531 Rep part cost per unit 650 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.940902 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 3,239 5 0.6 3.2 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 3.2

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50 $/Hr 0.01 hr/8 hr shift 10 478 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr Supervisor 15% of Op. NA 72 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr Maint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 3.2 kW-hr 22,766 1,184 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization 2 CO Catalyst 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx FGR 9/6/2006 Page 9 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 23: NOx Control - Low NOx Burner with Overfire Air

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs [2] Direct Capital Costs 468000 Purchased Equipment (A) 558,000 Purchased Equipment Total (B) 22% of control device cost (A) 677,970

Installation - Standard Costs 30% of purchased equip cost (B) 203,391 Installation - Site Specific Costs NA Installation Total 203,391 Total Direct Capital Cost, DC 881,361 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 210,171 Total Capital Investment (TCI) = DC + IC 1,091,532
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 174,008 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 213,364 Total Annual Cost (Annualized Capital Cost + Operating Cost) 387,372



### Emission Control Cost Calculation Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem PM10 1.9 6.8 6.8

- NA Total Particulates 1.9 6.8 6.8

- NA Nitrous Oxides (NOx) 11.6 41.3 68% 13.4 27.9 13,908 Sulfur Dioxide (SO 2 ) 16.8 59.8 59.8

- NA Sulfuric Acid Mist - - 0.0

- NA Fluorides - - 0.0

- NA Volatile Organic Compounds (VOC) 1.0 3.5 3.5

- NA Carbon Monoxide (CO) - - 0.0

- NA Lead (Pb)

- - 0.0

- NA

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 2 Cost based upon Analyzing Electric Power Gneration Under the CAAA.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx OFA 9/6/2006 Page 10 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 23: NOx Control - Low NOx Burner with Overfire Air

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 558,000 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 55,800 MN Sales Taxes 6.5% of control device cost (A) 36,270 Freight 5% of control device cost (A) 27,900 Purchased Equipment Total (B) 22% 677,970

Installation Foundations & supports 8% of purchased equip cost (B) 54,238 Handling & erection 14% of purchased equip cost (B) 94,916 Electrical 4% of purchased equip cost (B) 27,119 Piping 2% of purchased equip cost (B) 13,559 Insulation 1% of purchased equip cost (B) 6,780 Painting 1% of purchased equip cost (B) 6,780 Installation Subtotal Standard Expenses 30% 203,391
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 203,391 Total Direct Capital Cost, DC 881,361
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 67,797 Construction & field expenses 5% of purchased equip cost (B) 33,899 Contractor fees 10% of purchased equip cost (B) 67,797 Start-up 2% of purchased equip cost (B) 13,559 Performance test 1% of purchased equip cost (B) 6,780 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 20,339 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 210,171
Total Capital Investment (TCI) = DC + IC 1,091,532
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,091,532



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625 Supervisor 15% 15% of Operator Costs 14,344 Maintenance Maintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574 Maintenance Materials 100% of maintenance labor costs 574 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 170 kW-hr, 7650 hr/yr, 93% utilization 62,892 NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 174,008
Indirect Operating Costs Overhead 60% of total labor and material costs 66,670 Administration (2% total capital costs) 2% of total capital costs (TCI) 21,831 Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,915 Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,915 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 103,033 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 213,364

Total Annual Cost (Annualized Capital Cost + Operating Cost) 387,372

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx OFA 9/6/2006 Page 11 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 23: NOx Control - Low NOx Burner with Overfire Air

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Catalyst Equipment Life 2 years CRF 0.5531 Rep part cost per unit 650 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 28,265 Cost adjusted for freight & sales tax Installation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.940902 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 0 19 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 0.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50 $/Hr 2.00 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr Supervisor 15% of Op. NA 14,344 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr Maint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 170.0 kW-hr 1,209,465 62,892 $/kwh, 170 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization 2 CO Catalyst 650 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Low NOx OFA 9/6/2006 Page 12 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Expected Utilization Rate 93% Temperature 450 Deg F Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) NA Purchased Equipment Total (B) 22% of control device cost (A) NA

Installation - Standard Costs 30% of purchased equip cost (B) NA Installation - Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA Total Capital Investment (TCI) = DC + IC 5,563,529
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 362,636 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 756,672 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,119,307



### Emission Control Cost Calculation Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem PM10 1.9 6.8 6.8

- NA Total Particulates 1.9 6.8 6.8

- NA Nitrous Oxides (NOx) 11.6 41.3 90% 4.1 37.1 30,139 Sulfur Dioxide (SO 2 ) 16.8 59.8 59.8

- NA Sulfuric Acid Mist - - 0.0

- NA Fluorides - - 0.0

- NA Volatile Organic Compounds (VOC) 1.0 3.5 3.5

- NA Carbon Monoxide (CO) - - 0.0

- NA Lead (Pb)

- - 0.0

- NA

Notes & Assumptions Basis for SCR control cost: 1 The SCR capital investment is from vendor estimates (Babcok Power Inc, 2005). 2 SCR catalyst quote based on information obtained from Cormetech, Inc. It is used for catalyst replacement costs. 3 The total direct and indirect operating costs are based on operation and maintenance costs in the "Pwr Plt SCR $" tab per EPA correlation of SCR costs for power plants.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls NOx SCR PwrPlt 9/6/2006 Page 13 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) NA Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (B) 22% NA

Installation Foundations & supports 8% of purchased equip cost (B) NA Handling & erection 14% of purchased equip cost (B) NA Electrical 4% of purchased equip cost (B) NA Piping 2% of purchased equip cost (B) NA Insulation 1% of purchased equip cost (B) NA Painting 1% of purchased equip cost (B) NA Installation Subtotal Standard Expenses 30% NA
Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total NA Total Direct Capital Cost, DC NA
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) NA Construction & field expenses 5% of purchased equip cost (B) NA Contractor fees 10% of purchased equip cost (B) NA Start-up 2% of purchased equip cost (B) NA Performance test 1% of purchased equip cost (B) NA Model Studies of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) NA Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA
Total Capital Investment (TCI) = DC + IC 5,563,529
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 5,425,183



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Labor NA - Maintenance Materials 100% of maintenance labor costs - Utilities, Supplies, Replacements & Waste Management NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - CO Catalyst 650.00 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 52,717 NA NA - Total Annual Direct Operating Costs 362,636
Indirect Operating Costs Overhead 60% of total labor and material costs 22,032 Administration (2% total capital costs) 2% of total capital costs (TCI) 111,271 Property tax (1% total capital costs) 1% of total capital costs (TCI) 55,635 Insurance (1% total capital costs) 1% of total capital costs (TCI) 55,635 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 512,099 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 756,672

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,119,307

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls NOx SCR PwrPlt 9/6/2006 Page 14 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Catalyst Estimate amount of catalyst required Equipment Life 3 years Vol. #1 5000 ft3 CRF 0.3811 Flow #1 359,256 acfm Basis SCR Bids for proposed 2001 Taconite Plant Rep part cost per unit 65 $/ft 3 Flow #2 119,800 acfm Amount Required 1667.3 ft 3 Vol #2 1667.3 ft3 Catalyst Cost 120,301 Cost adjusted for freight & sales tax Installation Labor 18,045 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 138,346 Zero out if no replacement parts needed Annualized Cost 52,717
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.940902 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm D P in H2O Efficiency Hp kW Blower, Thermal 119,800 19 0.6 443.9 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1 Blower, Catalytic 119,800 23 0.6 537.3 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type Catalytic (catalytic or thermal) 537.3

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr Maint Mtls 100 % of Maintenance Labor NA 0 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 537.3 kW-hr 0 0 $/kwh, 537 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 14676 scfm 0 0 $/mscf, 14,676 scfm, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization 2 CO Catalyst 650 $/ft3 0 ft 3 0 52,717 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls NOx SCR PwrPlt 9/6/2006 Page 15 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost

EPA SCR Cost Worksheet for Coal Fired Power Plants

Determine Comparable Boiler Size Based on Flue Gas Exhaust Rate stack exhaust flow scfm 69,510 Moisture Content 10% Stack exhaust flow dcfm 60,265 Coal F Factor dscf/MMBtu 10,000 Equivalent Duty MMBtu/hr 362 Est. Power Plant Efficiency 35% Watt per Btu/hr 0.29307 Equivalent Power Plant kW 37,090 Uncontrolled NOx t/yr 41 Annual Operating Hours 8,000 Uncontrolled NOx lb/MMBtu 0.029
Plant Capacity kW A 37,090 Uncontrolled NOx lb/MMBtu B 0.029 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Total Capital Cost $5,563,529
D= 75*(300,000((B/1.5)^0.05*(C/100)^0.04/A)^0.35
Plant Capacity kW A 37,090 Capital Cost $/kW D $150.00 Fixed O&M Cost, $/yr E $36,719

E = D*A*0.0066
Plant Capacity kW A 37,090 Uncontrolled NOx lb/MMBtu B 0.03 NOx Reduction Efficiency C 90 Capital Cost $/kW D $150.00 Annual Capacity Factor G 0.82 Heat Input MMBtu/hr H 6000 Variable O&M Cost $/yr F $362,636
F = G*(225(0.37*B*H*C/100*8760/2000)*1.005+0.075*D*A*((B/1.5)^0.05*(c/100)^.4)+1.45*A) Note: used worst case factor for catalyst replacement Note: Capital Cost kW is estimate from Tom Robinson @ Babcock Power Inc.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls NOx SCR PwrPlt 9/6/2006 Page 16 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 25: Selective Non-Catalytic Reduction SNCR

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Control Eff NOx in lb/MMBtu Year Direct Capital Costs EPRI Correlation, 1998 $'s 50% 0.17 1998 551,300 Purchased Equipment (A) 2005 657,319 Purchased Equipment Total (B) 0% of control device cost (A) 657,319

Installation - Standard Costs 15% of purchased equip cost (B) 118,317 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC 925,876
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 153,526 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 96,655 Total Annual Cost (Annualized Capital Cost + Operating Cost) 250,181



### Emission Control Cost Calculation Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem PM10 1.9 6.8 6.8 - NA Total Particulates 1.9 6.8 6.8

- NA Nitrous Oxides (NOx) 11.6 41.3 50% 20.6 20.6 12,126 Sulfur Dioxide (SO 2 ) 16.8 59.8 59.8

- NA Sulfuric Acid Mist - - 0.0

- NA Fluorides - - 0.0

- NA Volatile Organic Compounds (VOC) 1.0 3.5 3.5

- NA Carbon Monoxide (CO) - - 0.0

- NA Lead (Pb)

- - 0.0

- NA

Notes & Assumptions 1 Cost Estimate from EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 5 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25 6 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29 7 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 8 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21 9 No coal ash disposal cost; fuel is natural gas

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls NOx SNCR 9/6/2006 Page 17 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 25: Selective Non-Catalytic Reduction SNCR

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 657,319 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 657,319

Indirect Installation General Facilities 5% of purchased equip cost (A) 32,866 Engineering & Home Office 10% of purchased equip cost (A) 65,732 Process Contingency 5% of purchased equip cost (A) 32,866
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 131,464
Project Contingency ( C) 15% of (A + B) 118,317

Total Plant Cost D A + B + C 907,100
Allowance for Funds During Construction (E) 0 for SNCR 0
Royalty Allowance (F) 0 for SNCR 0
Pre Production Costs (G) 2% of (D+E)) 18,142
Inventory Capital Reagent Vol * $/gal 634
Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 925,876
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 925,876



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 15.00 % of Total Capital Investment 138,881 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management NA NA - Natural Gas 2.31 $/mscf, 0 scfh, 7650 hr/yr, 93% utilization 1,215 Water 0.40 $/mgal, 4 gph, 7650 hr/yr, 93% utilization 13 NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - NA NA - Urea 405.00 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 13,416 NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 153,526

Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) 0 of total capital costs (TCI) 9,259 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 87,396 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 96,655

Total Annual Cost (Annualized Capital Cost + Operating Cost) 250,181

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls NOx SNCR 9/6/2006 Page 18 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 25: Selective Non-Catalytic Reduction SNCR

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst <- Enter Equipment Name to Get Cost Equipment Life 5 years CRF 0.2439 Rep part cost per unit 500 $/ft 3 Amount Required 12 ft 3 Packing Cost 6,690 Cost adjusted for freight & sales tax Installation Labor 1,004 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost Equipment Life 2 years CRF 0.0000 Rep part cost per unit 38 $/ft 3 Amount Required 0 Cages Total Rep Parts Cost 0 Cost adjusted for freight & sales tax See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr) Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag. Annualized Cost 0

Electrical Use NOx in 0.17 lb/MMBtu kW NSR 1.12 Power 0.0

Total 0.0

Reagent Use & Other Operating Costs Urea Use NOx in 0.17 lb/MMBtu 5 lb/hr Neat Efficiency 50% 50% solution 71.0 lb/ft 3 Density 50% Solution Duty 70 MMBtu/hr 9 lb/hr 1.0 gal/hr Volume 14 day inventory 330 gal $634 Inventory Cost

Water Use 4 gal/hr Inject at 10% solution

Fuel Use 0.1 MMBtu/hr 0.1 mscfh natural gas

Ash Generation 0.6 lb/hr
Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 138,881 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 0.1 scfh 526 1,215 $/mscf, 0 scfh, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 4.5 gph 32 13 $/mgal, 4 gph, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Comp Air 0.32 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 3 Urea 405 $/ton 0.0047 ton/hr 33 13,416 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization 1 SCR Catalyst 500 $/ft3 0 ft 3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls NOx SNCR 9/6/2006 Page 19 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 26: SO2 Control - Wet ESP

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs (1) Purchased Equipment (A) 2005 5,519,073 2,687,838 Purchased Equipment Total (B) 22% of control device cost (A) 3,265,724

Installation - Standard Costs 69% of purchased equip cost (B) 2,253,349 Installation - Site Specific Costs 0 Installation Total 2,253,349 Total Direct Capital Cost, DC 5,519,073 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,861,462 Total Capital Investment (TCI) = DC + IC 11,808,857
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 742,986 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,504,739 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,247,725



### Emission Control Cost Calculation Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost (5) Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem PM10 8.3 1.5 0.021 5.3 3.0 758,310 Total Particulates 8.3 1.5 0.021 5.3 3.0 758,310 Nitrous Oxides (NOx) 50.9

- 50.9 - NA Sulfur Dioxide (SO 2 

### ) 73.4 3.4 0.048 11.9 61.5 36,558

Notes & Assumptions 1 Total Direct Capital Cost Cost Estimated, 19% as compared to dry ESP cost. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 3 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3 4 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3 5 High control cost is due to the small additional decrease in emissions as compared to existing controls. 6 CUECost Workbook Version 1.0, USEPA Document Page 2.

Notes to User 1) Enter Data in Blue Highlighted Cells Throughout Worksheet 2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell 2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H 2b) If using concentration, enter concentration data in coluND Fand units in coluND H 3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls SO2 WESP 9/6/2006 Page 20 of 42

### 4) See comments in cell V88 regarding selection of reagents, catalysts and supplies

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls SO2 WESP 9/6/2006 Page 21 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 26: SO2 Control - Wet ESP

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 2,687,838 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 268,784 MN Sales Taxes 6.5% of control device cost (A) 174,709 Freight 5% of control device cost (A) 134,392 Purchased Equipment Total (B) 22% 3,265,724

Installation Foundations & supports 4% of purchased equip cost (B) 130,629 Handling & erection 50% of purchased equip cost (B) 1,632,862 Electrical 8% of purchased equip cost (B) 261,258 Piping 3% of purchased equip cost (B) 97,972 Insulation 2% of purchased equip cost (B) 65,314 Painting 2% of purchased equip cost (B) 65,314 Installation Subtotal Standard Expenses 69% 2,253,349

Installation Total 2,253,349 Total Direct Capital Cost, DC 5,519,073
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 653,145 Construction & field expenses 20% of purchased equip cost (B) 653,145 Contractor fees 10% of purchased equip cost (B) 326,572 Start-up 1% of purchased equip cost (B) 32,657 Performance test 1% of purchased equip cost (B) 32,657 Model Studies 2% of purchased equip cost (B) 65,314 Contingencies 3% of purchased equip cost (B) 97,972 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,861,462

7,380,535 Retrofit TCI (TCI*1.6) (6) 11,808,857

Total Capital Investment (TCI) = DC + IC Site Preparation, as required site preparation and foundations 0 Buildings, as required structural steel 0 Site Specific - Other Replacement Power - One 14 day outage [8] 0 Total Site Specific Costs 0 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 11,808,857



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 47,813 Supervisor 48% % of Operator Costs. 22,950 Maintenance Maintenance Labor (3) 66,249 ft2 grid area, 0.8 $/ft2 of grid area 54,656 Maintenance Materials (4) 1 1% of purchased equipment cost 32,657 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 228 kW-hr, 7650 hr/yr, 93% utilization 84,287 NA NA - Water 0.40 $/mgal, 24 gpm, 7650 hr/yr, 93% utilization 4,091 NA NA - NA NA - NA NA - NA NA - SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77 NA NA - NA NA - NA NA - NA NA - Caustic 305.21 $/ton, 227 lb/hr, 7650 hr/yr, 93% utilization 246,456 NA NA - Lost Revenue - Fly Ash NA 250,000 NA NA - Total Annual Direct Operating Costs 742,986 Indirect Operating Costs

Overhead 60% of total labor and material costs 94,845 Administration (2% total capital costs) 2% of total capital costs (TCI) 147,611 Property tax (1% total capital costs) 1% of total capital costs (TCI) 73,805 1 Insurance (1% total capital costs) 1% of total capital costs (TCI) 73,805 2 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,114,673 5 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,504,739 1 1
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,247,725

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls SO2 WESP 9/6/2006 Page 22 of 42

### Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

SO2 WESP 9/6/2006 Page 23 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 26: SO2 Control - Wet ESP

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3 

### Amount Required 0 ft 3 

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

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.94090199 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use
Flow acfm **∆** P in H2O 

### Efficiency Hp kW Blower Baghouse & ESP 

### 119,800 4.48 97.1 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.46 Liq flow Liquid SPGR **∆** P ft H2O 

### Efficiency Hp kW WESP Pump 120 gpm 1.000 40 0.5 1.8 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.47 WESP H2O WW Disch 

### 24 gpm 1.000 40 0.5 0.4 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.47

SCA Factor 553 ft 2 

### /1000 acfm
ESP Grid 66,249 ft 2 

### 1.94E-03 kW/ft 2 

### 128.5 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 227.8

Reagent Use & Other Operating Costs WESP Pump 23,960 acfm 5 gpm/kacfm 120 gpm EPA Cost Cont Manual 6th ed Section 6 Chapter 3.4.1.9 WESP Water Makeup Rate/WW Disch 

### 20% of circulating water rate = 24 gpm

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 1.0 hr/8 hr shift 956 47,813 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr Supervisor 48% of Operator Costs. NA 22,950 % of Operator Costs. Maintenance Maint Labor 66,249 ft2 grid area 0.825 $/ft 2 

### of grid area 54,656 ft2 grid area, 0.8 $/ft2 of grid area Maint Mtls 1 % of purchased equipment cost NA 32,657 1% of purchased equipment cost Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 227.8 kW-hr 1,620,903 84,287 $/kwh, 228 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 24.0 gpm 10,228 4,091 $/mgal, 24 gpm, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Comp Air 0.32 $/mscf 0 kscfm 0 0 $/mscf, 0 kscfm, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 Mi 0 0 $/ton-mi, 0 Mi, 7650 hr/yr, 93% utilization PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost Lime 90.0 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization Caustic 305.21 $/ton 227.0 lb/hr 807 246,456 $/ton, 227 lb/hr, 7650 hr/yr, 93% utilization Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 

### 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls SO2 WESP 9/6/2006 Page 24 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 27: SO2 Absorber

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs (1) 2002 [1] 1,908,056 Purchased Equipment (A) 2005 2,274,990 1,012,119 Purchased Equipment Total (B) 22% of control device cost (A) 1,229,724

Installation - Standard Costs 85% of purchased equip cost (B) 1,045,266 Installation - Site Specific Costs 0 Installation Total 1,045,266 Total Direct Capital Cost, DC 2,274,990 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 184,459 Total Capital Investment (TCI) = DC + IC 3,935,118
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 598,134 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 520,746 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,118,879



### Emission Control Cost Calculation Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem PM10 8.3

- 8.3 - NA Total Particulates 8.3

- 8.3 - NA Nitrous Oxides (NOx) 50.9

- 50.9 - NA Sulfur Dioxide (SO 2 

### ) 73.4 3.4 0.05 11.9 61.5 18,198

Notes & Assumptions 1 Original estimate was from Durr. Use 0.6 Powerlaw 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.

Notes to User 1) Enter Data in Blue Highlighted Cells Throughout Worksheet 2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell 2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H 2b) If using concentration, enter concentration data in coluND Fand units in coluND H 3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls SO2 Absorber 9/6/2006 Page 25 of 42

### 4) See comments in cell V88 regarding selection of reagents, catalysts and supplies

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls SO2 Absorber 9/6/2006 Page 26 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 27: SO2 Absorber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 1,012,119 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 101,212 MN Sales Taxes 6.5% of control device cost (A) 65,788 Freight 5% of control device cost (A) 50,606 Purchased Equipment Total (B) 22% 1,229,724

Installation Foundations & supports 12% of purchased equip cost (B) 147,567 Handling & erection 40% of purchased equip cost (B) 491,890 Electrical 1% of purchased equip cost (B) 12,297 Piping 30% of purchased equip cost (B) 368,917 Insulation 1% of purchased equip cost (B) 12,297 Painting 1% of purchased equip cost (B) 12,297 Installation Subtotal Standard Expenses 85% 1,045,266

Installation Total 1,045,266 Total Direct Capital Cost, DC 2,274,990
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 61,486 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 61,486 Start-up 1% of purchased equip cost (B) 12,297 Performance test 1% of purchased equip cost (B) 12,297 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 36,892 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 184,459
Total Capital Investment (TCI) = DC + IC 2,459,448 Retrofit TCI (TCI*1.6) (5) 3,935,118

Site Preparation, as required site preparation and foundations 0 Buildings, as required structural steel 0 Site Specific - Other Replacement Power - One 14 day outage [8] 0 Total Site Specific Costs 0

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 3,935,118



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr 23,906 Supervisor 15% 15% of Operator Costs 3,586 Maintenance Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr 28,688 Maintenance Materials 100% of maintenance labor costs 28,688 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 246 kW-hr, 7650 hr/yr, 93% utilization 91,145 NA NA - Water 0.40 $/mgal, 112 gpm, 7650 hr/yr, 93% utilization 19,194 NA NA - NA NA - WW Treat Neutralization 3.80 $/mgal, 91 gpm, 7650 hr/yr, 93% utilization 147,690 NA NA - SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77 NA NA - NA NA - NA NA - Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161 NA NA - NA NA - Lost Revenue - Fly Ash NA 250,000 NA NA - Total Annual Direct Operating Costs 598,134
Indirect Operating Costs Overhead 60% of total labor and material costs 50,920 Administration (2% total capital costs) 2% of total capital costs (TCI) 49,189 Property tax (1% total capital costs) 1% of total capital costs (TCI) 24,594 1 Insurance (1% total capital costs) 1% of total capital costs (TCI) 24,594 2 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 371,447 5 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 520,746 1 1
Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,118,879
See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls SO2 Absorber 9/6/2006 Page 27 of 42

### Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

SO2 Absorber 9/6/2006 Page 28 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 27: SO2 Absorber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3 

### Amount Required 0 ft 3 

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

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 37.94 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use
Flow acfm ∆ P in H2O 

### Efficiency Hp kW Blower, Scrubber 119,800 8.55 0.7

- 171.2 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 4,552 gpm 1 60 0.7

- 73.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 

### 112 gpm 1 60 0.7

- 1.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 246.4

Reagent Use & Other Operating Costs Caustic Use 16.75 lb/hr SO2 2.50 lb NaOH/lb SO2 

### 41.88 lb/hr Caustic Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 

### 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio Liquid/Gas ratio (2) 38.0 * L/G = Gal/1,000 acf Circulating Water Rate 4,552 gpm Water Makeup Rate/WW Disch = (3) 2.0% of circulating water rate + evap. loss = 112 gpm Evaopration Loss = (4) 21.36 gpm

Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.05 NOx 50.90 0.166071429 11.625 SO2 73.40 0.239285714 16.75

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 478 23,906 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr Supervisor 15% of Op. NA 3,586 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 478 28,688 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr Maint Mtls 100 % of Maintenance Labor NA 28,688 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 246.4 kW-hr 1,752,797 91,145 $/kwh, 246 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 112.4 gpm 47,984 19,194 $/mgal, 112 gpm, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Comp Air 0.32 $/mscf 0 kscfm 0 0 $/mscf, 0 kscfm, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 91.0 gpm 38,866 147,690 $/mgal, 91 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 

### 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls SO2 Absorber 9/6/2006 Page 29 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 28: SO2 Control - Spray Dryer and Baghouse

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs (1) 2002 [1] 7,786,400 Purchased Equipment (A) 2005 9,283,785 4,391,365 Purchased Equipment Total (B) 22% of control device cost (A) 5,335,508

Installation - Standard Costs 74% of purchased equip cost (B) 3,948,276 Installation - Site Specific Costs 0 Installation Total 3,948,276 Total Direct Capital Cost, DC 9,283,785 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 800,326 Total Capital Investment (TCI) = DC + IC (5) 16,134,577
Operating Costs (2) Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 693,518 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,061,186 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,754,704



### Emission Control Cost Calculation Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem PM10 8.3

- 8.3 - NA Total Particulates 8.3

- 8.3 - NA Nitrous Oxides (NOx) 50.9

- 50.9 - NA Sulfur Dioxide (SO 2 

### ) 73.4 3.4 0.05 11.9 61.5 44,804

Notes & Assumptions 1 Stone and Webster 2002 total direct installed cost estimate adjusted for inflation 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1.5.1.8 4 Bag replacement at 10 min/bag EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min per bag. 5 Bag replacement costs for baghouse need to be updated. Bag costs from EPA example calculations were used. 6 Dry scrubbing SO2 costs include addition of a baghouse. Assumed that the existing baghouse could not handle additional loading. 7 CUECost Workbook Version 1.0, USEPA Document Page 2.

Notes to User 1) Enter Data in Blue Highlighted Cells Throughout Worksheet 2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell 2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H 2b) If using concentration, enter concentration data in coluND Fand units in coluND H 3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Spray Dry Baghouse 9/6/2006 Page 30 of 42

### 4) See comments in cell V88 regarding selection of reagents, catalysts and supplies

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Spray Dry Baghouse 9/6/2006 Page 31 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 28: SO2 Control - Spray Dryer and Baghouse

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 4,391,365 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 439,136 MN Sales Taxes 6.5% of control device cost (A) 285,439 Freight 5% of control device cost (A) 219,568 Purchased Equipment Total (B) 22% 5,335,508

Installation Foundations & supports 4% of purchased equip cost (B) 213,420 Handling & erection 50% of purchased equip cost (B) 2,667,754 Electrical 8% of purchased equip cost (B) 426,841 Piping 1% of purchased equip cost (B) 53,355 Insulation 7% of purchased equip cost (B) 373,486 Painting 4% of purchased equip cost (B) 213,420 Installation Subtotal Standard Expenses 74% 3,948,276

Installation Total 3,948,276 Total Direct Capital Cost, DC 9,283,785
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 266,775 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 266,775 Start-up 1% of purchased equip cost (B) 53,355 Performance test 1% of purchased equip cost (B) 53,355 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 160,065 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 800,326

Total Capital Investment (TCI) = DC + IC 10,084,111 Retrofit TCI (TCI*1.6) (7) 16,134,577

Site Preparation, as required site preparation and foundations 0 Buildings, as required structural steel 0 Site Specific - Other Replacement Power - One 14 day outage [8] 0 Total Site Specific Costs 0
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 16,134,577



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625 Supervisor 15% 15% of Operator Costs 14,344 Maintenance Maintenance Labor 60.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 57,375 Maintenance Materials 100% of maintenance labor costs 57,375 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization 80,220 NA NA - Water 0.40 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization 24,000 NA NA - Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization 32,391 NA NA - NA NA - SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77 NA NA - NA NA - NA NA - Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161 NA NA - Lost Revenue - Fly Ash NA 250,000 NA NA - Filter Bags 37.94 $/bag, 0 bags, 7650 hr/yr, 93% utilization 76,951 Total Annual Direct Operating Costs 693,518
Indirect Operating Costs Overhead 60% of total labor and material costs 134,831 Administration (2% total capital costs) 2% of total capital costs (TCI) 201,682 Property tax (1% total capital costs) 1% of total capital costs (TCI) 100,841 Insurance (1% total capital costs) 1% of total capital costs (TCI) 100,841 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,522,990 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,061,186
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,754,704

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Spray Dry Baghouse 9/6/2006 Page 32 of 42

### Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

Spray Dry Baghouse 9/6/2006 Page 33 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 28: SO2 Control - Spray Dryer and Baghouse

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalsyt: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3 

### Amount Required 0 ft 3 

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

Replacement Parts & Equipment: Filter bags & cages (4) Equipment Life 4 years CRF 0.2952 Rep part cost per unit 38 $/bag Amount Required 4410 Total Rep Parts Cost 186,561 Cost adjusted for freight & sales tax Installation Labor 74,088 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4 Total Installed Cost 260,649 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag. Annualized Cost 76,951

Electrical Use
Flow acfm **∆** P in H2O 

### Efficiency Hp kW Blower, Baghouse 119,800 10 216.8 Baghouse Shaker 0.0 Gross fabric area ft 2 

### 0 EPA Cost Cont Manual 6th ed Section 6 Chapter 1 Eq 1.14 Other Other Other Other Other Total 216.8

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Gross BH Filter Area 0 ft 2 

### Cages 0 ft long 0 in dia 0.00 area/cage ft 2 

### 0.000 $/cage Bags 0 $/ft2 of fabric 0.00 $/bag H2O Use (1) 140.56 gpm 0.000 Total Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 

### 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio

Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.05 NOx 50.90 0.166071429 11.625 SO2 73.40 0.239285714 16.75

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr Supervisor 15% of Op. NA 14,344 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 1.0 hr/8 hr shift 956 57,375 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr Maint Mtls 100 % of Maintenance Labor NA 57,375 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 216.8 kW-hr 1,542,694 80,220 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 140.6 gpm 60,000 24,000 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization (3) Comp Air 0.32 $/mscf 2 scfm/kacfm 102,278 32,391 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost 1 Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization 5 Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization 1 SCR Catalyst 500 $/ft3 0 ft 3 

### 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 1 Filter Bags 37.940902 $/bag 0 bags NA 76,951 $/bag, 0 bags, 7650 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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Spray Dry Baghouse 9/6/2006 Page 34 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 29: SO2 Control - Dry Sorbent Injection and Baghouse

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs (1) 1997 2,359,900 Purchased Equipment (A) 2005 [6] 2,813,727 1,330,934 Purchased Equipment Total (B) 22% of control device cost (A) 1,617,084

Installation - Standard Costs 74% of purchased equip cost (B) 1,196,642 Installation - Site Specific Costs 0 Installation Total 1,196,642 Total Direct Capital Cost, DC 2,813,727 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 242,563 Total Capital Investment (TCI) = DC + IC (5) 4,890,063
Operating Costs (2) Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 693,518 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 718,670 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,412,189



### Emission Control Cost Calculation Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem PM10 8.3

- 8.3 - NA Total Particulates 8.3

- 8.3 - NA Nitrous Oxides (NOx) 50.9

- 50.9 - NA Sulfur Dioxide (SO 2 

### ) 73.4 3.4 0.05 11.9 61.5 22,969

Notes & Assumptions 1 Total Direct Capital Cost Cost Estimated using the Integrated Air Pollution Control Sytem Program Version 5a, EPA May 1999 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1.5.1.8 4 Bag replacement at 10 min/bag EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min per bag. 5 Dry scrubbing SO2 costs include addition of a baghouse. Assumed that the existing Ebaghouse could not handle additional loading. 6 Stone and Webster 2002 total direct installed cost estimate adjusted for inflation adjusted for costs already included 7 CUECost Workbook Version 1.0, USEPA Document Page 2.

Notes to User 1) Enter Data in Blue Highlighted Cells Throughout Worksheet 2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell 2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H 2b) If using concentration, enter concentration data in coluND Fand units in coluND H 3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls DSI Baghouse 9/6/2006 Page 35 of 42

### 4) See comments in cell V88 regarding selection of reagents, catalysts and supplies

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls DSI Baghouse 9/6/2006 Page 36 of 42

## Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 29: SO2 Control - Dry Sorbent Injection and Baghouse

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 1,330,934 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 133,093 MN Sales Taxes 6.5% of control device cost (A) 86,511 Freight 5% of control device cost (A) 66,547 Purchased Equipment Total (B) 22% 1,617,084

Installation Foundations & supports 4% of purchased equip cost (B) 64,683 Handling & erection 50% of purchased equip cost (B) 808,542 Electrical 8% of purchased equip cost (B) 129,367 Piping 1% of purchased equip cost (B) 16,171 Insulation 7% of purchased equip cost (B) 113,196 Painting 4% of purchased equip cost (B) 64,683 Installation Subtotal Standard Expenses 74% 1,196,642

Installation Total 1,196,642 Total Direct Capital Cost, DC (6) 2,813,727
Indirect Capital Costs Engineering, supervision [6] 5% of purchased equip cost (B) 80,854 Construction & field expenses [6] 0% of purchased equip cost (B) 0 Contractor fees [6] 5% of purchased equip cost (B) 80,854 Start-up 1% of purchased equip cost (B) 16,171 Performance test 1% of purchased equip cost (B) 16,171 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 48,513 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 242,563

Total Capital Investment (TCI) = DC + IC 3,056,290 Retrofit TCI (TCI*1.6) (7) 4,890,063

Site Preparation, as required site preparation and foundations 0 Buildings, as required structural steel 0 Site Specific - Other Replacement Power - One 14 day outage [8] 0 Total Site Specific Costs 0
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 4,890,063



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625 Supervisor 15% 15% of Operator Costs 14,344 Maintenance Maintenance Labor 60.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 57,375 Maintenance Materials 100% of maintenance labor costs 57,375 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization 80,220 NA NA - Water 0.40 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization 24,000 NA NA - Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization 32,391 NA NA - NA NA - SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77 NA NA - NA NA - NA NA - Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161 (3) NA NA - Lost Revenue - Fly Ash NA 250,000 NA NA - Filter Bags 37.94 $/bag, 0 bags, 7650 hr/yr, 93% utilization 76,951 Total Annual Direct Operating Costs 693,518
Indirect Operating Costs 1 Overhead 60% of total labor and material costs 134,831 2 Administration (2% total capital costs) 2% of total capital costs (TCI) 61,126 5 Property tax (1% total capital costs) 1% of total capital costs (TCI) 30,563 1 Insurance (1% total capital costs) 1% of total capital costs (TCI) 30,563 1 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 461,587 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 718,670 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,412,189 See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls DSI Baghouse 9/6/2006 Page 37 of 42

### Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

DSI Baghouse 9/6/2006 Page 38 of 42

## Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 29: SO2 Control - Dry Sorbent Injection and Baghouse

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalsyt: Equipment Life 5 years CRF 0.0000 Rep part cost per unit 500 $/ft 3 

### Amount Required 0 ft 3 

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

Replacement Parts & Equipment: Filter bags & cages (4) Equipment Life 4 years CRF 0.2952 Rep part cost per unit 38 $/bag Amount Required 4410 Total Rep Parts Cost 186,561 Cost adjusted for freight & sales tax Installation Labor 74,088 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4 Total Installed Cost 260,649 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag. Annualized Cost 76,951

Electrical Use
Flow acfm **∆** P in H2O 

### Efficiency Hp kW Blower, Baghouse 119,800 10 216.8 Baghouse Shaker 0.0 Gross fabric area ft 2 

### 0 EPA Cost Cont Manual 6th ed Section 6 Chapter 1 Eq 1.14 Other Other Other Other Other Total 216.8

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs Gross BH Filter Area 0 ft 2 

### Cages 0 ft long 5 in dia 0.00 area/cage ft 2 

### 0.000 $/cage Bags 0 $/ft2 of fabric 0.00 $/bag H2O Use (6) 140.56 gpm 0.000 Total Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 

### 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio

Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.05 NOx 50.90 0.166071429 11.625 SO2 73.40 0.239285714 16.75

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr Supervisor 15% of Op. NA 14,344 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 1.0 hr/8 hr shift 956 57,375 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr Maint Mtls 100 % of Maintenance Labor NA 57,375 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 216.8 kW-hr 1,542,694 80,220 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization Water 0.40 $/mgal 140.6 gpm 60,000 24,000 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization Comp Air 0.32 $/mscf 2 scfm/kacfm 102,278 32,391 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization Oxygen 1.49 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization SCR Catalyst 500 $/ft3 0 ft 3 

### 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization Filter Bags 37.94 $/bag 0 bags NA 76,951 $/bag, 0 bags, 7650 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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls DSI Baghouse 9/6/2006 Page 39 of 42

# Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 30: SO x 

# Control - Wet Scrubber

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Standardized Flow Rate 64,771 scfm @ 32o F Expected Utilization Rate 93% Temperature 450 Deg F Expected Annual Hours of Operation 7,650 0 Moisture Content 13% 0 Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Expected Equipment Life 20 0 Standardized Flow Rate 69,510 scfm @ 68o F Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 1,908,056 Purchased Equipment Total (B) 22% of control device cost (A) 2,318,288

Installation - Standard Costs 85% of purchased equip cost (B) 1,970,545 Installation - Site Specific Costs 6,200,000 Installation Total 1,970,545 Total Direct Capital Cost, DC 4,288,833 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 347,743 Total Capital Investment (TCI) = DC + IC 13,618,522
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 348,057 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,521,875 Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,869,933

Actual 

### Emission Control Cost Calculation Emis Emissions Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 11.6 50.9 0% 50.9 - NA Sulfur Dioxide (SO 2 

### ) 16.8 73.4

80% 14.7 58.7 31,845

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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Wet Scrubber 9/6/2006 Page 40 of 42

# Northshore Process Boiler BART Report - Appendix A Emission Control Cost Analysis Table 30: SOx Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,908,056 Instrumentation 10% of control device cost (A) 190,806 MN Sales Taxes 6.5% of control device cost (A) 124,024 Freight 5% of control device cost (A) 95,403 Purchased Equipment Total (B) 22% 2,318,288

Installation Foundations & supports 12% of purchased equip cost (B) 278,195 Handling & erection 40% of purchased equip cost (B) 927,315 Electrical 1% of purchased equip cost (B) 23,183 Piping 30% of purchased equip cost (B) 695,486 Insulation 1% of purchased equip cost (B) 23,183 Painting 1% of purchased equip cost (B) 23,183 Installation Subtotal Standard Expenses 85% 1,970,545
Total Direct Capital Cost, DC 4,288,833

Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 115,914 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 115,914 Start-up 1% of purchased equip cost (B) 23,183 Performance test 1% of purchased equip cost (B) 23,183 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 69,549 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 347,743
Total Capital Investment (TCI) = DC + IC 4,636,576 Retrofit multiplier 5 

### 60% of TCI 2,781,946

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 13,618,522



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 23,906 Supervisor 15% 15% of Operator Costs 3,586 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 28,688 Maintenance Materials 100% of maintenance labor costs 28,688 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 246 kW-hr, Annual Operating Hours, 93% utilization 91,145 Water 0.40 $/kgal, 112 gpm, Annual Operating Hours, 93% utilization 19,194 WW Treat Neutralization 3.80 $/kgal, 91 gpm, Annual Operating Hours, 93% utilization 147,690 Lime 90.00 $/ton, 16 lb/hr, Annual Operating Hours, 93% utilization 5,161 Total Annual Direct Operating Costs 348,057
Indirect Operating Costs Overhead 60% of total labor and material costs 50,920 Administration (2% total capital costs) 2% of total capital costs (TCI) 92,732 Property tax (1% total capital costs) 1% of total capital costs (TCI) 46,366 Insurance (1% total capital costs) 1% of total capital costs (TCI) 46,366 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,285,492 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,521,875

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,869,933

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Wet Scrubber 9/6/2006 Page 41 of 42

# Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis Table 30: SOx 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 119,800 8.55 0.7

- 171.2 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 4,552 gpm 1 60 0.7

- 73.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 

### 112 gpm 1 60 0.7

- 1.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 246.4

Reagent Use & Other Operating Costs Caustic Use 16.75 lb/hr SO2 2.50 lb NaOH/lb SO2 

### 41.88 lb/hr Caustic Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 

### 16.12 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 

### 4,552 gpm Water Makeup Rate/WW Disch 3 

### = 2.0% of circulating water rate + evap. loss = 112 gpm Evaopration Loss 4 

### = 21.36 gpm

Operating Cost Calculations Annual hours of operation: 7,650 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 478 23,906 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Supervisor 15% of Op. NA 3,586 15% of Operator Costs Maintenance Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 478 28,688 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, Maint Mtls 100 % of Maintenance Labor NA 28,688 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.052 $/kwh 246.4 kW-hr 1,752,797 91,145 $/kwh, 246 kW-hr, Annual Operating Hours, 93% utilization Water 0.40 $/kgal 112.4 gpm 47,984 19,194 $/kgal, 112 gpm, Annual Operating Hours, 93% utilization WW Treat Neutralization 3.80 $/kgal 91.0 gpm 38,866 147,690 $/kgal, 91 gpm, Annual Operating Hours, 93% utilization Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, Annual Operating Hours, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls Wet Scrubber 9/6/2006 Page 42 of 42

# 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 Northshore Mining Company (NMC) 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 Technology (BART) Modeling Protocol to Determine Sources Subject-to-Bart in the State of Minnesota. 4 

# 40 CFR 51, Appendix Y. 5 

# MPCA, March 2006, Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-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. There were no post-BART scenarios to be modeled.

Table 4-1 describes the pre-BART model input parameters. There were no post-BART scenarios to be
modeled.



# Modeled Results

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for the pre-BART emission scenario. 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 4-2.N

Barr Footer: Date: 7/5/2006 2:27:05 PM File: I:\projects\23\00\Minntac.mxd User: ams100 0MetersNorthshore Aerial PhotoTaconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This 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?CommentsBasic PrincipleCombustion Controls1 Overfire Air (OFA)YN------NOx 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 ---Mixes flue gas with combustion air which reduces oxygen content andtherefore reduces flame temperature3 Low-NOx Burners Y YY(preheatburners)Y(preheatburners)Higher 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---Need 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------Need high O2for process requirementsand product qualityReduces oxygen content in flue gas and reduces flame temperature6Burners out of Service(BOOS)Y N --- ---Need 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------ Power 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------Kiln 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---------Power 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)decrease amount of fuel required to make an acceptable product11 Coal DryingYN------ Applies 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 --- --- --- Check on status of researchReduce flame temperature and energy requirementsTaconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This 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?CommentsBasic Principle13 Ported KilnsYYY(grate-kilnsonly)N(Metso saysno NOximprovement)Applicable to grate kilns.Provides additional oxygen for pellet oxidation which reduces the overallenergy use of the kiln14 Combustion Zone Cooling YN------ Boiler technologyCooling of the primary flame zone by heat transfer to surroundingsurfaces15 Alternate FuelsYYY(for furnacescapable ofmultiple fuels)Y(not requiredby BART)Requires 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--------- Research levelA small fraction of the combustion air is replaced with oxygen.17 Preheat Combustion N--------- Research 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-ROTAMIXYN------Can'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------Optimization of combustion20 Parametric Monitoring YN------Optimization of combustion38Catalyst Injection(EPS Technologies)N--------- Research 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)YN------For 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®Y N --- --- Used for higher flue gas concentrationsUtilizes an oxidizing agent such as ozone to oxidize various pollutantsincluding NOxTaconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This 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?CommentsBasic Principle23Low Temperature Oxidation(LTO) - LoTOxY N --- ---Has 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)Y Y YYNeed 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 SCR Y N --- --- Clean side only26Selective Non-CatalyticReduction (SNCR)Y N --- ---Can'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--------- Still in research stages.Use of char (activated carbon) to adsorb oxides of nitrogen28 AbsorptionYN------ Similar to TriNOxUse of water, hydroxide and carbonate solutions, sulfuric acid, organicsolutions, molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.29OxidizerYN------ Redundant to regenerative SCRGas stream is sent through the regenerative, recuperative, catalytic ordirect fired oxidizer where pollutants are heated to a combustion point anddestroyed.30 SNOX N --- ------ Early 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---------Technology 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.Taconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This 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?CommentsBasic Principle32 Electron (E-Beam) Process N---------No 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---------Similar 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.34 NOXSON---------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---------Absorption 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--------- Research Level37 BiofiltersYN------ Not 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--------- Research 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.htmTaconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This 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?CommentsBasic Principle2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART ReportsTaconite BART AnalysisSO2 ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This 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?CommentsBasic Principle1Wet Scrubbing (HighEfficiency)YYYYAbsorption and reaction using an alkaline reagent to produce a solid compound2Wet Scrubbing (LowEfficiency)YYYYAbsorption and reaction using an alkaline reagent to produce a solid compound3Wet Walled ElectrostaticPrecipitator (WWESP)YYYYSuspended particles are separated from the flue gas stream, attracted to plates, andcollected in hoppers4 Dry sorbent injectionYYYNPulverized 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 YNLime 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)Natural gas is base caseUse a fuel with lower sulfur content.7 Load ReductionN---------Power plant technologyThis is a strategy to reduce load on a power plant by reducing the electrical demandthrought efficiency projects.8 Energy Efficiency ProjectsYYY(for largeprojects likeheat-recoup)Y(for largeprojects likeheat-recoup)decrease amount of fuel required to make an acceptable product9Coal DryingYN------Applies 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---------Research 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---------Research levelAn aqueous solution of proprietary diamine captures SO2from the feed gas in acountercurrent absorption tower. The rich solvent is regenerated by steam stripping,giving a byproduct of pure, water saturated SO2gas and lean solvent for recyclingto the absorber.12 Pahlman ProcessN --- --- ---Research 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.Taconite BART AnalysisSO2 ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This 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?CommentsBasic Principle13 SOx-NOx-Rox-BoxN --- --- ---Technology 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 --- --- ---No 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.15 Electrocatalytic OxidationN --- --- ---Similar to cold plasma. Will keep watch foravailability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen dioxide(NO2), sulfuric acid, and mercuric oxide respectively using non-thermal plasma.On recent project, the vender was doing final trials on full-scale applications.16 NOXSON --- --- ---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 --- --- ---Absorption 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 --- --- ---Early 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 --- --- ---Research 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 ReportsAppendix EClean Air Interstate Rule (CAIR)Cost-Effective air pollution Controls9/1/2006CommentsReferenceRegulatory Body/RuleSO2NOxSO2NOxBART100 to 1000100 to 100070 FR 39135BART281 to 129670 FR 39135 Table 3BART91970 FR 39133BARTGuidelines disparagingly reference "thousands ofdollars per ton" in commenting on the need toexceed MACT and its general unreasonableness.70_FR_25210_CAIR.pdfCAIR1300Estimated Marginal cost 2009BART(proposed rule) 200-1000BART proposed lists this as values for 90-95%SO2 control, which is still assumed, or .1 to .15lb/MMBtu. Dropped from final to give statesflexibility to require more. Says for scrubbers,bypasses aren't BART, only 100% scrubbing isBART.BART(proposed rule)0.2 lb/MMBtu for NOx is assumed reasonble.Recognizes that some sources may need SCR toget this level. For those, state discretion of the thecost vs. visibility value is necessary.CAIR(using IPM)10001500CAIR ( 2009 in 1999$)9002400CAIR ( 2015 in 1999$)18003000CAIR (depending on Nat'lemissions)1200 - 3000 1400- 2100This was modeled with TRUM (TechnologlyRetrofitting Updating Model) to develop themarginal values.Kammer_EPA_Decision.docKammer Decisionover 1000 over 1000LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU200-500 200-1500Bowers_vs_SWAPCA.txtBowers vs SWAPCA30030010001000954-1134 was ruled too much, in favor of 256-310for SO2. This did consider incremental value.Sections XVII to XIXWRAP3000EPA - Referenced by WrapReferences EPA-600S\7-90-018. Low is<$500/ton, Moderate is $500-3000/ton, High isover $3000/tonWRAP_Trading_program_methodology.pdfAvg. Expected Values ($/ton) Limiting/Marginal values ($/ton)MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdfY:\23\00 MN Taconite BART (2006)\Facility BART Reports\HTC\Appendix E - Table of Costs_per_ton.xlsAppendix FNorthshore Process Boilers BART AnalysisNOx ControlAvailable and Applicable ReviewReference(s)Revised: June 8, 2006

Reference No. 1NOxPollution ControlTechnologyAvailable? Applicable? MPCA Taconite BART Report AWMA Journal 9/05 Other 2CommentsBasic PrincipleCombustion Controls1 Overfire Air (OFA) Yes Yesx xCombustion air is separated into primary and secondary flow sections to achievecomplete burnout and to encourage the formation of N2rather than NOx2External Flue GasRecirculation (EFGR)Yes Yesx xMixes flue gas with combustion air which reduces oxygen content and thereforereduces flame temperature3 Low-NOx Burners Yes Yesx x xBurners are designed to reduce NOx formation through restriction of oxygen,flame temperature, and/or residence time4Induced Flue GasRecirculation BurnersYes Yesx x xNeed to be upfired. Needconvective loop to get gasrecirculatedDraws flue gas to dilute the fuel in order to reduce the flame temperature5 Low Excess Air Yes YesxReduces production Reduces oxygen content in flue gas and reduces flame temperature6Burners out of Service(BOOS)Yes NoxNeed capacity of allburners for worst casescenarioShut off the fuel flow from one burner or more to create fuel rich and fuel leanzones7 Fuel BiasingYes NoxCombustion is staged by diverting fuel from the upper level burners to the lowerones or from the center to the side burners to create fuel-rich and fuel-lean zones8 ReburningYes Yesx xPart of the total fuel heat input is injected into the furnace in a region above theprimary (main burners) flames to create a reducing atmosphere (re-burn zone),where hydrocarbon radicals react with NOx to produce elemental nitrogen9 Load Reduction Yes YesxThis is a strategy to reduce load on a power plant by reducing the electricaldemand throught efficiency projects.10 Energy Efficiency Projects Yes Yesxdecrease amount of fuel required to make an acceptable product11 Coal DryingYes YesxRequires available excessheat.Dry coal will increase the as-burned BTU value, and therefore less fuel is requiredto be burned. Specific energy efficiency project14 Combustion Zone Cooling Yes Yesx xCould reduce loadcapabilitiesCooling of the primary flame zone by heat transfer to surrounding surfacesY:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls1 of 4Appendix FReference(s)Revised: June 8, 2006

Reference No. 1NOxPollution ControlTechnologyAvailable? Applicable? MPCA Taconite BART Report AWMA Journal 9/05 Other 2CommentsBasic Principle15 Alternate FuelsYes Yesx xRequires case by caseanalysis. Typically,facilities experience lowerNOx when burning solidfuels.Lower combustion temps with solid fuels vs gas. May also reduce fuel NOx byusing a fuel with less nitrogen.16Oxygen EnhancedCombustionNo Nox xResearch levelA small fraction of the combustion air is replaced with oxygen.17 Preheat Combustion No Nox xResearch levelPulverized coal preheated and volatiles and fuel-bound nitrogen compounds arereleased in a controlled reducing atmosphere where the nitrogen compounds arereduced to N2.18 ROFA-ROTAMIX Yes Yesx xCombination of OFA and SCR. Wall-fired or tangentially-fired furnace thatutilizes high velocity overfire air. Additional NOx reductions are achieved withammonia injection (Rotamix)19 NOx CEMSYes YesxOptimization of combustion20 Parametric Monitoring Yes YesxOptimization of combustion38Catalyst Injection(EPS Technologies)No NoxResearch LevelA combustion catalyst is directly injected into the air intake stream and deliveredto the combustion site, initiating chemical reactions that change the dynamics ofthe flame.Post Combustion Controls21Non-Selective CatalyticReduction (NSCR)Yes NoxxFor clean services. Toomuch stuff in flue gaswould 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®Yes Yesx xRequires ozone generationUtilizes an oxidizing agent such as ozone to oxidize various pollutants includingNOx23Low Temperature Oxidation(LTO) - LoTOxYes Yesx x xHas been included as an"applicable and available"technology in recent BACTanalyses from multiplefacilities.Utilizes an oxidizing agent such as ozone to oxidize various pollutants includingNOxY:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls2 of 4Appendix FReference(s)Revised: June 8, 2006

Reference No. 1NOxPollution ControlTechnologyAvailable? Applicable? MPCA Taconite BART Report AWMA Journal 9/05 Other 2CommentsBasic Principle24Selective Catalytic Reduction(SCR)Yes Yesx x xNeed to inject atappropriate temperature.Applicable on clean sideonly.Ammonia (NH3) is injected into the flue gas stream in the presence of a catalystto convert NOx into N2and water25 Regenerative SCR Yes YesxClean side only26Selective Non-CatalyticReduction (SNCR)Yes Yesx x xUrea or ammonia-based chemicals are injected into the flue gas stream to convertNO to molecular nitrogen, N2, and water27 AdsorptionNo NoxStill in research stages. Use of char (activated carbon) to adsorb oxides of nitrogen28 AbsorptionYes YesxSimilar to TriNOxUse of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions,molten alkali carbonates, or hydroxides to absorb oxides of nitrogen.29OxidizerYes YesxRedundant to regenerativeSCRGas stream is sent through the regenerative, recuperative, catalytic or direct firedoxidizer where pollutants are heated to a combustion point and destroyed.30SNOXNo Nox xEarly commercialdevelopment 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 H2SO4vapor and then condensed to a concentrated liquid sulfuric acid (H2SO4).31 SOx-NOx-Rox-Box No NoxTechnology has not beendemonstratedDry 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.32 Electron (E-Beam) Process No Nox xNo operating commercialapplications on coalElectron 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.33 Electrocatalytic Oxidation No NoxSimilar to cold plasma.Will keep watch foravailability of thistechnologyUtilizes 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.Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls3 of 4Appendix FReference(s)Revised: June 8, 2006

Reference No. 1NOxPollution ControlTechnologyAvailable? Applicable? MPCA Taconite BART Report AWMA Journal 9/05 Other 2CommentsBasic Principle34NOXSONo NoxCommercial version ofadsorption. Limitedexperience (proof-ofconcept tests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gasfrom coal-fired utility and industrial boilers. In the process, the SO2is convertedto a saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) andthe NOx is converted to nitrogen and oxygen.35 Copper-OxideNo Nox xAbsorption and SCR.Experience limited to pilotscale.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 coppersulfate is reduced in a regenerator with a reducing agent, such as natural gas,producing a concentrated stream of SO2.36 Cold Plasma No NoxResearch Level37 BiofiltersYes NoxResearch levelGas stream is passed through a filter medium of soil and microbes. Pollutants areadsorbed and degraded by microbial metabolism forming the products carbondioxide and water.38 Pahlman Process No NoxResearch LevelGas stream is passed through a filter baghouse in which specially-developed,small-particle, high-surface area metal oxide sorbent have been 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.b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htmc) New and Emerging Environmental Technologies, http://neet.rti.org/d) ND BART ReportsY:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls4 of 4Appendix FTaconite BART AnalysisSOx ControlAvailable and Applicable ReviewReference(s)Revised: June 8, 2006

Reference No. 1SO2Pollution Control TechnologyAvailable? Applicable? MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle1 Wet Scrubbing (High Efficiency) Yes Yesx x xAbsorption and reaction using an alkaline reagent to produce a solid compound2Wet Scrubbing (Low Efficiency)Yes Yesx x xAbsorption and reaction using an alkaline reagent to produce a solid compound3 Wet Walled Electrostatic Precipitator (WWESP) Yes YesxxExisting fabric filtercontrolSuspended particles are separated from the flue gas stream, attracted to plates, and collected inhoppers4Dry sorbent injectionYes Yesx x xPulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Drysorption of SO2onto the lime or limestone particle occurs and the solid particles are collectedwith a fabric filter5 Spray Dryer Absorption (SDA)Yes YesxxLime slurry is sprayed into an absorption tower where SO2is absorbed by the slurry, formingCaSO3/CaSO46Alternative FuelsYes Yesx xNot permitted forother fuels.Use a fuel with lower sulfur content.7Load ReductionYes NoxCould reduceproductionThis is a strategy to reduce load on a power plant by reducing the electrical demand throughtefficiency projects.8Energy Efficiency ProjectsYes Yesxdecrease amount of fuel required to make an acceptable product9Coal DryingYes YesxRequires availableexcess heat sourceDry coal will increase the as-burned BTU value, and therefore less fuel is required to beburned. Specific energy efficiency project10Bio FiltersNo NoxResearch levelGas stream passes through a packed bed of specially engineered biomedia which supports thegrowth of active bacterial species. The pollutants in the gas stream are biodegraded orbiotransformed into innocuous products, such as carbon dioxide, water, chloride ion in water,sulfate or nitrate ions in water.11CANSOLV Regenerable SO2No NoxResearch levelAn aqueous solution of proprietary diamine captures SO2from the feed gas in a countercurrentabsorption tower. The rich solvent is regenerated by steam stripping, giving a byproduct ofpure, water saturated SO2gas and lean solvent for recycling to the absorber.12 Pahlman ProcessNo NoxResearch levelGas stream is passed through a filter baghouse in which specially-developed, small-particle,high-surface area metal oxide sorbent have been deployed. Pollutants are removed from thegases by adsorption.13SOx-NOx-Rox-BoxNo NoxTechnology has notbeen demonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammonia injectionupstream of a zeolitic selective catalytic reduction (SCR) catalyst incorporated in the baghouseto reduce NOx emissions.14Electron (E-Beam) ProcessNo NoxNo operatingcommercialapplications on coalElectron beam irradiation in the presence of ammonia to initiate chemical conversion of sulfurand nitrogen oxides into components which can be easily collected by conventional methodssuch as an ESP or baghouse.Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls1 of 2Appendix FReference(s)Revised: June 8, 2006

Reference No. 1SO2Pollution Control TechnologyAvailable? Applicable? MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle15Electrocatalytic OxidationNo NoxSimilar to coldplasma. Will keepwatch for availabilityof this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen dioxide (NO2),sulfuric acid, and mercuric oxide respectively using non-thermal plasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSONo NoCommercial versionof adsorption.Limited experience(proof-of-concepttests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gas from coalfired utility and industrial boilers. In the process, the SO2is converted to a saleable sulfur byproduct (liquid SO2, elemental sulfur, or sulfuric acid) and the NOx is converted to nitrogenand oxygen.17 Copper-OxideNo NoxAbsorption andSCR. Experiencelimited to pilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheres of alumina, to formcopper sulfate. Ammonia is injected into the flue gas before the absorption reactor and aselective catalytic reduction-type reaction occurs that reduces the nitric oxides in the flue gas.In the regeneration step, the copper sulfate is reduced in a regenerator with a reducing agent,such as natural gas, producing a concentrated stream of SO2.18 SNOXNo NoxEarly commercialdevelopment stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed by catalytic oxidationof SO2to SO3. The exit gas from the SO3converter passes through a novel glass-tubecondenser in which the SO3is hydrated to H2SO4vapor and then condensed to a concentratedliquid sulfuric acid (H2SO4).19 Cold PlasmaNo NoxResearch 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.b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htmc) New and Emerging Environmental Technologies, http://neet.rti.org/d) ND BART ReportsY:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls2 of 2