## Minntac BART Report September 8, 2006

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# i 

# Minntac BART Report September 8, 2006

T able of Contents

1. Executive Summary.............................................................................................................................iv
2. Introduction...........................................................................................................................................1 2.A BART Eligibility.........................................................................................................................3 2.B BART Determinations ................................................................................................................3
3. Streamlined BART Analysis ................................................................................................................9 3.A Indurating Furnaces ....................................................................................................................9 3.B PM-Only Taconite MACT Emission Units ................................................................................9 3.C Sources of fugitive PM that are subject to MACT standards....................................................10 3.D Non-MACT Units and Fugitive Sources (PM only).................................................................11 3.E Other Combustion Units ...........................................................................................................11 3.F Visibility Impact Modeling for Negligible Impacts..................................................................12
4. Baseline Conditions and Visibility Impacts for BART Eligible Units ...............................................17 4.A MPCA Subject-to-BART Modeling .........................................................................................17 4.B Facility Baseline Emission Rates..............................................................................................18 4.C Facility Baseline Modeling Results ..........................................................................................19
5. BART Analysis for BART Eligible Emission Units ..........................................................................22 5.A Indurating Furnace....................................................................................................................22 5.A.i Sulfur Dioxide Controls............................................................................................... 25 5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 25 5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 25 5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control T echnologies................................................................................................ 32 5.A.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 33 5.A.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 35 5.A.ii Nitrogen Oxide Controls.............................................................................................. 40 5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 40 5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 40 5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control T echnologies................................................................................................ 54 5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results............................... 54 5.A.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 57 5.B External Combustion Sources...................................................................................................62 5.B.i Nitrogen Oxide Controls.............................................................................................. 62 5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 62 5.B.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 63

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# ii 5 .B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control T echnologies................................................................................................ 70 5.B.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 71 5.B.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 73
6. Visibility Impacts................................................................................................................................77 6.A Post-BART Modeling Scenarios...............................................................................................77 6.B Post-BART Modeling Results ..................................................................................................77
7. Select BART.......................................................................................................................................81 7.A Indurating Furnaces ..................................................................................................................81 7.B External Combustion Sources...................................................................................................84

L ist of Tables

Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis ...14 Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data .............15 Table 3-3 De Minimis Visibility Modeling Results....................................................................16 Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data..20 Table 4-2 Baseline Visibility Modeling Results..........................................................................21 Table 5-1 Indurating Furnace SO 2 

# Control Technology – Availability, Applicability, and

T echnical Feasibility ..................................................................................................32 Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness.........................................32 Table 5-3 Indurating Furnace SO 2 

# Control Cost Summary ..........................................................34 Table 5-4 Indurating Furnace Post-BART SO 2 

# Control - Predicted 24-hour Maximum Emission

R ates ..........................................................................................................................37 Table 5-5 Indurating Furnace Post-BART SO 2 

# Modeling Scenarios - Visibility Modeling Results39 Table 5-6 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and

T echnical Feasibility ..................................................................................................53 Table 5-7 Indurating Furnace NO x 

# Control Technology Effectiveness ........................................54 Table 5-8 Indurating Furnace NO x 

# Control Cost Summary .........................................................55 Table 5-9 Indurating Furnace NO x 

# Control Technology Impacts Assessment..............................57 Table 5-10 Indurating Furnace Post- BART NO X 

# Control - Predicted 24-hour Maximum Emission

R ates ..........................................................................................................................60 Table 5-11 Indurating Furnace Post-BART NO X 

# Modeling Scenarios - Visibility Modeling Results61 Table 5-12 Boiler NO x 

# Control Technology – Availability, Applicability, and Technical Feasibility70 Table 5-13 Boiler NO x 

# Control Technology Effectiveness............................................................71 Table 5-14 Boiler NO x 

# Control Cost Summary .............................................................................72 Table 5-15 Boiler Post-BART NO X 

# Control - Predicted 24-hour Maximum Emission Rates .........75 Table 5-16 Boiler Post-BART NO X 

# Modeling Scenarios - Visibility Modeling Results ................76 Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results ...................................80

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# iii List of Figures

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

L ist of Appendices

Appendix A Control Cost Analysis Spreadsheets Appendix B Changes to MPCA BART Modeling Protocol Appendix C Visibility Impacts Modeling Report Appendix D NO X 

# Emissions Analysis – Pre and Post Installation of Air Injection Ports on Line 7

a t USS/Minntac Appendix E Indurating Furnace – Applicable and Available Retrofit Technologies Appendix F Summary of Relevant Economic Feasibility ($/ton) Control Costs Appendix G Process Heating Boiler – Applicable and Available Retrofit Technologies

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# iv 

# 1. Executive Summary

U.S. Steel Corporation’s Minnesota Ore Operations (Minntac) is located in northern Minnesota, with taconite mining and processing facilities near Mountain Iron, Minnesota. This report describes the background and methods for the selection of the Best Available Retrofit Technology (BART) as proposed by Minntac for its taconite processing plant.

Within the pellet making process, there are many pieces of equipment with pollution control devices to reduce emissions. Based on the regulatory definitions and the details provided in this report, Minntac’s BART-eligible units include emission units that were installed within the BART time window (1962-1977). These BART-eligible units include the indurating furnaces, heating boilers, minor combustions sources, and several material handling and storage units for ore, product, and additives. Preliminary visibility modeling conducted by the MPCA found that the BART-eligible air emissions from Minntac “cause or contribute to visibility impairment” in a federally protected Class I area, therefore making the facility subject-to-BART. As a subject-to-BART facility, a BART analysis was required to determine BART for the affected emission units.

Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include a streamlined approach for BART analyses 1 

# . The streamlined approach allows both the states and the
f acilities to focus their resources on the main contributors to visibility impairment. As described in section 3 of this document, the emissions from several of the sources at this facility meet the criteria for a streamlined analysis.

The streamlined analysis includes the specific provision that compliance with the Taconite MACT (40 CFR Part 63 Subpart RRRRR) for PM emissions as equivalent to BART. This provision is applicable to all indurating furnaces, ore crushing and handling operations, and finished pellet handling operations that are subject to BART. The Taconite MACT standard includes requirements for performance testing and continuous parametric monitoring for compliance demonstration.

After completion of the streamlined analysis, the focus of the BART analysis was the NO x 

# emissions
f rom four heating boilers and the SO 2 

# and NO x 

# emissions from the five indurating furnaces. The four
b oilers that underwent the BART analysis are relatively small, and have limited hours of operation and utilization. The Indurating Furnaces operate with existing control equipment which include: wet

1 

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

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# v scrubbers for each of the five stacks designed to control of particulate matter (PM) with collateral control of sulfur dioxide (SO 2 

# ); ported kilns on two of the furnaces designed for energy efficiency

w ith collateral control of nitrogen oxides (NO x 

# ); and low-NO x 

# burners installed on the preheat

s ection of one of the furnaces.

Guidelines included in 40 CFR §51 Appendix Y and MPCA Attachments 2 and 3 were used to determine BART for these sources. A dispersion modeling sequence of CALMET, CALPUFF, and CALBART was used to assess the visibility impacts of the baseline emissions and after the application of candidate BART controls. Visibility impacts were evaluated in the selection of BART. Other criteria that the BART rules require to be considered include the availability of control technologies, cost of control, energy and environmental impacts, existing pollution control technology in use at the source, and the remaining useful life of the source.

Based on the consideration of all of the above criteria, Minntac proposes no additional controls, emission limits, or monitoring requirements for the NO x 

# emissions from four heating boilers. This is
b ased on the conclusion that low-NOx burners were the only control technology that meet the cost screening threshold, but the technology did not provide significant improvement in the visibility modeling. In addition, the control cost for this technology is higher than the anticipated level for a BART analysis. It is also important to note that due to the relatively small size of the boilers and the low hours of operation, the actual visibility impact of the boilers is small.

Based on consideration of all of the above criteria, Minntac proposes the following as BART for SO 2



# a nd NO X 

# for the Indurating Furnaces:

• B ART for SO 2 

# :

o S O 2 

# emissions will be controlled by the existing wet scrubbers, which will be

o perated as required in accordance with provisions of the Taconite MACT.

o SO 2 

# emission limit for the Indurating Furnace on Line 3 will be determined based

o n upcoming performance testing to determine the actual emission rate from the furnace with the addition of the new scrubber. A proposed SO 2 

# limit for the
f urnace in the draft PSD permit for Minntac does not reflect the recently installed
wet scrubber.

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# vi o S O 2 

# emission limits for the Indurating Furnaces on lines 4, 5, 6, and 7 will be the
l imits which are based on using the existing wet scrubbers and reflect air dispersion modeling results for regional haze as proposed in the draft PSD permit:

⋅ Line 4 = 182 lbs/hr

⋅ Line 5 = 182 lbs/hr

⋅ Line 6 = 284 lbs/hr

⋅ Line 7 = 284 lbs/hr

o Compliance will be initially be demonstrated by a performance test at each
furnace.

o Continuous compliance will be demonstrated by continuous monitoring of scrubber water flow rate and scrubber pressure drop, which are the same parameters that will be monitored under the Taconite MACT. The operating limits will be determined based on the MACT compliance test and will be based on a 24-hour block average. Therefore, the compliance demonstration will be
consistent with the Taconite MACT.

• BART for NO x 

# :

o N O x 

# emissions will be controlled as follows:

⋅ L ine 3: Existing combustion controls and fuel blending. Line 3 does not currently use burners in its pre-heat section, and therefore low-NO x 

# burners

c annot be applied at this furnace.

⋅ Line 4: Installation of low-NO x 

# burners on the pre-heat section, existing

c ombustion controls, and fuel blending.

⋅ Line 5: Installation of low-NO x 

# burners on the pre-heat section, existing

c ombustion controls, and fuel blending.

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# vii ⋅ L ine 6: Operation of low-NO x 

# burners on the pre-heat section (installed as

r eplacement and reconfigured burners in April 2006), existing combustion controls, and fuel blending.

⋅ Line 7: Installation of low-NO x 

# burners on the pre-heat section, existing

c ombustion controls, and fuel blending.

o NO x 

# emission limits will be proposed by the facility 12-months after the
i nstallation of the low-NO x 

# burners to allow the facility sufficient time for

p rocess and emissions monitoring using NO x 

# CEMS to determine the actual

e mission rates under a variety of operating conditions. Although the facility anticipates a significant reduction in NO x 

# emissions with the installation of the
l ow-NO x 

# burners, the actual emissions reduction cannot be determined until the
b urners are operated under a variety of operation conditions.

o Initial and continuous compliance will be demonstrated after the appropriate emission limits have been determined. Compliance will be demonstrated using
the NO x 

# CEMS and will be based on a 30-day rolling average.

T he schedule for implementation of these controls, specifically installation of low-NO x 

# burners and

s ubsequent testing to demonstrate the appropriate BART emission limit, is within the 5-year timeframe required for BART implementation. In addition, Minntac will continue to evaluate energy efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission

rates.

Using the modeling protocol as described above and a NOx emission reduction estimate of 10% for
the installation of low-NO x 

# burners, the proposed BART controls will result in visibility
i mprovement on the 98 th 

# percentile day of approximately 0.488 deciviews (dV) when burning gas in

t he kiln and 0.465 dV when burning solid fuels in the kiln. This is a visibility improvement of approximately 7% compared to the baseline (pre-BART) operating conditions.

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# 1 

# 2. Introduction

To meet the Clean Air Act’s requirements, the U.S. Environmental Protection Agency (U.S. EPA) published regulations 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] and is found in 40 CFR part 51, in §51.300 through §51.309.

Within its boundary, Minnesota has two Class I areas – the Boundary Water Canoe Area Wilderness and Voyageurs National Park. In addition, emissions from Minnesota may contribute to visibility impairment in other states’ Class I areas, such as Michigan’s Isle Royale National Park and Seney Wilderness Area. By December 2007, MPCA must submit to U.S. EPA a Regional Haze State Implementation Plan (SIP) that identifies sources that cause or contribute to visibility impairment in these areas. The Regional Haze SIP must also include a demonstration of reasonable progress toward reaching the 2018 visibility goal for each of the state’s Class I areas.

One of the provisions of the Regional Haze Rule is that certain large stationary sources that were put in place between 1962 and 1977 must conduct a Best Available Retrofit Technology (BART) analysis. The purpose of the BART analysis is to analyze available retrofit control technologies to determine if a technology should be installed to improve visibility in Class I areas. The chosen technology is referred to as the BART controls, or simply BART. The SIP must require BART on all BART-eligible sources and mandate a plan to achieve natural background visibility by 2064. Figure 2-1 illustrates the BART-eligible facilities and the two Class I areas in Minnesota. When reviewing Figure 2-1, it is important to note that Minnesota Steel Industries (MSI) and Mesabi Nugget (Nugget), which are illustrated in the figure, are not currently constructed or in operation. The SIP must also include milestones for establishing reasonable progress towards the visibility improvement goals and plans for the first five-year period. Upon submission of the Regional Haze SIP, states must make the requirements for BART sources federally enforceable through rules, administrative orders or Title V permit amendments.

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# 2 Figure 2-1 Minnesota’s BART Geography The Minnesota SIP will address the 2 PSD Class I Areas [Voyageurs National Park (VPN) and Boundary

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

(Source MPCA BART-Strategy October 4, 2005)



# B y definition, reasonable progress means that the 20 best-visibility days must get no worse, and the 20 worst-visibility days must become as good as the 20 worst days under natural conditions. 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.

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# 3 

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

m ust meet the following three conditions:

1. Contain emission units in one or more of the 26 listed source categories under the PSD rules (e.g., taconite ore processing plants, fossil-fuel-fired steam electric plants larger than 250 MMBtu/hr, fossil-fuel boilers larger than 250 MMBtu/hr, petroleum refineries, coal cleaning plants, sulfur recovery plants, etc.);

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

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

Under the BART rules, large sources that have previously installed pollution-control equipment required under another standard (e.g., MACT, NSPS and BACT) are required to conduct visibility analyses to determine if the source is subject-to-BART. Installation of additional controls may be required to further reduce emissions of visibility impairing pollutants such as PM, PM 10 

# , PM 2.5 

# , SO 2 

# , N O x 

# , and possibly Volatile Organic Compounds (VOCs) and ammonia. Sources built before the
i mplementation of the Clean Air Act (CAA), which had previously been grandfathered, may also have to conduct such analyses and possibly install controls, even though they have been exempted to date from any other CAA requirements.

Once BART eligibility is determined, a source must then determine if it is ‘subject-to-BART.’ A source is subject-to-BART if emissions ‘cause or contribute’ to visibility impairment at any Class I area. Visibility modeling conducted with CALPUFF or another U.S. EPA -approved visibility model is necessary to make a definitive visibility impairment determination (>0.5 deciviews). Sources that do not cause or contribute to visibility impairment are exempt from BART requirements, even if they are BART-eligible.



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

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

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# 4 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. 2



# T he five steps of a BART analysis are:

Step 1 - Identify all Control Technologies

The first step in the analysis is to identify all available retrofit control technologies for each applicable emission unit. U.S. EPA is very specific about the criteria to be met for a technology to be considered available. In preambles to the interim and final rules
U.S. EPA defines “available” as follows:

Available retrofit technologies are those air pollution control technologies with a practical potential for application to the emissions unit and the regulated pollutant under evaluation. Air pollution control technologies can include a wide variety of available methods, systems, and techniques for control of the affected pollutant. Technologies required as BACT or LAER are available for BART purposes and must be included as control alternatives. The control alternatives can include not only existing controls for the source category in question, but also take into account technology transfer of controls that have been applied to similar source categories or gas streams. Technologies which have not yet been applied to (or permitted for) full scale operations need not be considered as available; we do not expect the source owner to purchase or construct a process or control device that has not been demonstrated in practice. 3



# S tep 2 - Eliminate Technically Infeasible Options

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

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

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.”

2 

# 40 CFR 51 Appendix Y 3 

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

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# 5 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.” 4



# 2

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

In general, a commercially available control technology, as defined in question 1, “will be presumed applicable if it has been used on the same or a similar source type.” If a control technology has not been demonstrated on a same or a similar source type, the technical feasibility is determined by “examining the physical and chemical characteristics of the pollutant-bearing stream and comparing them to the gas stream characteristics of the source types to which the technology has been applied previously.” 5



# 3

. Are there source-specific issues/conditions that would make the control technology not technically feasible?

This question addresses specific circumstances that “preclude its application to a particular emission unit.” This demonstration typically includes an “evaluation of the characteristics of the pollutant-bearing gas stream and the capabilities of the technology.” This also involves the identification of “un-resolvable technical difficulties.” However, when the technical difficulties are merely a matter of increased cost, the technology should be considered technically feasible and the technological difficulty evaluated as part of the economic analysis. 6



# I t is also important to note that vendor guarantees can provide an indication of technical feasibility but the U.S. EPA does not “consider a vendor guarantee alone to be sufficient justification that a control option will work.” Conversely, the U.S. EPA does not consider the lack of a vender guarantee as “sufficient justification 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

4 

# Federal Register 70, No. 128 (July 6, 2005): 39165 5 

# IBID 6 

# IBID

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# 6 evaluation of the chemical and engineering analysis and the information from vendor guarantees. 7



# S tep 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 8 

# , including receptor grid, meteorological
d ata, and other factors used for this part of the analysis were provided by the Minnesota Pollution Control Agency. The model outputs, including the 98th percentile deciview (dV) value and the number of days the facility contributes more than a 0.5 dV of 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.

7 

# IBID 8 

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

.

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# 7 The final step in the BART analysis is to select the “best alternative” using the results of steps 1 through 5. When selecting the “best alternative,” the U.S. EPA and MPCA guidance states that the “affordability” of the controls should be considered, and specifically states:

1. Even if the control technology is cost effective, there may be cases where the installation of controls would affect the viability of plant operations.

2. There may be unusual circumstances that justify taking into consideration the conditions of the plant and the economic effects requiring the use of a given control technology. These effects would include effects on product prices, the market share, and profitability of the source. Where there are such unusual circumstances that are judged to affect plant operations, you may take into consideration the conditions of the plant and the economic effects of requiring the use of a control technology. Where these effects are judged to have severe impacts on plant operations you may consider them in the selection process, but you may wish to provide an economic analysis that demonstrates, in sufficient detail for public review, the specific economic effects, parameters, and reasoning. (We recognize that this review process must preserve the confidentiality of sensitive business information). Any analysis may also consider whether competing plants in the same industry have been required to install BART controls if this information is available. 9



# T o 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.” 10 

# Those limits

m ust 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” 11 

# which could include the incorporation of

o ther regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR 64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If technological or economic limitations make measurement methodology for an emission unit

9 

# MPCA. March 2006. G uidance for Facilities Conducting a BART Analysis . Page 20. 10 

# MPCA. March 2006. G uidance for Facilities Conducting a BART Analysis . Page 23. 11 

# IBID

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# 8 infeasible, the BART limit can “instead prescribe a design, equipment, work practice, operation standard, or combination of these types of standards.” 12



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

12 

# IBID

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# 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 13 

# . The streamlined approach will allow both states and the
f acilities to focus their resources on the main contributors to visibility impairment. The following outlines the MPCA-approved streamlined BART analysis for taconite facilities and presents the results of the streamlined approach in Table 3-1. 

# 3.A Indurating Furnaces The indurating furnace is a source of three visibility impairing pollutants: NO x 

# , SO 2 

# , and PM.
R elative to NO x 

# and SO 2 

# , PM is not a major visibility impairing pollutant. Further, the indurating
f urnace is subject to the taconite MACT standard [40 CFR Part 63 Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing] for the PM emissions. MPCA’s guidance for conducting a BART review states that “MPCA will rely on MACT standards to represent BART level of control for those visibility impairing pollutants addressed by the MACT standard unless there are new technologies subsequent to the MACT standard, which would lead to cost-effective increases in the level of
control.” 14 

# Since the MACT standard was established very recently and becomes effective in 2006,

t he 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 these sources.

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
O re 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
O re 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. 15 

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

13 

# Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116 14 

# MPCA. March 2006. G uidance for Facilities Conducting a BART Analysis . Page 2. 15 

# Federal Register 67, no. 143 (December 18, 2002): 77570

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# 1 0 impact on visibility impairment, and no control requirements under the MACT standard is consistent with the intention of the BART analysis.

Since the MACT standard was established recently and will become effective in 2006, the technology analysis is up-to-date. Again, for these units subject to a MACT standard, BART will be presumed to be equivalent to MACT according to MPCA guidance.

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

# 3.C Sources of fugitive PM that are subject to MACT standardsThe taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from nonM ACT sources are addressed in section 3.D). These sources operate at ambient temperature, only emit PM, and do not emit NO x 

# or SO 2 

# . Taconite MACT fugitive sources include the following:

• S tockpiles (includes, but is not limited to, stockpiles of uncrushed ore, crushed ore, or finished pellets),

• Material Transfer Points,

• Plant Roadways,

• Tailings basins,

• Pellet loading areas, and

• Yard areas.

Control of emissions from these fugitive PM sources is maintained through a fugitive control plan, as required by the MACT standard and as required by the facility’s Title V air permit. The fugitive control plans consist of monitoring, primary controls, and contingent measures to prevent or mitigate fugitive PM emissions. The controls and measures are site specific and are appropriate to seasonal and weather conditions. 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.

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# 1 1 

# 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.
T hey include units such as:

• Bentonite storage and handling

• Additive storage and handling

• Concentrate storage and handling

• Coal and/or solid fuel storage and handling
Considering all PM emissions which are subject to the BART standard, the PM emissions from the above units typically represent approximately 1% of PM emissions from the facility, which are subject-to-BART. Relative to NO x 

# and SO 2 

# , PM is not a major visibility impairing pollutant.

T he point source emission units are controlled by either baghouses or scrubbers, which are technologies that achieve high levels of control for PM. Since these units already have control equipment for PM emissions, and since the PM emissions from these sources are small relative to the total PM emissions that are subject to the BART standard, additional control of these sources can be presumed to have minimal impact on visibility improvement in Class I areas. For the controlled sources, existing controls will be considered BART consistent with direction from MPCA in the May 18, 2006 meeting, and no further analysis will be required to establish BART for these sources. If any sources do not have existing controls, the facility will conduct an analysis for these sources to demonstrate that the impact on visibility in Class I areas is negligible. The procedure for the analysis is detailed in section 3.F of this document. Assuming that the modeling demonstrates that the sources have a negligible impact on visibility in Class I areas and no further analysis will be required
to establish BART for these sources.



# 3.E Other Combustion Units This facility has several other combustion units that are subject-to-BART. The combustion units are

s ources of three visibility impairing pollutants: NO x 

# , SO 2 

# , and PM. The remaining combustion

s ources include process heaters, boilers, emergency generators, air compressors, and fire pumps. It is important to note that the emissions from the indurating furnaces represent the vast majority of emissions of all visibility impairing pollutants, with the all other emission units contributing less than 1% of the total emissions of each pollutant from sources that are subject-to-BART. The emissions from all the remaining sources are small relative to the total 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. As directed by MPCA in the May 18, 2006 meeting, the existing

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# 1 2 operations for emergency generators and fire pumps will be considered BART. This facility has conducted an analysis for the remaining sources to demonstrate that the impact on visibility is negligible. The procedure for the analysis is detailed in section 3.F of this document. For the sources for which the modeling demonstrates negligible impact on visibility in Class I areas, no further analysis will be required to establish BART for these sources. 

# 3.F Visibility Impact Modeling for Negligible Impacts As described in section 3.D and 3.E of this document, this facility contains several sources that are

a ssumed to have a negligible impact on visibility in Class I areas. In order to confirm this assumption, a modeling analysis was conducted to determine the impact of the emissions from these sources on visibility in Class I areas. The analysis consisted of the following:

(1) Conduct air dispersion modeling for uncontrolled BART-eligible emission units and fugitive sources for the facility, as described in sections 3.D and 3.E above. The modeling was conducted based on MPCA modeling protocol 16 

# . One modeling

a nalysis was conducted. The modeling was conducted on a focused grid (as previously agreed to with MPCA) which is based on the facility impacts as presented by MPCA in “Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the State of Minnesota” (March 2006).

(2) Count the days with a 98 th 

# percentile (21 over 3-yrs, 7 each year) change in visibility

g reater than or equal to 0.05 deciviews (based on 10% of the facility threshold of 0.5 deciviews) at the modeled receptors with in the boundaries of each Class I area assessed over the 3-year period 2002-2004.

(3) If the modeled emission sources result in a 98 th 

# percentile change in visibility less

t han or equal to 0.05 deciviews, the point and fugitive sources will be considered to not cause or contribute to visibility impairment in Class I areas. Therefore, the existing operations will be considered BART. No further analysis will be required to
establish BART for these sources.

16 

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

.

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# 1 3 (4) If the modeled emissions result in a 98 th 

# percentile change in visibility greater than or

e qual to 0.05 deciviews, a full BART analysis will be conducted on the emission

sources.

The de minimis modeling input data is presented in Table 3-2. A summary of the results of the de minimis modeling is presented in Table 3-3. The details of the de minimis modeling are presented in Appendix C.

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# 1 4 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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# 1 5 Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data

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# 1 6 Table 3-3 De Minimis Visibility Modeling Results

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# 1 7 

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

As indicated in U.S. EPA’s final BART guidance 17 

# , one of the factors to consider when determining
B ART for an individual source is the degree of visibility improvement resulting from the retrofit technology. The visibility impacts for this facility were determined using CALPUFF, a U.S. EPA approved model. The CALPUFF program models how a pollutant contributes to visibility impairment with consideration for the background atmospheric ammonia, ozone and meteorological data. Additionally, the interactions between the visibility impairing pollutants NO x 

# , SO 2, 

# PM 2.5 

# and
P M 10 

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

a pproach when assessing visibility impacts.

In order to determine the visibility improvement resulting from the retrofit technology, the source must first be modeled at baseline conditions. Per MPCA guidance, the baseline, or pre-BART conditions, shall represent the average emission rate in units of pounds per hour (lbs/hr) and reflect
the maximum 24-hour actual emissions 18



# . 

# 4.A MPCA Subject-to-BART Modeling In order to determine which sources are “Subject-to-BART” in the state of Minnesota, the MPCA

c ompleted modeling of the BART-eligible emission units at various facilities in Minnesota in accordance with the Regional Haze rule. The modeling by MPCA was conducted using CALPUFF, as detailed in the “Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota,” finalized in March 2006. The modeling by MPCA was conducted using emission rate information submitted by the facility. The emissions were reported in units of pounds per hour (lbs/hr) and were 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.

17 

# Federal Register 70, no. 128 (July 6, 2005): 39106. 18 

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

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# 1 8 It is important to note that the MPCA subject-to-BART modeling only included the induration furnace sources. This is due to the fact that this facility contains 375 BART-eligible emission units, which would have added increased complexity to the modeling. However, the modeling results of only the indurating furnaces demonstrated that the facility is subject-to-BART. 

# 4.B Facility Baseline Emission Rates Prior to re-creating the MPCA visibility impairment model, the modeling protocol was re-revaluated.
O n behalf of this facility and the other Minnesota taconite facilities, Barr Engineering proposed changes to the modeling protocol. The changes, as submitted to MPCA on May 16, 2006 are presented in Appendix B. The MPCA has given verbal approval to the proposed changes to the modeling protocol.

Consistent with MPCA modeling and as agreed upon in the MPCA-approved changed to the modeling protocol, only the induration furnaces were required to be modeled for this facility. However, the NO x 

# emissions from Boilers #1, #2, #4 and #5 were also added to the visibility model

a s these sources are also subject to a full BART analysis for NO x 

# .

I n addition, the maximum 24-hour emission rates were re-evaluated and adjusted, as appropriate, to confirm that the emission rates represent the maximum steady-state operating conditions during periods of high capacity utilization. The maximum 24-hour emission rates were adjusted to reflect the highest emission rate as measured during a representative stack test, as opposed to the emission rate as measured during the most recent stack test. The baseline emission rates from the following sources were adjusted using this criteria:

o Line 3 Rotary Kiln (EU 225 / SV 103) - NO x 

# and SO 2



# o L ine 4 Rotary Kiln (EU 261 / SV 118) - NO x 

# and SO 2



# o L ine 5 Rotary Kiln (EU 280 / SV 127) - NO x 

# and SO 2



# o L ine 6 Rotary Kiln (EU 315 / SV 144) - NO x 

# and SO 2



# o L ine 7 Rotary Kiln (EU 334 / SV 151) - NO x 

# and SO 2



# T he MPCA visibility impairment modeling evaluated the impacts of the maximum 24-hour emissions
of SO 2 

# , NO x 

# , and PM. However, it is important to note that the worst-case SO 2 

# emissions scenario is
b ased on solid fuel operation and the worst-case NO x 

# emissions scenario is based on natural gas

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# 1 9 operation. Therefore, baseline modeling was conducted for two separate operating scenarios for fuel burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that natural gas is the only fuel that is burned in the preheat section of the kiln.

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

# 4.C Facility Baseline Modeling Results The Minnesota BART modeling protocol also describes the post processing elements of the

a nalysis. 19 

# The CALBART output files provide the following two methods to assess the expected

p ost-BART visibility improvement:

• 98 th 

# Percentile: As defined by federal guidance and as stated in the MPCA’s document which
i dentifies the Minnesota facilities that are subject to BART 20 

# , a source "contributes to

v isibility impairment” if the 98 th 

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

# highest
d ay) 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, the modeling of the revised baseline emissions confirms that the facility is considered to contribute to visibility impairment in Class I areas because the modeled 98 th 

# percentile of the baseline conditions

e xceeds the threshold of 0.5 dV. The results of this modeling are also utilized in the post-BART modeling analysis in section 6 of this document.

The full modeling analysis is presented in Appendix C.

19 

# MPCA. March 2006. B est Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota. Page 8. 20 

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

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# 2 0 Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data

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# 2 1 Table 4-2 Baseline Visibility Modeling Results

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# 2 2 

# 5. BART Analysis for BART Eligible Emission Units

BART eligible sources at this facility can be divided into groups based upon type of process. The Minntac facility had two types of processes which were required to undergo a full BART analysis:

• Indurating Furnaces for NO x 

# and SO 2 

# (Section 5.A)

o L ine 3 Rotary Kiln (EU 225 / SV 103)

o Line 4 Rotary Kiln (EU 261 / SV 118)

o Line 5 Rotary Kiln (EU 282 / SV 127)

o Line 6 Rotary Kiln (EU 315 / SV 144)

o Line 7 Rotary Kiln (EU 334 / SV 151)

• External Combustion Sources for NO x 

# (Section 5.B)

o U tility Plant Heating Boiler #1 (EU 001 / SV 001)

o Utility Plant Heating Boiler #2 (EU 002 / SV 002)

o Utility Plant Heating Boiler #4 (EU 004 / SV 004)

o Utility Plant Heating Boiler #5 (EU 005 / SV 005) 

# 5.A Indurating Furnace “Soft” or “green” pellets are oxidized and heat-hardened in the induration furnace. The induration

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

This facility has five grate/kiln induration furnaces, in which the pellets are dried on a grate and then transferred to a rotary kiln for hardening and oxidation. The pellet hardening and oxidation section of the induration furnace is designed to operate at 2,400 oF and higher. This temperature is required to meet taconite pellet product specifications. Fuel combustion in the induration furnace is carried out at approximately 15% to 18% oxygen to provide sufficient oxygen for pellet oxidation.

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# 2 3 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 to be directed to the process instead of heating ambient air to combustion temperatures.

The five grate/kiln induration furnaces at this facility utilize the following fuels:

• Line 3 Rotary Kiln (EU 225 / SV 103) – natural gas, biomass, and fuel oil

• Line 4 Rotary Kiln (EU 261 / SV 118) – natural gas, biomass, and fuel oil

• Line 5 Rotary Kiln (EU 282 / SV 127) – natural gas, biomass, and fuel oil

• Line 6 Rotary Kiln (EU 315 / SV 144) – natural gas, biomass, fuel oil and coal

• Line 7 Rotary Kiln (EU 334 / SV 151) – natural gas, biomass, fuel oil and coal

Emissions from the induration furnaces are controlled as follows:

• PM / PM 10 

# : PM emissions are controlled by a wet scrubbers with water used as the scrubbing solution. The PM emissions from the indurating furnace are subject to the taconite MACT standard. are regulated by the Taconite MACT. As addressed in section 3.A, BART will be presumed to be equivalent to MACT for PM and no further analysis will be required to
establish BART for PM for these sources.

On lines 4, 5, 6 and 7, the water from the scrubber passes through the scrubber once, with some of the discharge water being used immediately used as process water in the concentrator with the remainder of the water being discharged to the tailings basin. The wet scrubbers are designed to remove PM and are considered a high efficiency PM wet scrubbers and will be evaluated as such within this BART analysis.

The Line 3 wet scrubber was installed after the BART baseline period and started operation on June 2006. The scrubber is a recirculating scrubber with the scrubber blowdown water being treated before being discharged to the tailings basin. The wet scrubber is designed to

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# 2 4 remove PM and is considered a high efficiency PM wet scrubber and will be evaluated as such within this BART analysis. Since the scrubber was installed after the baseline date, the emissions in the post-BART modeling analysis were adjusted to account for the improved removal efficiency.

• SO 2 

# : SO 2 

# emissions are controlled as collateral SO 2 

# reductions by the existing wet scrubbers.
T herefore, the existing wet scrubbers are considered a low-efficiency SO 2 

# scrubbers and will
b e evaluated as such within this BART analysis.

• NO X 

# : NO X 

# is controlled through existing combustion practices and fuel switches (lower NO x



# e missions when burning solid fuels). NO X 

# emissions are monitored using NO X 

# continuous

e missions monitoring systems (CEMS).

Air injection ports were installed on the kilns on Line 7 in 2001 and Line 6. The purpose of the ports is to allow air injection into the pellet bed as it travels down the kiln bed. In March 2002, Minntac submitted a report to MPCA presenting an analysis of the NO X 

# emissions from
L ine 7 before and after the installation of the ports. This report is presented in Appendix D. As described in the report, the NO X 

# emissions from the kiln decreased by approximately 5%

w hen burning natural gas. However, no emission reduction was noted when burning solid fuels. When evaluating the use of air injection ports for the reduction of NO X 

# emissions, it is
i mportant to note that solid fuels are typically burned in the furnaces and therefore, the actual improvement in NO X 

# emissions would be significantly less than 5% estimate.

I n April 2006, replacement and reconfigured burners were installed into the preheat section of Line 6. The burners were installed as an energy efficiency project. However, after installation of the burners, the emissions from the kiln were evaluated using the data from the
NO x 

# CEMS. This evaluation showed a reduction in NO X 

# emissions from the kiln of

a pproximately 10% when the preheat section was in operation. Since the low-NO X 

# burners

w ere installed after the baseline date, the emissions in the post-BART modeling analysis were adjusted to account for the reduced emissions from Line 6. Additional information regarding the post-BART modeling is presented in Step 5 of this BART analysis.

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# 2 5 

# 5.A.i Sulfur Dioxide Controls

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies S tep 1 identifies a comprehensive list of all potential retrofit control technologies that were evaluated. Many emerging technologies were identified that are not currently commercially available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the technology as it was understood at that time. In regards to the availability of the technology with respect to Step 1 of the BART analysis, the list has not changed from the information submitted at that time. The comprehensive list of control technologies is presented in Appendix E.

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As stated in section 2.B of this document, the technical feasibility of each option is determined by answering three specific questions:

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

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

3. Are there source-specific issues/conditions that would make the control technology not technically feasible?

A preliminary list of technologies was submitted to MPCA on May 9, 2006 with the status of the technology as it was understood at that time. As work on this evaluation progressed, additional information became apparent regarding the limited scope and scale of some of the technology applications. Appendix E presents the current status of the availability and applicability of each technology.

The following section describes retrofit SO 2 

# control technologies that were identified as available and

a pplicable in the May 9 submittal and discusses aspects of those technologies that determine whether or not the technology is technically feasible for the indurating furnace.

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

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# 2 6 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,

c austic is added to the water spray system, allowing the WWESP spray system to function as an SO 2



# a bsorber.

The SO 2 

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

a s SO 2 

# flue gas concentration, fuel used, and ore composition. Since the induration furnaces at this
f acility currently employ a wet scrubbers designed for removal of particulate matter, the scrubbers also perform as low efficiency SO 2 

# wet scrubbers. The addition of a WWESP would act as a

p olishing SO 2 

# control device and would experience reduced control efficiency due to lower SO 2 

# inlet

c oncentrations. A control efficiency as a polishing WWESP ranges from 30-80% dependent upon the process specific operating parameters.

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

# reduction for this BART analysis.

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

# , is generally termed flue-gas desulfurization (FGD).
F GD 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 typically used as

s crubbing agents. Most FGD 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
d esigns for removal efficiency up to 95% SO 2 

# . Typical high efficiency SO 2 

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

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

# could be a venturi rod scrubber
d esign 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

e mission reduction.

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# 2 7 Limestone scrubbing introduces limestone slurry with the water in the scrubber. The sulfur dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in the following equations:

CaCO 3 

# + SO 2 

# → CaSO 3 

# • 1/2 H2O + CO 2 

# C aSO 3 

# •1/2 H 2 

# O + 3H 2 

# O + O 2 

# → 2 CaSO 4 

# •2 H 2 

# O

L ime 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
C a(OH) 2 

# + SO 2 

# + 1/2 O 2 

# + H 2 

# O → CaSO 4 

# •2 H 2 

# O

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

# removal reactions are as
f ollows:

Na+ + OH- + SO 2 

# + → Na 2 

# SO 3 

# 2 Na+ + 2OH- + SO 2 

# + → Na 2 

# SO 3 

# + H 2 

# O

C austic scrubbing produces a liquid waste, and requires less equipment as compared to lime or limestone scrubbers. If lime or limestone is used as the reagent for SO 2 

# removal, additional

e quipment is needed for preparing the lime/limestone slurry and collecting and concentrating the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air injection blower is needed to supply the oxygen for the second reaction to occur.

The normal SO 2 

# control efficiency range for SO 2 

# scrubbers on coal-fired utility boilers with low

e xcess air is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency scrubbers. The highest control efficiencies can be achieved when SO 2 

# concentrations are the highest. Unlike

c oal-fired boilers, indurating furnaces operate with maximum excess air to enable proper oxidation of the pellet. The excess air dilutes the SO 2 

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



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

# control efficiency of the

w et scrubber.

As previously stated, wet scrubbers are currently in place on the furnaces exhausts and are believed
to remove 15% to 30% of the SO 2 

# in the exhaust based on Barr’s experience and testing which has

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# 2 8 been completed. Taking into consideration the removal of SO 2 

# from the low-efficiency primary PM

s crubber as well as a high efficiency SO 2 

# polishing wet scrubber, an estimated overall efficiency of

t he control train would then be approximately 80%.

In theory, the SO 2 

# removal efficiency of the existing scrubbers could be improved through the

a dditions of caustic, lime, or limestone in the scrubber water to raise the pH. The existing scrubber on lines 4-7 currently operates at approximately a neutral pH. However, the scrubbers, piping, pumps and water tanks were not designed to operate at a higher pH so corrosion of the system would
be a concern. The addition of the chemicals and increased SO 2 

# removal would create additional

s olids and sulfates in the scrubber discharged to the tailings basin which would require substantial and expensive treatment to maintain an acceptable water quality which could be discharged through the existing NPDES permit. The new scrubber on Line 3 is a recirculating scrubber which operates at a pH which is typically less than 7. The scrubber was operated temporarily at a higher pH, but plugging and other operational problems resulted and the scrubber was returned to the current operating pH. Based on these concerns, the improvement of SO 2 

# removal efficiency of the existing

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

Based on the information contained within this report, a wet scrubber is considered an available technology for SO 2 

# reduction for this BART analysis.

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

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

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



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

# control

e fficiency range for dry SO 2 

# scrubbers is 70% to 90 % for coal fired utility boilers.

I nduration waste gas streams are high in water content and are exhausted at or near their dew points. Gases leaving the induration furnace are currently treated for removal of particulate matter using a wet scrubber. The exhaust temperature is typically in the range of 100°F to 150°F and is saturated with water. For comparison, a utility boiler exhaust operates at 350 °F or higher and is not saturated with water. Under induration furnace waste gas conditions, the baghouse filter cake would become saturated with moisture and plug both the filters and the dust removal system. Although this may be an available and applicable control option, it is not technically feasible due to the high moisture content and will not be further evaluated in this report.

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# 2 9 Spray Dryer Absorption (SDA) Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 

# is

a bsorbed by the slurry, forming CaSO 3 

# /CaSO 4 

# . The liquid-to-gas ratio is such that the water

e vaporates 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
d esulfurization (FGD) may also be used.

Under induration furnace waste gas conditions, the baghouse filter cake would become saturated with moisture and plug both the filters and the dust removal system. In addition, because of the moisture in the exhaust, the lime slurry would not dry properly and it would plug up the dust collection system. Similarly to the dry sorbent injection control option, this is an available and applicable control option, but is not technically feasible due to the high moisture content. This option will not be further evaluated in this report.

Energy Efficiency Projects Energy efficiency projects provide opportunities for a facility to reduce their fuel consumption, which results in lower operating costs. Typically reduced fuel usage translates into reduced air emissions. An example of an energy efficiency project would be to use waste heat 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, this facility has already implemented several energy efficiency projects. Each project carries its own fuel usage reductions and, potentially, corresponding emission reductions. It would be impossible to assign a general potential emission reduction for the energy efficient category. Due to the uncertainty and generalization of this category, this will not be further evaluated in this report. However, it should be noted that the facility 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 taconite facilities to reduce fuel costs. One option for reducing fuel costs is to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To achieve reduction of SO 2 

# emissions

t hrough alternative fuel usage, the source must be currently burning a high-sulfur fuel, typically coal, and would switch to a lower-sulfur fuel such as natural gas. However, a fuel switch would trade one visibility impairment pollutant (SO 2 

# ) for another (NO x 

# ), as induration furnaces typically emit

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# 3 0 significantly less NO x 

# when burning solid fuels. Therefore, if this option is pursued, the impact on

e missions of all visibility pollutants must be quantified and the cumulative visibility impact modeled to determine the net benefit of a particular alternative fuel.

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. 21



# T herefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility impairment pollutant for another, and the fact that BART cannot 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, the facility will continue to evaluate and implement alternate fuel usage as the feasibility arises.

Coal Processing Pre-combustion coal processing techniques have been proposed as one strategy to reduce
uncontrolled SO 2 

# emissions. Coal processing technologies are being developed to remove moisture

a nd potential contaminants from the coal prior to use.

These processes typically employ both mechanical and thermal means to increase the quality of coal by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine enters a first stage separator where it is crushed and screened to remove large rock and rock
material. 22 

# The processed coal is then passed on to an intermediate storage facility prior to being sent

t o the next stage in the process, the thermal process. In this stage, coal passes through pressure locks into the thermal processors where steam is injected. Moisture in the coal is released under these conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock and sulfur-bearing pyrites. After treatment, the coal is discharged into a second pressurized lock. The second pressurized lock is vented into a water condenser to return the processor to atmospheric pressure and to flash cool the coal. Water, removed from the process at various points, and condensed process steam are reused within the process or treated prior to being discharged.

21 

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

22 

# The coal processing description provided herein is based on the K-Fuel ® 

# process under development by KFx, Inc.

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# 3 1To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coalfired boiler. Using processed fuels at a taconite plant would require research, test burns, and extended trials to identify potential impacts on plant systems, including the furnaces, material handling, and emission control systems. Therefore, processed fuels are not considered commercially available, and will not be analyzed further in this BART analysis.

Coal drying is currently being explored at a coal-fired utility in North Dakota as a potential viable option a pre-combustion control for SO 2 

# reduction. In the process, raw coal is crushed and screened

t o remove rocks and other impurities, such as pyretic sulfur. The crushed coal is then thermally processed to remove excess moisture. For this option to be viable, excess heat or low pressure steam must be available to dry the coal. Since this heat source is not available at this facility, coal drying is not feasible and will not be further evaluated in this report.

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

# control technologies that are

a vailable and applicable to the indurating furnace process are identified in Table 5-1. The technical feasibility as determined in Step 2 is also included in Table 5-1.

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# 3 2 Table 5-1 Indurating Furnace SO 2 

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

SO 2 

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



# Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y Secondary Wet Scrubber Y Y Y Y Modifications to Existing Wet Scrubbing (Low Efficiency) Y Y N N Dry Sorbent Injection Y Y Y N Spray Dry Absorption Y Y Y N Energy Efficiency Projects Y Y Y N

Alternative Fuels Y Y Y N (not required by BART) Coal Processing Y Y Y N



# 5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies Table 5-2 describes the expected control efficiency from each of the remaining feasible control options. WWESP and wet scrubbing control options listed in Table 5-2 would be considered polishing control devices since wet scrubber currently operate as primary control.

Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness

SO 2 

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

Secondary Wet Scrubber 60%

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# 3 3 5.A.i.d STEP 4 – Evaluate Impacts and Document the Results As illustrated in Table 5-2 above, the technically feasible control technologies remaining provide varying levels of emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental impacts to better differentiate as presented below.

Economic Impacts Table 5-3 details the expected costs associated with installation of a secondary wet scrubber or a wet walled electrostatic precipitator (WWESP) after the existing scrubber on each stack. Equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S. EPA cost models. Capital costs were based on recent vendor quotations. The cost for that unit was scaled to each stack’s flow rate using the 6/10 power law as shown in the following equation:

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



# D irect and indirect costs were estimated as a percentage of the fixed capital investment using U.S. EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours per year (EPA default value). Operating costs of consumable materials, such as electricity, water, and
chemicals were established based on the U.S. EPA control cost manual 23 

# and engineering experience,

a nd were adjusted for the specific flow rates and pollutant concentrations.

Due to space considerations, 60% of the total capital investment was included in the costs to account
for a retrofit installation. 24 

# After discussions with facility staff and management, it was determined

t he 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, such as an SO 2 

# scrubber or
W WESP, 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 recent actual retrofit costs for installation of a secondary wet scrubber at the facility. The detailed cost analysis is provided in Appendix A.

23 

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

. 24 

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

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# 3 4 Table 5-3 Indurating Furnace SO 2 

# Control Cost Summary

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# 3 5 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 F. 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 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 25



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

The cost of SO 2 

# control for both of the technically feasible technologies is greater than $12,000 per

t on of pollutant removed. This cost is higher than the MPCA-directed annualized cost screening level and is far in excess of any cost that is considered to be cost effective for BART. Therefore, these alternatives are removed from further consideration in this analysis.

Energy and Environmental Issues

Because the cost of SO 2 

# controls for Minntac is so high and does not meet a reasonable definition of

c ost effective technology, these alternatives are removed from further consideration in this analysis.

5.A.i.e STEP 5 – Evaluate Visibility Impacts As previously stated in section 4 of this document, states are required to consider the degree of visibility improvement resulting from the retrofit technology, in combination with other factors such as economic, energy and other non-air quality impacts, when determining BART for an individual

25 

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

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# 3 6 source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this
document. Because the cost of SO 2 

# controls is so high and does not meet a reasonable definition of

c ost effective technology, visibility impacts were not modeled for SO 2 

# .

H owever, as previously stated, a new scrubber was installed on Line 3 after the BART baseline period and started operation on June 2006. The scrubber is considered a high efficiency scrubber for PM and a low efficiency scrubber for SO 2 

# . Since the scrubber was installed after the baseline date,

t he emissions in the post-BART modeling analysis must be adjusted to account for the improved removal efficiency. Also as previously stated, replacement and reconfigured burners were installed into the preheat section of Line 6 on April 2006 which reduced the NO X 

# emissions from the kiln of

a pproximately 10% when the preheat section was in operation. Since the low-NO X 

# burners were
i nstalled after the baseline date, the emissions in the post-BART modeling analysis must also be adjusted to account for the reduced emissions from Line 6. Therefore, the visibility impacts modeling presented in this section represent the post-baseline (i.e. post-BART) current operations of the facility.

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 projected emission rate. In the visibility impacts modeling analysis, the emissions from the Line 3 indurating furnaces were adjusted to account for the new wet scrubber and the emissions from the Line 6 indurating furnace was adjusted to account for replacement and reconfigured low-NO x 

# burners which have been installed in the preheat section. The emissions from

a ll other Subject-to-BART sources were not changed. Table 5-4 provides a summary of the modeled
SO 2 

# , NO X 

# , and PM 24-hour maximum emission rates for the post-baseline (i.e. post-BART) current

o perations. Similar to the modeling for the baseline or pre-BART operating conditions, modeling was conducted for two separate operating scenarios for fuel burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that natural gas is the only fuel that is burned in the preheat section of the kiln. The stack parameters (location, height, velocity, and temperature) were assumed to remain unchanged from the baseline modeling.

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# 3 7 Table 5-4 Indurating Furnace Post-BART SO 2 

# Control - Predicted 24-hour Maximum Emission R ates

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# 3 8 Post-BART Visibility Impacts Modeling Results Results of the post-BART visibility impacts modeling for current operations are presented in Table 5-5. 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.

As illustrated in tables 5-5, the current operation of the facility results in a visibility improvement of 0.196 dV when burning natural gas in the kiln and 0.188 dV when burning solid fuels in the kiln. Both of these values represent a 3% improvement compared to the baseline or pre-BART emissions.

A summary of visibility impacts for the total facility BART analysis are presented in Section 6.

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# 3 9 Table 5-5 Indurating Furnace Post-BART SO 2 

# Modeling Scenarios - Visibility Modeling R esults

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# 4 0 

# 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

m echanisms by which NO x 

# production occurs:

• F uel bound nitrogen compounds in the fuel are oxidized in the combustion process to NO x 

# .

• T hermal NO x 

# production arises from the thermal dissociation of nitrogen and oxygen

m olecules 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.

• P rompt NO x 

# is a form of thermal NO x 

# which is generated at the flame boundary. It is the

r esult of reactions between nitrogen and carbon radicals generated during combustion. Only
minor amounts of NO x 

# are emitted as prompt NO x 

# .

T he majority of NO x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the heater, the balance

o f NO 2 

# is formed in the atmosphere when NO reacts with oxygen in the air.

5 .A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies Step 1 identifies a comprehensive list of all potential retrofit control technologies that were evaluated. Many emerging technologies were identified that are not currently commercially available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the technology as it was understood at that time. In regards to the availability of the technology with respect to Step 1 of the BART analysis, the list has not changed from the information submitted at that time. The comprehensive list of control technologies is presented in Appendix E.

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As stated in section 2.B of this document, the technical feasibility of each option is determined by answering three specific questions:

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

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

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# 4 1 3. Are there source-specific issues/conditions that would make the control technology not technically feasible?

A preliminary list of technologies was submitted to MPCA on May 9, 2006 with the status of the technology as it was understood at that time. As work on this evaluation progressed, additional information became apparent regarding the limited scope and scale of some of the technology applications. Appendix E presents the current status of the availability and applicability of each technology.

The following section describes retrofit NO x 

# control technologies that were identified as available

a nd applicable in the May 9 submittal and discusses aspects of those technologies that determine whether or not the technology is technically feasible for the indurating furnace.

External Flue Gas Recirculation (EFGR) External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures thereby reducing thermal NO x 

# formation. In an external flue gas recirculation system, flue gas is

c ollected 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

t his technology to be effective, the combustion conditions must have the ability to be controlled at the burner tip.

The typical NO x 

# control efficiency range for EFGR on a boiler is 30% to 50%.

A pplication for EFGR technology in taconite induration is problematic for three reasons:

1. The process exhaust gas in an induration furnace has approximately 15% - 18% oxygen versus a boiler which has 2% - 3% oxygen. In a boiler, the flue gas is relatively inert so it can be used as a diluent for oxygen 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

p roduct specifications. Existing burners are designed to meet these process conditions.

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# 4 2 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

L ow-NO x 

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

# formation through

t he 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
f uel) condition. Oxygen levels and flame temperatures are low; this results in less NO x 

# formation. In

t he 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).

I f 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. In addition, the oxygen concentration cannot be controlled at the burner tip in the induration section of the furnace. Therefore, LNB is not feasible in the induration section of the permit.

However, the use LNB in the pre-heat section of the furnace is feasible and NO x 

# reductions could be

c redited for that section of the furnace. However, the NO x 

# emissions from the pre-heat section

c annot be measured separately from the total furnace NO x 

# emissions, so the actual emission reduction
f rom the burners is unknown. However, in April 2006 replacement and reconfigured burners were installed into the preheat section of Line 6. The burners were installed as an energy efficiency project. After installation of the burners, the emissions from the kiln were evaluated using the data

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# 4 3 from the NO x 

# CEMS. This analysis showed a reduction in NO X 

# emissions from the kiln of

a pproximately 10% when the preheat section was in operation. Based on this information, a 10%
reduction was assumed for the installation of low-NO x 

# burners on the preheat sections of lines 4, 5,

a nd 7 (Line 3 does not currently use burners in the preheat section). However, due to differences in design and operation of the various kilns, the 10% reduction should only be treated as an estimate as the actual emissions reduction would not be known until after installation and testing. Low-NO x 

# b urners will be considered an available and applicable technology for lines with preheat sections.

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

# burners which

a re 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

t he burner peak flame temperature was also being investigated. This technique has already been successfully used for reducing NO x 

# emissions from gas turbines. The water injection technique

s hows promise for high temperature applications, but will not be further investigated in this report as the technology is still in the research and development phase.

Induced Flue Gas Recirculation Burners Induced flue gas recirculation burners, also called ultra low-NO x 

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

# burner control technologies. The burner is designed to draw flue

g as 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
b urners in high temperature applications is 25-50%.

As previously noted, taconite furnaces are designed to operate with oxygen levels of approximately 15% to 18%. At these oxygen levels, flue gas recirculation is ineffective at NO x 

# reduction, and it

w ould adversely affect combustion because excessive amounts of oxygen would be injected into the flame pattern. In addition, IFGR relies on convective flow of flue gas through the burner and requires burners to be up-fired; meaning that the burner is mounted in the furnace floor and the flame rises up. Furthermore, IFGR is not feasible in the kiln because the reduced flame temperatures associated with IFGR could 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.

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# 4 4 Energy Efficiency Projects Energy efficiency projects provide opportunities for a facility 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, this facility has already implemented several energy efficiency projects. Each project carries its own fuel usage reductions and, potentially, corresponding emission reductions. It would be impossible to assign a general potential emission reduction for the energy efficient category. Due to the uncertainty and generalization of this category, this will not be further evaluated in this report. However, it should be noted that the facility 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. 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.

Air injection ports were installed on the kilns on Line 7 in 2001 and Line 6. The purpose of the ports is to allow air injection into the pellet bed as it travels down the kiln bed. In March 2002, Minntac submitted a report to MPCA presenting an analysis of the NO X 

# emissions from Line 7 before and

a fter the installation of the ports. This report is presented in Appendix D. As described in the report,
the NO X 

# emissions from the kiln decreased by approximately 5% when burning natural gas.
H owever, no emission reduction was noted when burning solid fuels. When evaluating the use of air injection ports for the reduction of NOx emissions, it is important to note that solid fuels are typically burned in the furnaces and therefore, the actual improvement in NOX emissions would be significantly less than 5% estimate.

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# 4 5 Alternate Fuels As described within the energy efficiency description, increased price of fuel has pushed taconite facilities to reduce fuel costs. One option for reducing fuel costs is to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To achieve reduction of SO 2 

# emissions

t hrough alternative fuel usage, the source must be currently burning a high-sulfur fuel, typically coal, and would switch to a lower-sulfur fuel such as natural gas. However, a fuel switch would trade one visibility impairment pollutant (SO 2 

# ) for another (NO x 

# ), as induration furnaces typically emit

s ignificantly less NO x 

# when burning solid fuels. Therefore, if this option is pursued, the impact on

e missions of all visibility pollutants must be quantified and the cumulative visibility impact modeled to determine the net benefit of a particular alternative fuel.

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



# T herefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility impairment pollutant for another, and the fact that BART cannot 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, the facility will continue to evaluate and implement alternate fuel usage as the feasibility arises.

Process Optimization with NO x 

# CEMS or Other Parametric Monitoring

M PCA guidance lists “NO x 

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



# e missions 27 

# . Based on conversations with MPCA staff, this work practice would include process

a djustments, or optimization, to minimize NO x 

# emissions. The impact of the process adjustments

w ould be measured using the NO x 

# CEMS. If NO x 

# CEMS are not installed, it may also be possible to

m easure the impact of the process changes using parametric monitoring.

As part of the negotiation of the draft PSD permit, Minntac has installed NO x 

# CEMS on all five
i ndurating furnaces. The use of the NO x 

# CEMS has resulted in lower emissions being reported in the

a nnual emissions inventory. However, this decrease may be due to having actual emission data available for the report rather than using the emissions from stack tests which were conducted at

26 

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

27 

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

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# 4 6 worst-case operating conditions. In addition, the NO x 

# CEMS has allowed Minntac to quantify the

e missions rates for all fuel combinations.

Although the NO x 

# CEMS has allowed the facility to use better data for reporting, the facility has not

y et identified specific operating parameters which can be controlled to reduce emissions without sacrificing unit efficiency or product quality.

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 as a control technology.
T herefore, 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

c ombustion 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

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

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# 4 7 NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NO x 

# ,

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



# e mission 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,

r esulting in nitrogen (N 2 

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO x 

# removal

a re:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[ UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (2)

N SCR 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

g as 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

n ormal 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 to 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

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# 4 8 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 benefit of RSCR compared to SCR is that it has a thermal efficiency of 90% - 95% versus the heat exchange system in a reheat SCR system which has a thermal efficiency of 60% to
70%.

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.

There are several concerns about the technical feasibility and applicability of SCR 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 SCR;

• The taconite dust is highly erosive and can cause significantly equipment damage. R-SCR 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;

• SCR 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;

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# 4 9 • SCR catalyst had been shown to oxidize mercury. Oxidized mercury can be absorbed by the local environment and have adverse impact. The impact of SCR on mercury emissions needs to be studied to determine whether or not mercury oxidation is a problem and to identify mitigation methods if needed.

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.

However, 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,

a nd 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®.

N O + O 3 

# → N O 2 

# + O 2 

# (1)

N O 2 

# + O 3 

# → N O 3 

# + O 2 

# (2)

N O 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O → 2 HNO 3 

# (4)

H NO 3 

# + NaOH → N aNO 3 

# + H 2 

# O (5)

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# 5 0 Low Temperature Oxidation (Tri-NO x ® 

# )

T his technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

# in a

p rimary scrubbing stage. Then NO 2 

# is removed through caustic scrubbing in a secondary stage. The

r eactions 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

a ssigned 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

s tages reduce NO 2 

# to nitrogen gas, while the oxygen becomes part of a soluble salt. Another possible

a dvantage of the Tri-NO x ® 

# process is that concurrent scrubbing of sulfuric acid mist can be achieved.
T ri-NO x ® 

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

# concentration in the

e xhaust gas (1,000 ppm NO x 

# ). NO x 

# concentrations in taconite exhaust are typically no higher than
3 00 ppm. Therefore, Tri-NO x ® 

# is not applicable to taconite processing and will not be analyzed
f urther in this BART analysis.

Low Temperature Oxidation (LoTOx ® 

# )

B OC Gases’ Lo-TOx ® 

# is an example of a version of an LTO system. LoTOx ® 

# technology uses ozone

t o 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

s crubber used for particulate or sulfur dioxide removal, The N 2 

# O 5 

# is converted to HNO 3 

# in a

s crubber, and is removed with lime or caustic. Ozone for LoTOx ® 

# is generated on site with an

e lectrically 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

e conomically 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 applies to an indurating furnace, the technology has not been demonstrated on a taconite pellet indurating furnace. This raises uncertainties about how or whether the technology will transfer. The second component of the technical feasibility review includes determining if the

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# 5 1 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
f low rates from 150 – 35,000 acfm, which is quite small, compared to the indurating furnace flue gas flow rates of more than 500,000 acfm. This large scale-up is contrary to good engineering practices and could be problematic in maintaining the current removal efficiencies.

In addition, only two of BOC’s LoTOx ® 

# installations are fully installed and operational applications.
T herefore, 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

o zone to form hematite (Fe 2 

# O 3 

# ); since the ozone injection point would be before the scrubber,

t here can be more than 400 pounds per hour of taconite dust in the flue gas which could consume a significant amount of the ozone being generated which may change the reaction kinetics; consequently, this would necessitate either an increase in the amount of ozone generated or a decrease in the estimated control efficiency;

• The ozone that would be injected into the flue gas would react with the SO 2 

# , converting the

m aterial to SO 3 

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

• S ince 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.

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# 5 2 In addition, 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.

Step 2 Conclusion Based upon the determination within Step 2, the remaining NO x 

# control technologies that are

a vailable 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 5-6.

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# 5 3 Table 5-6 Indurating Furnace NO x 

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

SO 2 

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



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

Low-N 

# O x 

# Burners Y Y Y (preheat section) Y

Induced Flue Gas Recirculation Burners Y Y N --- Energy Efficiency Projects Y Y Y N Ported Kilns Y Y Y Y

Alternative Fuels Y Y N N (not required by BART) Process Optimization using 

# NO x 

# CEMS Y Y Y N Non-Selective Catalytic Reduction (NSCR) Y N --- --- Selective Catalytic Reduction (SCR) with conventional reheat Y Y Y Y

Regenerative SCR Y N --- --- Selective Non-Catalytic Reduction (SNCR) Y N --- --- Low Temperature Oxidation (LTO) Y N --- ---

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# 5 4 5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies Table 5-7 describes the expected control efficiency from each of the remaining technically feasible control options as identified in Step 2.

Table 5-7 Indurating Furnace NO x 

# Control Technology Effectiveness



# NO x 

# Pollution Control Technology Approximate Control Efficiency SCR with Conventional Reheat 80%

Low-N 

# O x 

# Burners 1 0%
Ported Kilns 5%



# 5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results Table 5-8 details the expected costs associated with installation of SCR with conventional reheat, low
NO x 

# burners, ported kilns, and a combination of low-NO x 

# burners and ported kilns.

E quipment design was based on the maximum 24-hour emissions, vendor estimates (when available), 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



# D irect and indirect costs were estimated as a percentage of the fixed capital investment using U.S. EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours per year. Operating costs of consumable materials, such as electricity, water, and chemicals were
established based on the U.S. EPA control cost manual 28 

# and engineering experience, and were

a djusted for the specific flow rates and pollutant concentrations.

28 

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

.

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# 5 5 Table 5-8 Indurating Furnace NO x 

# Control Cost Summary

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# 5 6 Due to space considerations, 60% 29 

# of the total capital investment was included in the costs to

a ccount 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.

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 F. 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 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 30



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

29 

# U.S. EPA, C UE Cost Workbook Version 1.0 . Page 2. 30 

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

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# 5 7 The cost of NO x 

# control for using SCR with conventional reheat is far in excess of any cost that is

c onsidered to be cost effective for BART, or even for BACT. Therefore, this technology is not carried forward in the analysis. The costs for ported kilns, low-NO x 

# burners, and ported kilns with
l ow-NO x 

# burners, where appropriate, are below the MPCA recommended screening threshold of $ 12,000 per ton, and therefore are carried forward in the BART analysis.

Energy and Environmental Issues The energy and non-air quality impacts for ported kilns, low-NO x 

# burners, and ported kilns with lowN O x 

# burners, where appropriate, are presented in Table 5-9.

Table 5-9 Indurating Furnace NO x 

# Control Technology Impacts Assessment
Control Technology Energy Impacts Other Impacts
Ported Kilns • None • None

Low-N 

# O x 

# Burners • Improved efficiency of preheat section • None
Ported Kilns with
Low-N 

# O x 

# Burners • Improved efficiency of preheat section • None



# 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.

However, as previously stated, a new scrubber was installed on Line 3 after the BART baseline period and started operation in June 2006. The scrubber is considered a high efficiency scrubber for PM and a low efficiency scrubber for SO 2 

# . Since the scrubber was installed after the baseline date,

t he emissions in the post-BART modeling analysis must be adjusted to account for the improved removal efficiency. Also as previously stated, replacement and reconfigured burners were installed into the preheat section of Line 6 which reduced the NO X 

# emissions from the kiln of approximately
1 0% when the preheat section was in operation. Since the low-NO X 

# burners were installed after the
b aseline date, the emissions in the post-BART modeling analysis must also be adjusted to account for

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# 5 8 the reduced emissions from Line 6. Therefore, the visibility impacts modeling presented in this section represent the post-baseline (i.e. post-BART) current operations of the facility.

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 amaximum 24-hour average projected emission rate. Similar to the modeling for the baseline or preBART operating conditions, modeling was conducted for two separate operating scenarios for fuel burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that natural gas is the only fuel that is burned in the preheat section of the kiln. The stack parameters (location, height, velocity, and temperature) were assumed to remain unchanged from the baseline modeling. In the visibility impacts modeling analysis, the emissions were adjusted as follows:

• Line 3 indurating furnaces emissions were adjusted to account for the new wet scrubber and the emissions;

• Line 6 indurating furnace emissions were adjusted to account for the replacement and reconfigured low-NO x 

# burners which have been installed in the preheat section.

• T he emissions during current operations for all indurating furnaces were adjusted for each control technology, as appropriate; and

• The emissions from all other Subject-to-BART sources were not changed.

Table 5-10 provides a summary of the modeled SO 2 

# , NO X 

# , and PM 24-hour maximum emission rates
f or the post-baseline (i.e. post-BART) current operations.

Post-BART Visibility Impacts Modeling Results Results of the post-BART visibility impacts modeling for current operations are presented in Table 5-11. 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. As illustrated in tables 5-11, post-BART modeled visibility improvements are as follows:

• The current operation of the facility results in a visibility improvement of 0.196 dV when burning natural gas in the kiln and 0.188 dV when burning solid fuels in the kiln. Both of these values represent a 3% improvement compared to the baseline emissions.

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# 5 9 • The installation of ported kilns on lines 3, 4, and 5 could result in a visibility improvement of 0.330 dV when burning natural gas in the kiln, which represents a 5% improvement from the baseline when burning natural gas in the kiln. Since ported kilns do not reduce emissions when burning solid fuels, there is no additional visibility improvement for that scenario compared to current operations. It is very important to note that normal operation of the indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no improvement in visibility for ported kilns under normal operation.

• The installation of low-NO x 

# burners on the preheat sections of lines 4, 5, and 7 results in a

v isibility improvement of 0.488 dV when burning natural gas in the kiln, and 0.465 dV when burning solid fuels in the kiln. Both of these values represent a 7% improvement compared
to the baseline emissions.

• The combined installation of ported kilns on lines 3, 4, and 5 and low-NO x 

# burners on lines 4,
5 , and 7 results in a visibility improvement of 0.627 dV when burning natural gas in the kiln and 0.465 dV when burning solid fuels in the kiln. Since ported kilns do not reduce emissions when burning solid fuels, it is again very important to note that normal operation of the indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no improvement in visibility for ported kilns under normal operation and the visibility improvement for normal operation is only due to the low-NOX burners on the preheat sections of lines 4, 5, and 7.

A summary of visibility impacts for the total facility BART analysis are presented in Section 6.

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# 6 0 Table 5-10 Indurating Furnace Post- BART NO X 

# Control - Predicted 24-hour Maximum E mission Rates

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# 6 1 Table 5-11 Indurating Furnace Post-BART NO X 

# Modeling Scenarios - Visibility Modeling R esults

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# 6 2 

# 5.B External Combustion Sources Five utility plant heating boilers are subject-to-BART at this facility. As shown in section 4, the five
b oilers underwent a streamlined analysis for SO 2 

# and PM and one of the boilers underwent a

s treamlined analysis for NO x 

# . Therefore, the remaining four boilers require a full BART analysis for
N O X 

# .

T he utility plant heating boilers are permitted to burn natural gas and fuel oil. The boilers are generally operated on a seasonal basis to provide heat to the facility. The highest emitting days are typically cold days in which the facility has a high heat demand and on which a natural gas curtailment occurs which requires the burning of the higher-emitting fuel oil.


# 5.B.i Nitrogen Oxide Controls

To be able to control NO x 

# it is important to understand how NO x 

# is formed. There are three

m echanisms by which NO x 

# production occurs:

• F uel bound nitrogen compounds in the fuel are oxidized in the combustion process to NO x 

# .

• T hermal NO x 

# production arises from the thermal dissociation of nitrogen and oxygen

m olecules 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.
C onditions for formation of thermal NO x 

# exist primarily in the burner flame.

• P rompt NO x 

# is a form of thermal NO x 

# which is generated at the flame boundary. It is the

r esult of reactions between nitrogen and carbon radicals generated during combustion. Only
minor amounts of NO x 

# are emitted as prompt NO x 

# .

T he majority of NO x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the heater, the balance

o f NO 2 

# is formed in the atmosphere when NO reacts with oxygen in the air.

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

# is formed, available and applicable control technologies were

e valuated. Step 1 identifies a comprehensive list of all potential retrofit control technologies that were evaluated. Many emerging technologies were identified that are not currently commercially

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# 6 3 available. Appendix G presents the current status of the availability and applicability of each technology.

5.B.i.b STEP 2 – Eliminate Technically Infeasible Options Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As stated in section 2.B of this document, the technical feasibility of each option is determined by answering three specific questions:

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

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

3. Are there source-specific issues/conditions that would make the control technology not technically feasible?

The following describes retrofit NO x 

# control technologies that were identified as available and

a pplicable 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

r educing thermal NO x 

# formation. In an external flue gas recirculation system, flue gas is collected from the
h eater 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 a boiler to accommodate EFGR, air ducts and registers

n eed to be able to withstand higher temperatures and flow rates, burners must be able to produce a stable flame with the flue gas added, and the firebox must be able to accommodate longer flame length to avoid flame impingement. Based on conversations with utility plant staff, the existing equipment cannot meet these requirements. Therefore, this option is not technically feasible and will not be further evaluated in this report.



# Low NO x 

# Burners (LNB)

L ow-NO x 

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

# formation through

t he 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, NO x 

# formation

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# 6 4 is limited by either one of two methods. Under staged air rich (high fuel) condition, low oxygen levels limit flame temperatures resulting in less NO x 

# 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

t he primary zone act to lower the local oxygen concentration, resulting in a decrease in NO x 

# f ormation. Low NO x 

# burners typically achieve NO x 

# emission reductions of 25% - 50% for process
b oilers. LNB is a technology commonly used on boilers and is considered a available and applicable technology.

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 the typical NO x 

# control technology used in
b oilers and is primarily geared to reduce thermal NO x 

# . Staging of the combustion air creates an initial
f uel-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

c ombustion zone where NO x 

# is most likely to be formed. LNB is a technology commonly used on
b oilers and is considered a available and applicable technology. In addition, OFA can also be used in
combination with LNB.

Induced Flue Gas Recirculation Burners Induced flue gas recirculation burners, also called ultra low-NO x 

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

# burner control technologies. The burner is designed to draw flue

g as 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
b urners in high temperature applications is 50-75%. This technology is considered an available and applicable technology.

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# 6 5 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 example energy efficiency project would be to reduce steam consumption which would decrease fuel burning requirements. 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, Minntac has already implemented several 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 Minntac will continue to evaluate and implement energy efficiency projects as they arise.

Alternate Fuels The increased price of fuel has pushed companies to evaluate alternate fuel consumption and available fuel sources. These fuel sources come in all forms – solid, liquid and gas. The heating boilers at Minntac are capable of burning natural gas and fuel oil. Since the boilers do not burn solid fuels, the options for alternate fuels are limited. Normal operation is on natural gas which is generally the lowest emitting fuel for a boiler.

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. 31



# T herefore, due to the uncertainty of alternative fuel costs, the limited options available, the fact that natural gas is the typical fuel burned in 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, Minntac will continue to evaluate and implement alternate fuel usage as the feasibility arises.

31 

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

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# 6 6 Post Combustion Controls

NO x 

# can be controlled using add-on systems located downstream of the boiler combustion process.
T he 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

a re 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 

# ,

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



# e mission 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,

r esulting in nitrogen (N 2 

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO x 

# removal

a re:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[ UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (2)

N SCR 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. Since the highest emitting days occur while burning fuel oil, 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

g as stream in the presence of a catalyst. NO x 

# is removed through the following chemical reaction:

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# 6 7 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

n ormal 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 benefit of RSCR compared to SCR is that it has a thermal efficiency of 90% - 95% versus the heat exchange system in a reheat SCR system which has a thermal efficiency of 60% to
70%.

SCR and R-SCR have both been applied to boilers. Although there may be concerns about the actual applicability of the technology to the boilers at this facility, the technologies will be considered feasible for the purposes of this report.

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%.
W ithout a catalyst, the reaction requires a high temperature range to obtain activation energy. The
relevant reactions are as follows:

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# 6 8 

# NO + NH 3 

# + 1⁄4O 2 

# → N 2 

# + 3/2 

# H 2 

# O (1)

N H 3 

# + 1⁄4O 2 

# → N O + 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,

a nd 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®.

N O + O 3 

# → N O 2 

# + O 2 

# (1)

N O 2 

# + O 3 

# → N O 3 

# + O 2 

# (2)

N O 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O → 2 HNO 3 

# (4)

H NO 3 

# + NaOH → N aNO 3 

# + H 2 

# O (5)

L ow Temperature Oxidation (Tri-NO x ® 

# )

T his technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

# in a

p rimary scrubbing stage. Then NO 2 

# is removed through caustic scrubbing in a secondary stage. The

r eactions 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

a ssigned 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

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# 6 9 stages reduce NO 2 

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

# is

t ypically applied at small to medium sized sources with high NO x 

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

# ).

L ow Temperature Oxidation (LoTOx ® 

# )

B OC Gases’ Lo-TOx ® 

# is an example of a version of an LTO system. LoTOx ® 

# technology uses ozone

t o 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

s crubber used for particulate or sulfur dioxide removal, The N 2 

# O 5 

# is converted to HNO 3 

# in a

s crubber, and is removed with lime or caustic. Ozone for LoTOx ® 

# is generated on site with an

e lectrically 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

e conomically feasible, a source of low cost oxygen must be available from a pipeline or on site generation.

Although only two of BOC’s LoTOx ® 

# installations are fully installed and operational applications,
L oTOx has been applied to gas and coal fired boilers. Therefore, although LoTOx is an emerging technology, has limited installations, and there may be concerns about the actual applicability of the technology to the boilers at this facility, the technologies will be considered feasible for the purposes of this report.

Step 2 Conclusion Based upon the determination within Step 2, the remaining NO x 

# control technologies that are

a vailable and applicable to the indurating furnace process are identified in Table 5-12. The technical feasibility as determined in Step 2 is also included in Table 5-13.

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# 7 0 Table 5-12 Boiler NO x 

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

SO 2 

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



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

# O x 

# Burners Y Y Y Y Overfired Air Y Y Y Y Induced Flue Gas Recirculation (IFGR) Y Y Y Y Energy Efficiency Projects Y Y Y N Alternative Fuels Y Y Y N Non-Selective Catalytic Reduction (NSCR) Y Y Y N Selective Catalytic Reduction (SCR) Y Y Y Y Regenerative SCR Y Y Y Y Selective Non-Catalytic Reduction (SNCR) Y Y Y Y Low Temperature Oxidation (LTO) Y Y Y Y



# 5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies Table 5-13 describes the expected control efficiency from each of the remaining technically feasible control options as identified in Step 2.

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# 7 1 Table 5-13 Boiler NO x 

# Control Technology Effectiveness

NOx Pollution Control Technology Approximate Control Efficiency LoTOx 90% SCR 80%
Low-N 

# O x 

# Burners with IFGR 7 5%
R-SCR 70%
Low-N 

# O x 

# Burners with OFA 6 7%
Low-N 

# O x 

# Burners 5 0% Selective Non-Catalytic Reduction (SNCR) 50%



# 5.B.i.d STEP 4 – Evaluate Impacts and Document the Results Table 5-14 details the expected costs associated with installation of NO x 

# controls. Capital costs were

c alculated 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 3,156 operating hours per year, which is based on historic operating records. Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant concentrations. Where applicable, 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 detailed cost analysis is provided in Appendix A.

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective air pollution controls in the electric utility industry for large power plants are in the range $1,000 to $1,300 per ton removed as illustrated in Appendix F. 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 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.

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# 7 2 Table 5-14 Boiler NO x 

# Control Cost Summary

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# 7 3 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



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

The costs of NO x 

# control for SCR, low-NOx burners with flue gas recirculation, low-NO X 

# burners

w ith overfire air, and SNCR are far in excess of any cost that is considered to be cost effective for BART, or even for BACT. Therefore, these technologies are not carried forward in the analysis.
The costs for low-NO x 

# burners are below the MPCA recommended screening threshold of $12,000

p er ton, and therefore are carried forward in the BART analysis.

Energy and Environmental Impacts The energy and environmental impacts for low-NO x 

# burners are minimal.

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.

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. The stack parameters (location, height, velocity, and temperature) were assumed to remain unchanged from the baseline modeling.

Table 5-15 provides a summary of the modeled NO X 

# 24-hour maximum emission rates for the postb aseline (i.e. post-BART) operating scenario for installing low-NO X 

# burners on the four boilers.

32 

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

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# 7 4 Post-BART Visibility Impacts Modeling Results Results of the post-BART visibility impacts modeling 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. As illustrated in tables 5-16, post-BART modeled visibility improvements are as
follows:

• The installation of low-NO x 

# burners on the boilers results in a visibility improvement of
0 .008 dV which is a 0.1% improvement compared to the baseline emissions. Based on these modeling results, the visibility improvement for the installation of low-NO x 

# burners on the
b oilers is basically negligible.

A summary of visibility impacts for the total facility BART analysis are presented in Section 6.

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# 7 5 Table 5-15 Boiler Post-BART NO X 

# Control - Predicted 24-hour Maximum Emission Rates

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# 7 6 Table 5-16 Boiler Post-BART NO X 

# Modeling Scenarios - Visibility Modeling Results

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# 7 7 

# 6. Visibility Impacts

As previously stated in section 4 of this document, states are required to consider the degree of visibility improvement resulting from the retrofit technology, in combination with other factors such as economic, energy and other non-air quality, when determining BART for an individual source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document. The visibility impacts of individual control technologies were presented in Step 5 of sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e. This section of the report evaluates the various BART control scenarios utilizing both SO 2 

# and NO x 

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

T he intent of this section is to present the modeling scenarios for combinations of SO 2 

# and NO x



# c ontrols. However, since there were no control technologies for SO 2 

# that required visibility impacts

a nalysis, there are no SO 2 

# /NO x 

# combinations that need to be evaluated. Therefore, no new or

a dditional modeling scenarios are presented in this section. 

# 6.A Post-BART Modeling Scenarios All of the modeling scenario results, as presented in sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e or this

r eport, are presented in Table 6-1. As previously stated, no new or additional modeling scenarios are presented. 

# 6.B Post-BART Modeling Results Results of all post-BART modeling scenarios are presented in Table 6-1. These results were also

p resented in Step 5 of sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e. As previously stated, no new or additional modeling scenarios are presented. 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.

When reviewing the modeling results for the indurating furnaces, it is important to note the following:

• Current Operation:

o The current operation of the facility results in a visibility improvement of 0.196 dV when burning natural gas in the kiln and 0.188 dV when burning solid fuels in the kiln. Both of these values represent a 3% improvement compared to the baseline
emissions.

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# 7 8 • Ported Kilns:

o Natural Gas Operation: The installation of ported kilns on lines 3, 4, and 5 results in a visibility improvement of 0.330 dV when burning natural gas in the kiln, which represents an addition 0.134 dV compared to the current operation when burning natural gas in the kiln. This is a 5% improvement from the baseline when burning natural gas in the kiln and a 2% improvement from the current operation when burning natural gas in the kiln.

o Solid Fuel Operation: Since ported kilns do not reduce emissions when burning solid fuels, there is no additional visibility improvement for that scenario compared to current operations. It is very important to note that normal operation of the indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no improvement in visibility for ported kilns under normal operation.

• Low-NO X 

# Burners:

o N atural Gas Operation: The installation of low-NO x 

# burners on the preheat sections

o f lines 4, 5, and 7 results in a visibility improvement of 0.488 dV when burning natural gas in the kiln which represents an addition 0.292 dV compared to the current operation when burning natural gas in the kiln. This is a 7% improvement from the baseline when burning natural gas and a 4% improvement from the current operation when burning natural gas.

o Solid Fuel Operation: The installation of low-NO x 

# burners on the preheat sections of
l ines 4, 5, and 7 results in a visibility improvement of 0.465 dV when burning solid fuels in the kiln which represents an addition 0.277 dV compared to the current operation when burning solid fuels in the kiln. This is a 7% improvement from the baseline when burning solid fuels in the kiln and a 4% improvement from the current operation when burning solid fuels in the kiln.

• Ported Kilns with Low-NO X 

# Burners:

o N atural Gas Operation: The combined installation of ported kilns on lines 3, 4, and 5
and low-NO x 

# burners on lines 4, 5, and 7 results in a visibility improvement of 0.627
d V when burning natural gas in the kiln which represents an addition 0.431 dV

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# 7 9 compared to the current operation when burning natural gas in the kiln. This is a 9% improvement from the baseline when burning natural gas in the kiln and a 6% improvement from the current operation when burning natural gas in the kiln.

o Solid Fuel Operation: The combined installation of ported kilns on lines 3, 4, and 5
and low-NO x 

# burners on lines 4, 5, and 7 results in a visibility improvement of 0.465
d V when burning solid fuels in the kiln which represents an addition 0.277 dV compared to the current operation when burning solid fuels in the kiln. This is a 7% improvement from the baseline when burning solid fuels in the kiln and a 7% improvement from the current operation when burning solid fuels in the kiln.

When reviewing the modeling results for the boilers, it is important to note the following:

• The installation of low-NO x 

# burners on the boilers results in a visibility improvement of
0 .008 dV which is a 0.1% improvement compared to the baseline emissions. Based on these modeling results, the visibility improvement for the installation of low-NO x 

# burners on the
b oilers is basically negligible.

## Minntac BART Report September 8, 2006

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# 8 0 Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results

## Minntac BART Report September 8, 2006

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# 8 1 

# 7. Select BART

The final step in the BART analysis is to select the “best alternative” using the results of steps 1 through 5, as presented in section 5 of this report. 

# 7.A Indurating Furnaces Minntac operates five indurating furnaces which are subject-to-BART:

• L ine 3 Rotary Kiln (EU 225 / SV 103)

• Line 4 Rotary Kiln (EU 261 / SV 118)

• Line 5 Rotary Kiln (EU 282 / SV 127)

• Line 6 Rotary Kiln (EU 315 / SV 144)

• Line 7 Rotary Kiln (EU 334 / SV 151)

As presented in section 3 of the report, the PM emissions from the indurating furnaces were subject to a streamlined BART analysis based on the specific provision that compliance with the Taconite MACT (40 CFR Part 63 Subpart RRRRR) for PM emissions is equivalent to BART. The Taconite MACT standard includes requirements for performance testing and continuous parametric monitoring for compliance demonstration.

As presented in section 5.A of this report, the five indurating furnaces at Minntac were required to undergo a full BART analysis for NO x 

# and SO 2 

# .

A s presented in section 5.A of this report, the indurating furnace was required to undergo a full BART analysis for SO 2 

# and NO x 

# . The selection is based on consideration of all of the criteria

p resented in MPCA and U.S. EPA guidance for determining BART, as presented in this report.

The following technologies were identified as technically feasible and subject to the full BART analysis: new wet scrubbers that control PM and SO 2 

# , add-on secondary wet scrubber to control

a dditional SO 2 

# control, ported kiln, SCR (with conventional flue gas reheat), and NO x 

# CEMS. The

s econdary wet scrubber, ported kiln, and SCR alternatives were not proposed as BART for the following reasons:

## Minntac BART Report September 8, 2006

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# 8 2 Ported Kiln
Converting the kilns 3, 4 and 5 to ported kilns would result in only an estimated 5% decrease
in NO x 

# emissions when burning gas in the kiln and the corresponding impact on visibility is

a lso minimal. It would not result in emissions reductions when burning solid fuel in the kiln, which is the primary fuel used by Minntac. Therefore, the technology will not result in any significant visibility improvement at the Class I areas compared to the current operation. Further, it is not cost effective at an estimated amount of more than $5,000/ton NO x 

# removed.

B ased on the consideration of all of the criteria presented in the BART analysis, Minntac proposes the following as BART for SO 2 

# and NO X 

# for the Indurating Furnaces:

• B ART for SO 2 

# :

o S O 2 

# emissions will be controlled by the existing wet scrubbers, which will be

o perated as required in accordance with provisions of the Taconite MACT.

o SO 2 

# emission limit for the Indurating Furnace on Line 3 will be determined based

o n upcoming performance testing to determine the actual emission rate from the furnace with the addition of the new scrubber. A proposed SO 2 

# limit for the
f urnace in the draft PSD permit for Minntac does not reflect the recently installed
wet scrubber.

o SO 2 

# emission limits for the Indurating Furnaces on lines 4, 5, 6, and 7 will be the
l imits which are based on using the existing wet scrubbers and reflect air dispersion modeling results for regional haze as proposed in the draft PSD permit:

⋅ Line 4 = 182 lbs/hr

⋅ Line 5 = 182 lbs/hr

⋅ Line 6 = 284 lbs/hr

⋅ Line 7 = 284 lbs/hr

o Compliance will be initially be demonstrated by a performance test at each
furnace.

## Minntac BART Report September 8, 2006

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# 8 3 o Continuous compliance will be demonstrated by continuous monitoring of scrubber water flow rate and scrubber pressure drop, which are the same parameters that will be monitored under the Taconite MACT. The operating
limits will be determined based on the initial SO 2 

# compliance test and will be
b ased on a 24-hour block average, consistent with the Taconite MACT.

• BART for NO x 

# :

o N O x 

# emissions will be controlled as follows:

⋅ L ine 3: Existing combustion controls and fuel blending. Line 3 does not currently use burners in its pre-heat section, and therefore low-NO x 

# burners

c annot be applied at this furnace.

⋅ Line 4: Installation of low-NO x 

# burners on the pre-heat section, existing

c ombustion controls, and fuel blending.

⋅ Line 5: Installation of low-NO x 

# burners on the pre-heat section, existing

c ombustion controls, and fuel blending.

⋅ Line 6: Operation of low-NO x 

# burners on the pre-heat section (installed as

r eplacement and reconfigured burners in April 2006), existing combustion controls, and fuel blending.

⋅ Line 7: Installation of low-NO x 

# burners on the pre-heat section, existing

c ombustion controls, and fuel blending.

o NO x 

# emission limits will be proposed by the facility 12-months after the
i nstallation of the low-NO x 

# burners to allow the facility sufficient time for

p rocess and emissions monitoring using NO x 

# CEMS to determine the actual

e mission rates under a variety of operating conditions. Although the facility anticipates a significant reduction in NO x 

# emissions with the installation of the
l ow-NO x 

# burners, the actual emissions reduction cannot be determined until the
b urners are operated under a variety of operation conditions.

## Minntac BART Report September 8, 2006

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# 8 4 o Initial and continuous compliance will be demonstrated after the appropriate emission limits have been determined. Compliance will be demonstrated using
the NO x 

# CEMS and will be based on a 30-day rolling average.

T he schedule for implementation of these controls, specifically installation of low-NO x 

# burners and

s ubsequent testing to demonstrate the appropriate BART emission limit, will be within the 5-year time-frame required for BART implementation. In addition, Minntac will continue to evaluate energy efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission

rates.

Using the modeling protocol as described above and a NOx emission reduction estimate of 10% for
the installation of low-NO x 

# burners, the proposed BART controls will result in visibility
i mprovement on the 98 th 

# percentile day of approximately 0.488 dV when burning gas in the kiln and
0 .465 dV when burning solid fuels in the kiln. This is a visibility improvement of approximately 7% compared to the baseline (pre-BART) operating conditions.



# 7.B External Combustion Sources Minntac operates 5 utility plant heating boilers which are subject-to-BART:

o U tility Plant Heating Boiler #1 (EU 001 / SV 001)

o Utility Plant Heating Boiler #2 (EU 002 / SV 002)

o Utility Plant Heating Boiler #3 (EU 003 / SV 003)

o Utility Plant Heating Boiler #4 (EU 004 / SV 004)

o Utility Plant Heating Boiler #5 (EU 005 / SV 005)

As presented in section 3 of the report, the SO 2 

# and PM emissions from all five boilers underwent a

s treamlined BART analysis based on the de minimis modeling results as presented in section 3.F. In addition, the NO x 

# emissions from boiler #3 underwent a streamlined BART analysis for NO x 

# . Based

o n the consideration of all of the criteria presented in the BART analysis, Minntac proposes no additional controls, emission limits, or monitoring requirements for the NO x 

# emissions from four
h eating boilers. This is based on the conclusion that the control technologies that meet the cost screening threshold do not provide significant improvement in the visibility modeling. It is also

## Minntac BART Report September 8, 2006

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# 8 5 important to note that due to the relatively small size of the boilers and the low hours of operation, the actual visibility impact of the boilers is small.Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions Required3.A. Indurating FurnacesEU 223Traveling Grate (Line 3)------655.2 0.01 SV 103 BART Analysis for SO2 + NOxEU 225Rotary Kiln (Line 3)------ Incl with EU223 0.01 SV 103 BART Analysis for SO2 + NOxEU 226 Pellet Cooler Secondary Air (Line 3)------ Incl with EU223 0.01 SV 103 BART Analysis for SO2 + NOxEU 259Traveling Grate (Line 4)------1,504.8 0.01 SV 118 BART Analysis for SO2 + NOxEU 260 Recouperative System Air (Line 4)------ Incl with EU259 0.01 SV 118 BART Analysis for SO2 + NOxEU 261Rotary Kiln (Line 4)------ Incl with EU259 0.01 SV 118 BART Analysis for SO2 + NOxEU 262 Pellet Cooler Secondary Air (Line 4)------ Incl with EU259 0.01 SV 118 BART Analysis for SO2 + NOxEU 280Traveling Grate (Line 5)------2,568.0 0.01 SV 127 BART Analysis for SO2 + NOxEU 281 Recouperative System Air (Line 5)------ Incl with EU280 0.01 SV 127 BART Analysis for SO2 + NOxEU 282Rotary Kiln (Line 5)------ Incl with EU280 0.01 SV 127 BART Analysis for SO2 + NOxEU 283 Pellet Cooler Secondary Air (Line 5)------ Incl with EU280 0.01 SV 127 BART Analysis for SO2 + NOxEU 313Traveling Grate (Line 6)------1,944.0 0.01 SV 144 BART Analysis for SO2 + NOxEU 314Recoup System (Line 6)------ Incl with EU314 0.01 SV 144 BART Analysis for SO2 + NOxEU 315Rotary Kiln (Line 6)------ Incl with EU314 0.01 SV 144 BART Analysis for SO2 + NOxEU 316 Pellet Cooler Secondary Air (Line 6)------ Incl with EU314 0.01 SV 144 BART Analysis for SO2 + NOxEU 332Traveling Grate (Line 7)------1,968.0 0.01 SV 151 BART Analysis for SO2 + NOxEU 333Recoup System (Line 7)------ Incl with EU332 0.01 SV 151 BART Analysis for SO2 + NOxEU 334Rotary Kiln (Line 7)------ Incl with EU332 0.01 SV 151 BART Analysis for SO2 + NOxEU 335 Pellet Cooler Secondary Air (Line 7)------ Incl with EU332 0.01 SV 151 BART Analysis for SO2 + NOx3.B. PM-Only Taconite MACT Emission UnitsEU 013Dump Pocket------62.4 0.008 SV 013NoneEU 014Crusher------ Incl with EU013 0.008 SV 013NoneEU 015Dump Pocket------62.4 0.008 SV 014NoneEU 016Crusher------ Incl with EU015 0.008 SV 014NoneEU 017Dump Pocket------62.4 0.008 SV 015NoneEU 018Crusher------ Incl with EU017 0.008 SV 015NoneEU 019Dump Pocket------ Incl with EU017 0.008 SV 015NoneEU 020Crusher------ Incl with EU017 0.008 SV 015NoneEU 022Pre-1969 Panfeeder------11.0 0.008 SV 016NoneEU 023Pre-1969 Panfeeder------ Incl with EU022 0.008 SV 016NoneEU 024Pre-1969 Panfeeder------11.0 0.008 SV 017NoneEU 025Pre-1969 Panfeeder------ Incl with EU024 0.008 SV 017NoneEU 026Post-1969 Panfeeder------11.0 0.008 SV 018NoneEU 027Post-1969 Panfeeder------ Incl with EU026 0.008 SV 018NoneEU 034 Ore Transfer From 061-02-1 to 005-02-1------31.2 0.008 SV 021NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 035 Ore Transfer From 061-02-1 to 005-02-1------ Incl with EU034 0.008 SV 021NoneEU 036 Ore Transfer From 061-03-1 to 010-01-1------31.2 0.008 SV 022NoneEU 037 Ore Transfer Fr 004-01-1 to Turn Bin 060-01-1------ Incl with EU036 0.008 SV 022NoneEU 038 Ore Transfer Fr 004-02-1 to Turn Bin 060-01-1------ Incl with EU036 0.008 SV 022NoneEU 039 Ore Transfer From 011-01-1 to 060-01-1------ Incl with EU036 0.008 SV 022NoneEU 040 Ore Transfer From 061-01-1 to 005-01-1------31.2 0.008 SV 023NoneEU 041 Ore Transfer From 061-08-1 to 010-02-1------31.2 0.008 SV 024NoneEU 042 Ore Transfer From 061-07-1 to 005-03-1------ Incl with EU041 0.008 SV 024NoneEU 043 Ore Transfer From 061-06-1 to 005-04-1------ Incl with EU041 0.008 SV 024NoneEU 044 Ore Transfer From 011-03-1 to Turn Bin------ Incl with EU041 0.008 SV 024NoneEU 045 Ore Transfer From 004-03-1 to Turn Bin------ Incl with EU041 0.008 SV 024NoneEU 046 Ore Transfer From 004-04-1 to Turn Bin------ Incl with EU041 0.008 SV 024NoneEU 047 Ore Transfer From 011-02-1 to 011-03-1------31.2 0.008 SV 025NoneEU 048 Ore Transfer From Stockpile to 011-01-1------31.2 0.008 SV 026NoneEU 052 Ore Transfer Fr 008-01-1 to 009-01-1 or 009-02-1 ------6.0 0.008 SV 030NoneEU 053 Ore Transfer From 008-02-1 to 009-02-1------ Incl with EU052 0.008 SV 030NoneEU 054Secondary Crusher------14.2 0.008 SV 031NoneEU 055Secondary Crusher------14.2 0.008 SV 032NoneEU 056Secondary Crusher------12.0 0.008 SV 033NoneEU 057Secondary Crusher------14.2 0.008 SV 034NoneEU 058 Ore Transfer From 001-01-1 to 070-01-1------5.5 0.008 SV 035NoneEU 059 Ore Transfer From 005-02-1 to 006-02-1------ Incl with EU058 0.008 SV 035NoneEU 060 Ore Transfer From 005-01-1 to 006-01-1------ Incl with EU058 0.008 SV 035NoneEU 061 Ore Transfer From 003-01-1 to 004-01-1------5.5 0.008 SV 036NoneEU 062 Ore Transfer From 003-02-1 to 004-02-1------ Incl with EU061 0.008 SV 036NoneEU 063 Ore Transfer From 003-03-1 to 004-01-1------ Incl with EU061 0.008 SV 036NoneEU 064 Ore Transfer From 003-04-1 to 004-02-1------ Incl with EU061 0.008 SV 036NoneEU 065 Ore Transfer From 006-01-1 to 080-01-1------5.5 0.008 SV 037NoneEU 066 Ore Transfer From 006-01-1 to 080-03-1------ Incl with EU065 0.008 SV 037NoneEU 067 Ore Transfer From 006-01-1 to 080-05-1------ Incl with EU065 0.008 SV 037NoneEU 068 Ore Transfer From 006-01-1 to 080-07-1------ Incl with EU065 0.008 SV 037NoneEU 069Tertiary Crusher------7.2 0.008 SV 038NoneEU 070Tertiary Crusher------7.2 0.008 SV 039NoneEU 071Tertiary Crusher------7.2 0.008 SV 040NoneEU 072Tertiary Crusher------7.2 0.008 SV 041NoneEU 073Tertiary Crusher------7.2 0.008 SV 042NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 074Tertiary Crusher------7.2 0.008 SV 043NoneEU 075Tertiary Crusher------7.2 0.008 SV 044NoneEU 076Tertiary Crusher------7.2 0.008 SV 045NoneEU 077Tertiary Crusher------7.2 0.008 SV 046NoneEU 078Tertiary Crusher------7.2 0.008 SV 047NoneEU 079Tertiary Crusher------7.2 0.008 SV 048NoneEU 080Tertiary Crusher------7.2 0.008 SV 049NoneEU 081Tertiary Crusher------16.6 0.008 SV 050NoneEU 082Tertiary Crusher------16.6 0.008 SV 051NoneEU 083Tertiary Crusher------16.6 0.008 SV 052NoneEU 084Tertiary Crusher------16.6 0.008 SV 053NoneEU 085 Ore Transfer From 006-01-1 to 080-15-1------16.8 0.008 SV 054NoneEU 086 Ore Transfer From 006-01-1 to 080-09-1------ Incl with EU085 0.008 SV 054NoneEU 087 Ore Transfer From 006-01-1 to 080-11-1------ Incl with EU085 0.008 SV 054NoneEU 088 Ore Transfer From 006-01-1 to 080-13-1------ Incl with EU085 0.008 SV 054NoneEU 089 Ore Transfer From 006-01-2 to 080-15-1------ Incl with EU085 0.008 SV 054NoneEU 090 Ore Transfer From 006-01-2 to 080-09-1------ Incl with EU085 0.008 SV 054NoneEU 091 Ore Transfer From 006-01-2 to 080-11-1------ Incl with EU085 0.008 SV 054NoneEU 092 Ore Transfer From 006-01-2 to 080-13-1------ Incl with EU085 0.008 SV 054NoneEU 093Secondary Crusher------18.7 0.008 SV 055NoneEU 094Secondary Crusher------18.7 0.008 SV 056NoneEU 095Secondary Crusher------18.7 0.008 SV 057NoneEU 096Secondary Crusher------18.7 0.008 SV 058NoneEU 097Secondary Crusher------18.7 0.008 SV 059NoneEU 098 Ore Transfer From 008-03-1 to 009-03-1------5.5 0.008 SV 060NoneEU 099 Ore Transfer From 003-05-1 to 003-06-1------ Incl with EU098 0.008 SV 060NoneEU 100 Ore Transfer From 003-06-1 to 003-02-1------ Incl with EU098 0.008 SV 060NoneEU 101 Ore Transfer From 009-03-1 to 009-02-1------ Incl with EU098 0.008 SV 060NoneEU 102 Ore Transfer From 001-01-2 to 070-02-1------7.7 0.008 SV 061NoneEU 103Secondary Crusher------14.2 0.008 SV 062NoneEU 104 Ore Transfer From 008-04-1 to 009-04-1------6.0 0.008 SV 063NoneEU 105 Ore Transfer From 008-05-1 to 009-05-1------ Incl with EU105 0.008 SV 063NoneEU 106Secondary Crusher------14.6 0.008 SV 064NoneEU 107Secondary Crusher------18.7 0.008 SV 065NoneEU 108Secondary Crusher------18.7 0.008 SV 066NoneEU 109Secondary Crusher------18.7 0.008 SV 067NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 110Secondary Crusher------18.7 0.008 SV 068NoneEU 111 Ore Transfer From 001-03-1 to 070-03-1------4.8 0.008 SV 069NoneEU 112 Ore Transfer From 003-07-1 to 003-09-1------6.0 0.008 SV 070NoneEU 113 Ore Transfer From 003-08-1 to 003-10-1------ Incl with EU112 0.008 SV 070NoneEU 114 Ore Transfer From 003-09-1 to 004-03-1------6.0 0.008 SV 071NoneEU 115 Ore Transfer From 003-10-1 to 004-04-1------ Incl with EU114 0.008 SV 071NoneEU 116 Ore Transfer From 006-03-1 to 080-18-1------12.5 0.008 SV 072NoneEU 117 Ore Transfer From 006-03-1 to 080-20-1------ Incl with EU116 0.008 SV 072NoneEU 118 Ore Transfer From 006-03-1 to 080-22-1------ Incl with EU116 0.008 SV 072NoneEU 119 Ore Transfer From 006-03-1 to 080-24-1------ Incl with EU116 0.008 SV 072NoneEU 120 Ore Transfer From 006-03-1 to 080-26-1------ Incl with EU116 0.008 SV 072NoneEU 121 Ore Transfer From 006-03-1 to 080-28-1------ Incl with EU116 0.008 SV 072NoneEU 122 Ore Transfer From 006-04-1 to 080-18-1------ Incl with EU116 0.008 SV 072NoneEU 123 Ore Transfer From 006-04-1 to 080-20-1------ Incl with EU116 0.008 SV 072NoneEU 124 Ore Transfer From 006-04-1 to 080-22-1------ Incl with EU116 0.008 SV 072NoneEU 125 Ore Transfer From 006-04-1 to 080-24-1------ Incl with EU116 0.008 SV 072NoneEU 126 Ore Transfer From 006-04-1 to 080-26-1------ Incl with EU116 0.008 SV 072NoneEU 127 Ore Transfer From 006-04-1 to 080-28-1------ Incl with EU116 0.008 SV 072NoneEU 128Tertiary Crusher------10.6 0.008 SV 073NoneEU 129Tertiary Crusher------10.6 0.008 SV 074NoneEU 130Tertiary Crusher------10.6 0.008 SV 075NoneEU 131Tertiary Crusher------10.6 0.008 SV 076NoneEU 132Tertiary Crusher------10.6 0.008 SV 077NoneEU 133Tertiary Crusher------10.6 0.008 SV 078NoneEU 134Tertiary Crusher------10.6 0.008 SV 079NoneEU 135Tertiary Crusher------10.6 0.008 SV 080NoneEU 136Tertiary Crusher------10.6 0.008 SV 081NoneEU 137Tertiary Crusher------10.6 0.008 SV 082NoneEU 138Tertiary Crusher------10.6 0.008 SV 083NoneEU 140 Ore Transfer From 005-03-1 to 006-03-1------5.5 0.008 SV 085NoneEU 141 Ore Transfer From 005-04-1 to 006-04-1------ Incl with EU140 0.008 SV 085NoneEU 144 Ore Transfer From 009-01-1 to 020-01-1------10.6 0.008 SV 087NoneEU 145 Ore Transfer From 009-02-1 to 020-02-1------ Incl with EU144 0.008 SV 087NoneEU 146 Ore Transfer From 009-02-1 to 020-06-1------ Incl with EU144 0.008 SV 087NoneEU 147 Ore Transfer From 020-05-1 to 020-01-1------ Incl with EU144 0.008 SV 087NoneEU 155 Ore Transfer From 020-01-1 to Bin 100-06------5.5 0.008 SV 089NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 156 Ore Transfer From 020-01-1 to Bin 100-07------ Incl with EU155 0.008 SV 089NoneEU 157 Ore Transfer From 020-01-1 to Bin 100-08------ Incl with EU155 0.008 SV 089NoneEU 158 Ore Transfer From 020-01-1 to Bin 100-09------ Incl with EU155 0.008 SV 089NoneEU 159 Ore Transfer From 020-01-1 to Bin 100-10------ Incl with EU155 0.008 SV 089NoneEU 160 Ore Transfer From 021-03-1 to 022-03-1------ Incl with EU155 0.008 SV 089NoneEU 161 Ore Transfer From 021-04-1 to 022-04-1------ Incl with EU155 0.008 SV 089NoneEU 162 Ore Transfer From 020-01-1 to Bin 100-11------9.1 0.008 SV 090NoneEU 163 Ore Transfer From 020-01-1 to Bin 100-12------ Incl with EU162 0.008 SV 090NoneEU 164 Ore Transfer From 020-01-1 to Bin 100-13------ Incl with EU162 0.008 SV 090NoneEU 165 Ore Transfer From 020-01-1 to Bin 100-14------ Incl with EU162 0.008 SV 090NoneEU 166 Ore Transfer From 020-01-1 to Bin 100-15------ Incl with EU162 0.008 SV 090NoneEU 167 Ore Transfer From 021-05-1 to 022-05-1------ Incl with EU162 0.008 SV 090NoneEU 168 Ore Transfer From 021-06-1 to 022-06-1------ Incl with EU162 0.008 SV 090NoneEU 169 Ore Transfer From 020-01-1 to Bin 100-16------4.3 0.008 SV 091NoneEU 170 Ore Transfer From 020-01-1 to Bin 100-17------ Incl with EU169 0.008 SV 091NoneEU 171 Ore Transfer From 020-01-1 to Bin 100-18------ Incl with EU169 0.008 SV 091NoneEU 172 Ore Transfer From 020-01-1 to Bin 100-19------ Incl with EU169 0.008 SV 091NoneEU 173 Ore Transfer From 020-01-1 to Bin 100-20------ Incl with EU169 0.008 SV 091NoneEU 174 Ore Transfer From 021-07-1 to 022-07-1------ Incl with EU169 0.008 SV 091NoneEU 175 Ore Transfer From 021-08-1 to 022-08-1------ Incl with EU169 0.008 SV 091NoneEU 176 Ore Transfer From 020-01-1 to Bin 100-21------10.6 0.008 SV 092NoneEU 177 Ore Transfer From 020-01-1 to Bin 100-22------ Incl with EU176 0.008 SV 092NoneEU 178 Ore Transfer From 020-01-1 to Bin 100-23------ Incl with EU176 0.008 SV 092NoneEU 179 Ore Transfer From 020-01-1 to Bin 100-24------ Incl with EU176 0.008 SV 092NoneEU 180 Ore Transfer From 020-01-1 to Bin 100-25------ Incl with EU176 0.008 SV 092NoneEU 181 Ore Transfer From 021-09-1 to 022-09-1------ Incl with EU176 0.008 SV 092NoneEU 182 Ore Transfer From 021-10-1 to 022-10-1------ Incl with EU176 0.008 SV 092NoneEU 183 Ore Transfer From 020-01-1 to Bin 100-26------10.6 0.008 SV 093NoneEU 184 Ore Transfer From 020-01-1 to Bin 100-27------ Incl with EU183 0.008 SV 093NoneEU 185 Ore Transfer From 020-01-1 to Bin 100-28------ Incl with EU183 0.008 SV 093NoneEU 186 Ore Transfer From 020-01-1 to Bin 100-29------ Incl with EU183 0.008 SV 093NoneEU 187 Ore Transfer From 020-01-1 to Bin 100-30------ Incl with EU183 0.008 SV 093NoneEU 188 Ore Transfer From 021-11-1 to 022-11-1------ Incl with EU183 0.008 SV 093NoneEU 189 Ore Transfer From 021-12-1 to 022-12-1------ Incl with EU183 0.008 SV 093NoneEU 190 Ore Transfer From 009-04-1 to 020-04-1------10.6 0.008 SV 094NoneEU 191 Ore Transfer From 009-05-1 to 020-03-1------ Incl with EU190 0.008 SV 094NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 192 Ore Transfer From 009-05-1 to 020-05-1------ Incl with EU190 0.008 SV 094NoneEU 193 Ore Transfer From 020-06-1 to 020-04-1------ Incl with EU190 0.008 SV 094NoneEU 194 Ore Transfer From 020-01-1 to Bin 100-31------10.6 0.008 SV 095NoneEU 195 Ore Transfer From 020-01-1 to Bin 100-32------ Incl with EU194 0.008 SV 095NoneEU 196 Ore Transfer From 020-01-1 to Bin 100-33------ Incl with EU194 0.008 SV 095NoneEU 197 Ore Transfer From 020-01-1 to Bin 100-34------ Incl with EU194 0.008 SV 095NoneEU 198 Ore Transfer From 020-01-1 to Bin 100-35------ Incl with EU194 0.008 SV 095NoneEU 199 Ore Transfer From 021-13-1 to 022-13-1------ Incl with EU194 0.008 SV 095NoneEU 200 Ore Transfer From 021-14-1 to 022-14-1------ Incl with EU194 0.008 SV 095NoneEU 201 Ore Transfer From 020-01-1 to Bin 100-36------10.6 0.008 SV 096NoneEU 202 Ore Transfer From 020-01-1 to Bin 100-37------ Incl with EU201 0.008 SV 096NoneEU 203 Ore Transfer From 020-01-1 to Bin 100-38------ Incl with EU201 0.008 SV 096NoneEU 204 Ore Transfer From 021-15-1 to 022-15-1------ Incl with EU201 0.008 SV 096NoneEU 205 Ore Transfer From 021-16-1 to 022-16-1------ Incl with EU201 0.008 SV 096NoneEU 206 Ore Transfer From 020-01-1 to Bin 100-39------ Incl with EU201 0.008 SV 096NoneEU 207 Ore Transfer From 020-01-1 to Bin 100-40------ Incl with EU201 0.008 SV 096NoneEU 208 Ore Transfer From 020-01-1 to Bin 100-41------10.6 0.008 SV 097NoneEU 209 Ore Transfer From 020-01-1 to Bin 100-42------ Incl with EU208 0.008 SV 097NoneEU 210 Ore Transfer From 020-01-1 to Bin 100-43------ Incl with EU208 0.008 SV 097NoneEU 211 Ore Transfer From 020-01-1 to Bin 100-44------ Incl with EU208 0.008 SV 097NoneEU 212 Ore Transfer From 020-01-1 to Bin 100-45------ Incl with EU208 0.008 SV 097NoneEU 213 Ore Transfer From 021-17-1 to 022-17-1------ Incl with EU208 0.008 SV 097NoneEU 214 Ore Transfer From 021-18-1 to 022-18-1------ Incl with EU208 0.008 SV 097NoneEU 221Traveling Grate------4.6 0.008 SV 101NoneEU 222Traveling Grate------9.1 0.008 SV 102NoneEU 227L3 Pellet Cooler------832.8 0.008 SV 104NoneEU 228L3 Pellet Cooler Dump Zone------9.4 0.008 SV 105NoneEU 229L3 Feeder 041/046 Belts------912.0 0.008 SV 106NoneEU 230 Pellet Trnsfr Fr 041-03-1 to 042-01-1 or 042-02-2 ------4.3 0.008 SV 107NoneEU 231 Pellet Trnsfr Fr 046-03-1 to 042-01-1 or 042-02-2 ------ Incl with EU230 0.008 SV 107NoneEU 232 Pellet Transfer From 042-01-1 to 043-01-1------4.3 0.008 SV 108NoneEU 233 Pellet Transfer From 042-01-2 to 043-01-2------ Incl with EU232 0.008 SV 108NoneEU 234 Pellet Trnsfr Fr 041-03-1 to 042-01-1 or 042-02-2 ------4.3 0.008 SV 109NoneEU 235 Pellet Trnsfr Fr 046-03-1 to 042-01-1 or 042-02-2 ------ Incl with EU234 0.008 SV 109NoneEU 257Traveling Grate------2.6 0.008 SV 116NoneEU 258Traveling Grate------722.4 0.008 SV 117NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 263L4 Pellet Cooler------304.1 0.008 SV 119NoneEU 264L4 Conv. Trans. Feeder------912.0 0.008 SV 120NoneEU 265L4 Pellet Cooler Dump Zone------33.6 0.008 SV 121NoneEU 266 Pellet Trnsfr Fr 041-04-1 to 042-01-1 or 042-02-2 ------26.4 0.008 SV 122NoneEU 267 Pellet Trnsfr Fr 046-04-1 to 042-01-1 or 042-02-2 ------ Incl with EU266 0.008 SV 122NoneEU 278Traveling Grate------2.6 0.008 SV 125NoneEU 279Traveling Grate------705.2 0.008 SV 126NoneEU 284L5 Pellet Cooler------145.7 0.008 SV 128NoneEU 285L5 Conv. Trans. Feeder------912.0 0.008 SV 129NoneEU 286L5 Pellet Cooler Dump Zone------33.6 0.008 SV 130NoneEU 287 Pellet Trnsfr Fr 041-05-1 to 042-01-1 or 042-02-2 ------43.2 0.008 SV 131NoneEU 288 Pellet Trnsfr Fr 046-05-1 to 042-01-1 or 042-02-2 ------ Incl with EU287 0.008 SV 131NoneEU 289Conveyor------77.8 0.008 SV 132NoneEU 290Conveyor------77.8 0.008 SV 133NoneEU 291Conveyor------77.8 0.008 SV 134NoneEU 292Conveyor------77.8 0.008 SV 135NoneEU 293Conveyor------77.8 0.008 SV 136NoneEU 294Conveyor------77.8 0.008 SV 137NoneEU 295 Pellet Transfer From 046-06-1 to 042-07-1------31.2 0.008 SV 138NoneEU 296 Pellet Transfer From 046-06-2 to 042-07-2------ Incl with EU295 0.008 SV 138NoneEU 311Traveling Grate------2.6 0.008 SV 142NoneEU 312Traveling Grate------767.4 0.008 SV 143NoneEU 318 Pellet Trnsfr Fr 041-06-1 to 042-06-1 or 042-06-2 ------48.0 0.008 SV 146NoneEU 319 Pellet Trnsfr Fr 046-06-1 to 042-06-1 or 042-06-2 ------ Incl with EU318 0.008 SV 146NoneEU 330Traveling Grate------2.6 0.008 SV 149NoneEU 331Traveling Grate------717.0 0.008 SV 150NoneEU 337 Pellet Trnsfr Fr 041-07-1 to 042-06-1 or 042-06-2 ------384.0 0.008 SV 153NoneEU 338 Pellet Trnsfr Fr 046-07-1 to 042-06-1 or 042-06-2 ------ Incl with EU337 0.008 SV 153NoneEU 339 Pellet Transfer From 043-03-1 to 044-03-1------77.8 0.008 SV 154NoneEU 340 Pellet Transfer From 043-03-2 to 044-03-2------77.8 0.008 SV 155NoneEU 341Conveyor------204.4 0.008 SV 156NoneEU 342Conveyor------204.4 0.008 SV 157NoneEU 343Conveyor------204.4 0.008 SV 158NoneEU 344Conveyor------204.4 0.008 SV 159NoneEU 345Conveyor------204.4 0.008 SV 160NoneEU 346Conveyor------204.4 0.008 SV 161NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 347Conveyor------204.4 0.008 SV 162NoneEU 348Conveyor------204.4 0.008 SV 163NoneEU 349Conveyor------204.4 0.008 SV 164NoneEU 350Conveyor------204.4 0.008 SV 165NoneEU 351Conveyor------204.4 0.008 SV 166NoneEU 352Conveyor------204.4 0.008 SV 167NoneEU 353Conveyor------204.4 0.008 SV 168NoneEU 354Conveyor------204.4 0.008 SV 169NoneEU 355Conveyor------204.4 0.008 SV 170NoneEU 359 Pellet Transfer From 043-06-1 to 044-06-1------204.4 0.008 SV 174NoneEU 360Conveyor------204.4 0.008 SV 175NoneEU 361 Pellet Transfer From 043-06-2 to 044-06-2------204.4 0.008 SV 176NoneEU 362Conveyor------204.4 0.008 SV 177NoneEU 363 Pellet Transfer From 044-06-1 to 044-07-1------204.4 0.008 SV 178NoneEU 364 Pellet Transfer From 044-06-2 to 044-07-2------204.4 0.008 SV 179NoneEU 365Conveyor------204.4 0.008 SV 179NoneEU 366Pellet Hopper------204.4 0.008 SV 180NoneEU 397Line 6 Cooler Vent Stack------648.0 0.008 SV 196NoneEU 398Line 7 Cooler Vent Stack------616.1 0.008 SV 197NoneN/AN/A - Total facility fugitive sources------5,650.4 --- N/ANone3.D. Non-MACT Units and Fugitive Sources (PM only)EU 148Limestone Transfer(formerly Ore Transfer From 020-01-1 to Bin 100-01)------9.6--- SV 088NoneEU 149Limestone Transfer(formerly Ore Transfer From 020-01-1 to Bin 100-02)------ Incl with EU148 --- SV 088NoneEU 150Limestone Transfer(formerly Ore Transfer From 020-01-1 to Bin 100-03)------ Incl with EU148 --- SV 088NoneEU 151Limestone Transfer(formerly Ore Transfer From 021-01-1 to 022-01-1)------ Incl with EU148 --- SV 088NoneEU 152Limestone Transfer(formerly Ore Transfer From 020-01-1 to Bin 100-04)------ Incl with EU148 --- SV 088NoneEU 153Limestone Transfer(formerly Ore Transfer From 021-02-1 to 022-02-1)------ Incl with EU148 --- SV 088NoneEU 154Limestone Transfer(formerly Ore Transfer From 020-01-1 to Bin 100-05)------ Incl with EU148 --- SV 088NoneEU 217Pekay Mixer------2.4--- SV 100None3.C. Sources of fugitive PM that are subject to MACT standardsTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 218Pekay Mixer------ Incl with EU217 --- SV 100NoneEU 219Pekay Mixer------ Incl with EU217 --- SV 100NoneEU 220Pekay Mixer------ Incl with EU217 --- SV 100NoneEU 236Bentonite Bin------3.1--- SV 110NoneEU 237Bentonite Bin------ Incl with EU236 --- SV 110NoneEU 238Bentonite Bin------ Incl with EU236 --- SV 110NoneEU 239Bentonite Day Bin------0.3--- SV 111NoneEU 240Bentonite Day Bin------ Incl with EU239 --- SV 111NoneEU 241Bentonite Day Bin------ Incl with EU239 --- SV 111NoneEU 242Bentonite Day Bin------ Incl with EU239 --- SV 111NoneEU 243Bentonite Unloading Hopper------0.1--- SV 112NoneEU 244Bentonite Storage Bin------3.1--- SV 113NoneEU 245Bentonite Storage Bin------ Incl with EU244 --- SV 113NoneEU 246Bentonite Storage Bin------ Incl with EU244 --- SV 113NoneEU 247Storage Bin------0.3--- SV 114NoneEU 248Storage Bin------ Incl with EU247 --- SV 114NoneEU 249Storage Bin------ Incl with EU247 --- SV 114NoneEU 250Storage Bin------ Incl with EU247 --- SV 114NoneEU 251Storage Bin------ Incl with EU247 --- SV 114NoneEU 252Pekay Mixer------2.9--- SV 115NoneEU 253Pekay Mixer------ Incl with EU252 --- SV 115NoneEU 254Pekay Mixer------ Incl with EU252 --- SV 115NoneEU 255Pekay Mixer------ Incl with EU252 --- SV 115NoneEU 256Pekay Mixer------ Incl with EU252 --- SV 115NoneEU 268Storage Bin------0.3--- SV 123NoneEU 269Storage Bin------ Incl with EU268 --- SV 123NoneEU 270Storage Bin------ Incl with EU268 --- SV 123NoneEU 271Storage Bin------ Incl with EU268 --- SV 123NoneEU 272Storage Bin------ Incl with EU268 --- SV 123NoneEU 273Pekay Mixer------2.9--- SV 124NoneEU 274Pekay Mixer------ Incl with EU273 --- SV 124NoneEU 275Pekay Mixer------ Incl with EU273 --- SV 124NoneEU 276Pekay Mixer------ Incl with EU273 --- SV 124NoneEU 277Pekay Mixer------ Incl with EU273 --- SV 124NoneEU 297Bentonite Storage Bin------3.1--- SV 139NoneEU 298Bentonite Storage Bin------ Incl with EU297 --- SV 139NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 299Bentonite Storage Bin------ Incl with EU297 --- SV 139NoneEU 300Bentonite Unloading Hopper------ Incl with EU297 --- SV 139NoneEU 301Storage Bin------0.4--- SV 140NoneEU 302Storage Bin------ Incl with EU301 --- SV 140NoneEU 303Storage Bin------ Incl with EU301 --- SV 140NoneEU 304Storage Bin------ Incl with EU301 --- SV 140NoneEU 305Storage Bin------ Incl with EU301 --- SV 140NoneEU 306Pekay Mixer------1.6--- SV 141NoneEU 307Pekay Mixer------ Incl with EU306 --- SV 141NoneEU 308Pekay Mixer------ Incl with EU306 --- SV 141NoneEU 309Pekay Mixer------ Incl with EU306 --- SV 141NoneEU 310Pekay Mixer------ Incl with EU306 --- SV 141NoneEU 320Storage Bin------0.4--- SV 147NoneEU 321Storage Bin------ Incl with EU320 --- SV 147NoneEU 322Storage Bin------ Incl with EU320 --- SV 147NoneEU 323Storage Bin------ Incl with EU320 --- SV 147NoneEU 324Storage Bin------ Incl with EU320 --- SV 147NoneEU 325Pekay Mixer------1.6--- SV 148NoneEU 326Pekay Mixer------ Incl with EU325 --- SV 148NoneEU 327Pekay Mixer------ Incl with EU325 --- SV 148NoneEU 328Pekay Mixer------ Incl with EU325 --- SV 148NoneEU 329Pekay Mixer------ Incl with EU325 --- SV 148NoneEU 367Coal Unload Hopper------0.2--- SV 181NoneEU 368Coal Hopper Conveyor------ Incl with EU367 --- SV 181NoneEU 369Coal Conv. Feed------ Incl with EU367 --- SV 181NoneEU 370Coal Silo Feed------ Incl with EU367 --- SV 181NoneEU 371Coal Silo Discharge------ Incl with EU367 --- SV 181NoneEU 372Coal Silo Transfer------ Incl with EU367 --- SV 181NoneEU 373Coal Silo------ Incl with EU367 --- SV 181NoneEU 374Coal Conv. Discharge------0.2--- SV 182NoneEU 375Coal Screen------ Incl with EU374 --- SV 182NoneEU 376Coal Reversing Belt------ Incl with EU374 --- SV 182NoneEU 377Day Bin Belt Feed------ Incl with EU374 --- SV 182NoneEU 378Day Bin Belt Discharge------ Incl with EU374 --- SV 182NoneEU 379Coal Pulverizer------ Incl with EU374 --- SV 182 De Minimis Modeling for PM10EU 380Coal Pulverizer------ Incl with EU374 --- SV 182 De Minimis Modeling for PM10Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 381Coal Day Bin------ Incl with EU374 --- SV 182 De Minimis Modeling for PM10EU 382Coal Day Bin------ Incl with EU374 --- SV 182 De Minimis Modeling for PM103.E. Other Combustion UnitsEU 001Utility Plant Heating Boiler #1193.50.45.3--- SV 001BART Analysis for NOxDe Minimis Modeling for PM10 and SO2EU 002Utility Plant Heating Boiler #2719.81.519.5--- SV 002BART Analysis for NOxDe Minimis Modeling for PM10 and SO2EU 003Utility Plant Heating Boiler #3105.60.22.9--- SV 003BART Analysis for NOxDe Minimis Modeling for PM10 and SO2EU 004Utility Plant Heating Boiler #4230.80.56.3--- SV 004BART Analysis for NOxDe Minimis Modeling for PM10 and SO2EU 005Utility Plant Heating Boiler #5226.50.56.1--- SV 005BART Analysis for NOxDe Minimis Modeling for PM10 and SO2EU 006Utility Plant Diesel Generator3.10.20.2--- SV 006NoneEU 008Utility Plant Diesel Generator8.40.60.6--- SV 008NoneEU 009Utility Plant Diesel Fire Pump10.90.70.7--- SV 009NoneEU 010 Mobile Eqp Shop Heating Boiler #16.80.00.2--- SV 010De Minimis Modeling for SO2 + NOxEU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU010 Incl with EU010 --- SV 011De Minimis Modeling for SO2 + NOxEU 012 Mobile Eqp Shop Diesel Generator2.30.20.2--- SV 012NoneEU 028Coarse Crusher Zinc Furnace3.30.00.3--- SV 019De Minimis Modeling for SO2, NOx + PM10EU 032Coarse Crusher Zinc Furnace0.51.40.0--- SV 020De Minimis Modeling for SO2, NOx + PM10EU 033Coarse Crusher Zinc FurnaceIncl with EU032 Incl with EU032 Incl with EU032 --- SV 020De Minimis Modeling for SO2, NOx + PM10EU 051Crusher Area Diesel Generator2.00.10.1--- SV 029NoneEU 142Fine Crusher Zinc Furnace5.616.70.3--- SV 086De Minimis Modeling for SO2, NOx + PM10EU 143Fine Crusher Zinc Furnace5.616.70.3--- SV 086De Minimis Modeling for SO2, NOx + PM10EU 215 Concentrator Area Diesel Generator45.03.03.1--- SV 098NoneEU 383Diesel Generator15.41.01.1--- SV 183NoneEU 384Diesel Generator19.21.31.3--- SV 184NoneEU 385Diesel Generator6.10.40.4--- SV 185NoneEU 386Diesel Generator7.50.50.5--- SV 186NoneTable 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission Unit DescriptionNOx Max. 24-hrActualEmissions (lb/day)SO2 Max. 24-hr ActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumberActions RequiredEU 387Air Compressor171.111.311.8--- SV 187De Minimis Modeling for SO2, NOx + PM10* The taconite MACT emission limits are based on EPA Method 5 and include the applicable averaging and grouping provisions, as presented in theregulation.Table 3-2: De Minimis Modeling Input Data and the Basis for 24-hour Emissions DataEU #EU DescriptionSO2Maximum24-hr EmissionRate (lbs/day)NOxMaximum24-hr EmissionRate (lbs/day)PM2.5Maximum 24-hr EmissionRate (lbs/day)PM10Maximum24-hr EmissionRate (lbs/day) SV #Stack Easting(utm)StackNorthing(utm)Height ofOpeningfromGround (ft)BaseElevationofGround(ft)Stack length,width, orDiameter (ft)FlowRate atexit(acfm)ExitTemp(°F)Basis for SO224-hour ActualEmissionsBasis for NOx24-hour ActualEmissionsBasis forPM2.524-hourActualEmissionsBasis for PM1024-hour ActualEmissionsEU 379Coal Pulverizer0.000.000.000.15 SV 182 NANA 163.5 1676 2.83 29000.0 70n/an/an/aAP-42 EmissionFactorEU 380Coal Pulverizer0.000.000.00 Incl with EU 379 SV 182 NANA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382EU 381Coal Day Bin0.000.000.00 Incl with EU 379 SV 182 NANA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382EU 382Coal Day Bin0.000.000.00 Incl with EU 379 SV 182 NANA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382EU 001 Utility Plant Heating Boiler #1 0.41 193.52 0.005.25 SV 001 527605.4429 5268166.228 67.25 1682 4.50 17000.0 380AP-42 EmissionFactorAP-42 EmissionFactorn/aAP-42 EmissionFactorEU 002 Utility Plant Heating Boiler #2 1.54 719.83 0.0019.54 SV 002 527612.1358 5268167.191 67.25 1682 4.50 17000.0 380AP-42 EmissionFactorAP-42 EmissionFactorn/aAP-42 EmissionFactorEU 003 Utility Plant Heating Boiler #3 0.23 105.64 0.002.87 SV 003 527619.1379 5268168.2 67.25 1682 4.50 20800.0 380AP-42 EmissionFactorAP-42 EmissionFactorn/aAP-42 EmissionFactorEU 004 Utility Plant Heating Boiler #4 0.49 230.83 0.006.27 SV 004 527626.9988 5268169.38 68.59 1682 4.50 25500.0 380AP-42 EmissionFactorAP-42 EmissionFactorn/aAP-42 EmissionFactorEU 005 Utility Plant Heating Boiler #5 0.49 226.49 0.006.15 SV 005 527633.9031 5268170.379 68.59 1682 4.50 25500.0 380AP-42 EmissionFactorAP-42 EmissionFactorn/aAP-42 EmissionFactorEU 010 Mobile Eqp Shop Heating Boiler #1 0.016.790.000.18 SV 010 527646.157 5266984.445 58.84 1619 2.50 4100.0 380AP-42 EmissionFactorAP-42 EmissionFactorn/aAP-42 EmissionFactorEU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU010 0.00 Incl with EU010 SV 011 527650.711 5266985.142 58.84 1619 2.50 4100.0 380 Incl with EU010 Incl with EU010 n/a Incl with EU010EU 028 Coarse Crusher Zinc Furnace0.003.290.000.31 SV 019 527252.4492 5267524.117 32 1732 1.67 36700.0 700AP-42 EmissionFactorAP-42 EmissionFactorn/aAP-42 EmissionFactorEU 032 Coarse Crusher Zinc Furnace1.440.480.000.02 SV 020 527164.3521 5267449.81 32 1732 1.67 36700.0 70019 gallons used inJan of 2005 * AP-42Emission Factor19 gallons used inJan of 2005 * AP-42Emission Factorn/a19 gallons used inJan of 2005 * AP-42Emission FactorEU 033 Coarse Crusher Zinc Furnace Incl with EU032 Incl with EU032 0.00 Incl with EU032 SV 020 527164.3521 5267449.81 32 1732 1.67 36700.0 700 Incl with EU032 Incl with EU032 n/a Incl with EU032EU 142 Fine Crusher Zinc Furnace16.725.590.000.25 SV 086 527183.7471 5267919.903 29 1731 1.67 36700.0 700Assume one full dayof operation: 24 hrs *operating rate * AP42 Emission FactorAssume one full dayof operation: 24 hrs* operating rate *AP-42 EmissionFactorn/aAssume one full dayof operation: 24 hrs* operating rate *AP-42 EmissionFactoEU 143 Fine Crusher Zinc Furnace16.725.590.000.25 SV 086 527173.7879 5267919.13 29 1731 1.67 36700.0 700Assume one full dayof operation: 24 hrs *operating rate * AP42 Emission FactorAssume one full dayof operation: 24 hrs* operating rate *AP-42 EmissionFactorn/aAssume one full dayof operation: 24 hrs* operating rate *AP-42 EmissionFactoEU 387Air Compressor11.28 171.12 0.0011.76 SV 187 NANA 40 1676 1.00 12000 80 Based on PTE Based on PTE n/a Based on PTETable 3-3 De Minimis Visibility Modeling Results2002200320042002 – 2004 CombinedClass IArea withGreatestImpact Model ScenarioModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewBWCA De Minimis0.04000.03400.02900.0310Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions DataEU #EU DescriptionSO2Maximum24-hr EmissionRate (lbs/day)NOxMaximum24-hr EmissionRate (lbs/day)PM2.5Maximum 24-hrEmission Rate(lbs/day)PM10Maximum24-hr EmissionRate (lbs/day) SV #StackEasting(utm)StackNorthing(utm)Height ofOpeningfromGround (ft)BaseElevationofGround(ft)Stack length,width, orDiameter (ft)Flow Rateat exit(acfm)ExitTemp(°F)Basis for SO224-hour ActualEmissionsBasis for NOx24-hour ActualEmissionsBasis forPM2.524-hour ActualEmissionsBasis for PM1024-hour ActualEmissionsBaseline Conditions - Utility Plant Heating BoilersEU 001 Utility Plant Heating Boiler #1 0.41194n/a5.3 SV 001 527605.4429 5268166.228 67.25 1682 4.5 17,000 380AP-42 EmissionFactorAP-42 EmissionFactorN/AAP-42 EmissionFactorEU 002 Utility Plant Heating Boiler #2 1.54720n/a19.5 SV 002 527612.1358 5268167.191 67.25 1682 4.5 17,000 380AP-42 EmissionFactorAP-42 EmissionFactorN/AAP-42 EmissionFactorEU 003 Utility Plant Heating Boiler #3 0.23106n/a2.9 SV 003 527619.1379 5268168.2 67.25 1682 4.5 20,800 380AP-42 EmissionFactorAP-42 EmissionFactorN/AAP-42 EmissionFactorEU 004 Utility Plant Heating Boiler #4 0.49231n/a6.3 SV 004 527626.9988 5268169.38 68.59 1682 4.5 25,500 380AP-42 EmissionFactorAP-42 EmissionFactorN/AAP-42 EmissionFactorEU 005 Utility Plant Heating Boiler #5 0.49226n/a6.1 SV 005 527633.9031 5268170.379 68.59 1682 4.5 25,500 380AP-42 EmissionFactorAP-42 EmissionFactorN/AAP-42 EmissionFactorBaseline Conditions - Indurating Furnaces - Natural Gas Burning in KilnEU 223Line 33072 19133n/a6552 SV 103 528069.3977 5268291.49 116 1698 10.4 322,000 130Stack TestMay 2005Stack TestJune 1997N/AStack TestMay 2005EU 259Line 43192 29520n/a2568 SV 118 528116.5749 5268294.618 139.6 1702 14.0 650,000 115Stack TestJuly 2006Stack TestApril 2004N/AStack TestJuly 2005EU 280Line 53192 29520n/a2568 SV 127 528130.9199 5268296.414 139.6 1702 14.0 650,000 115 Same as Line 4 Same as line 4 N/AStack TestMay 2005EU 313Line 62520 26232n/a1968 SV 144 528362.9511 5268243.387 140 1700 16.0 600,000 109 Same as Line 7 Same as line 7 N/AStack TestApril 2005EU 332Line 72520 26232n/a1968 SV 151 528377.6897 5268245.79 140 1700 16.0 600,000 109Stack TestJune 2002Stack TestJune 2002N/AStack TestApril 2005Baseline Conditions - Indurating Furnaces - Solid Fuel Burning in KilnEU 223Line 33072 12168n/a6552 SV 103 528069.3977 5268291.49 116 1698 10.4 322,000 130Stack TestMarch 1994Stack TestApril 2004N/AStack TestMay 2005EU 259Line 43192 27360n/a2568 SV 118 528116.5749 5268294.618 139.6 1702 14.0 650,000 115Stack TestJuly 2005Stack TestApril 2004N/AStack TestJuly 2005EU 280Line 53192 27360n/a2568 SV 127 528130.9199 5268296.414 139.6 1702 14.0 650,000 115 Same as line 4 Same as line 4 N/AStack TestMay 2005EU 313Line 64032 19440n/a1968 SV 144 528362.9511 5268243.387 140 1700 16.0 600,000 109 Same as line 7 Same as line 7 N/AStack TestApril 2005EU 332Line 74032 19440n/a1968 SV 151 528377.6897 5268245.79 140 1700 16.0 600,000 109Stack TestMarch 1994Stack TestMay 2004N/AStack TestApril 2005Table 4-2 Baseline Visibility Modeling ResultsTable 4-2 Baseline Visibility Modeling Results2002200320042002 – 2004 CombinedModelingScenarioSO2NOxClass I Areawith GreatestImpactModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasBWCA 5.508 177 7.201 168 5.962 160 6.209 5051BaselineIndurating FurnacesburningSolid FuelsBaselineIndurating FurnacesburningSolid FuelsBWCA 4.78 173 6.377 162 5.26 155 5.52 490Scenario Control Technology

# Table 5-3 SO 2 

# Control Cost Summary



# Control T echnology Installed Capital Cost

(MM$) Operating Cost

(MM$/yr) Annualized

Pollution Control Cost ($/ton)

Line 3 $27,948,027 $5,322,323 $20,201 Line 4 $39,347,773 $8,448,332 $23,597 Line 5 $39,347,773 $8,448,332 $23,597 Line 6 $36,370,821 $7,939,628 $18,216 Line 7 $37,793,453 $8,123,761 $18,638

Line 3 $19,626,314 $2,816,433 $14,253 

# Line 4 $26,664,036 $4,123,939 $15,358 

# Line 5 $26,664,036 $4,123,939 $15,358 

# Line 6 $25,704,464 $3,953,025 $12,093 

# Line 7 $25,704,464 $3,953,025 $12,093 

# Secondary Wet Scrubber W et Walled Electrostatic Precipitator (WWESP)Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission RatesScenario Control TechnologySO2NOxControlScenario SV #EmissionUnitSO2NOx% ReductionMax 24-hourlbs/day % ReductionMax 24-hourlbs/daySV 103 Line 330% 2,150 --- 19,128SV 118 Line 4--- 3,192 --- 29,520SV 127 Line 5--- 3,192 --- 29,520SV 144 Line 6--- 2,520 10% 23,609SV 151 Line 7--- 2,520 --- 26,232SV 103 Line 330% 2,150 --- 12,168SV 118 Line 4--- 3,192 --- 27,360SV 127 Line 5--- 3,192 --- 27,360SV 144 Line 6--- 4,032 10% 17,496SV 151 Line 7--- 4,032 --- 19,4402Current Operationsw/ Line 3 ScrubberIndurating Furnaces BurningNat GasCurrent Operationw/ line 6 BurnersIndurating Furances BurningNat Gas3Current Operationsw/ Line 3 ScrubberIndurating Furnaces BurningSolid FuelCurrent Operationw/ line 6 BurnersIndurating Furnaces BurningSolid FuelTable 5-5 Post-BART SO2Modeling Scenarios - Visibility Modeling ResultsScenario #SO2NOxClass I Areawith GreatestImpactModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasBWCA 5.508 177 7.201 168 5.962 160 6.209 5051BaselineIndurating FurnacesburningSolid FuelsBaselineIndurating FurnacesburningSolid FuelsBWCA 4.78 173 6.377 162 5.26 155 5.52 4902Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasCurrent Operationw/ line 6 BurnersIndurating FurancesBurning Nat GasBWCA 5.333 176 7.005 168 5.807 157 6.043 5013Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelCurrent Operationw/ line 6 BurnersIndurating FurnacesBurning Solid FuelBWCA 4.642 171 6.189 159 5.106 148 5.365 478Scenario Control Technology20042002 – 2004Combined20022003

# Table 5-8 Indurating Furnace NOx Control Cost Summary



# Control Technology Installed

Capital Cost (MM$) Operating

Cost (MM$/yr) Annualized

Pollution Control Cost ($/ton) Incremental

Control Cost ($/ton)

Line 3 $69,222,423 $19,513,772 $18,135 n/a Line 4 $58,874,795 $28,169,433 $19,433 n/a Line 5 $58,874,795 $28,169,433 $19,347 n/a Line 6 $56,748,729 $26,419,264 $18,595 n/a Line 7 $56,748,729 $26,419,264 $17,129 n/a

Line 3 n/a n/a n/a n/a Line 4 $5,091,356 $480,588 $5,844 $5,076 Line 5 $6,474,892 $611,184 $5,974 $5,209 Line 6 n/a n/a n/a n/a Line 7 n/a n/a n/a n/a

Line 3 n/a n/a n/a n/a Line 4 $1,474,892 $139,219 $768 -$3,673 Line 5 $1,474,892 $139,219 $765 -$3,657 Line 6 n/a n/a n/a n/a Line 7 $1,200,000 $113,272 $588 n/a

Line 3 $3,616,464 $341,369 $5,076 n/a Line 4 $5,000,000 $471,965 $5,209 n/a Line 5 $5,000,000 $471,965 $5,186 n/a Line 6 n/a n/a n/a n/a Line 7 n/a n/a n/a n/a Low-NOx Burners

Ported Kilns Selective Catalytic Reduction (SCR)

Low-NOx Burners + Ported KilnsTable 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission RatesScenario Control TechnologySO2NOxControlScenario SV #EmissionUnitSO2NOx% ReductionMax 24-hourlbs/day % ReductionMax 24-hourlbs/daySV 103 Line 3--- 2,150 5% 18,172SV 118 Line 4--- 3,192 5% 28,044SV 127 Line 5--- 3,192 5% 28,044SV 144 Line 6--- 2,520Ports alreadyinstalled23,609SV 151 Line 7--- 2,520Ports alreadyinstalled26,232SV 103 Line 3--- 2,150No NOximprovementon solid fuels12,168SV 118 Line 4--- 3,192No NOximprovementon solid fuels27,360SV 127 Line 5--- 3,192No NOximprovementon solid fuels27,360SV 144 Line 6--- 4,032No NOximprovementon solid fuels17,496SV 151 Line 7--- 4,032No NOximprovementon solid fuels19,4404Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasPorted Kilns(lines 3, 4, 5)Indurating FurancesBurning Nat Gas5Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelPorted Kilns(lines 3, 4, 5)Indurating FurancesBurning Solid Fuel6Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission RatesScenario Control TechnologySO2NOxControlScenario SV #EmissionUnitSO2NOx% ReductionMax 24-hourlbs/day % ReductionMax 24-hourlbs/day4SV 103 Line 3--- 2,150low-NOx NotAvailable19,128SV 118 Line 4--- 3,192 10% 26,568SV 127 Line 5--- 3,192 10% 26,568SV 144 Line 6--- 2,520low-NOxAlreadyInstalled23,609SV 151 Line 7--- 2,520 10% 23,609SV 103 Line 3--- 2,150low-NOx NotAvailable12,168SV 118 Line 4--- 3,192 10% 24,624SV 127 Line 5--- 3,192 10% 24,624SV 144 Line 6--- 4,032low-NOxAlreadyInstalled17,496SV 151 Line 7--- 4,032 10% 17,496SV 103 Line 3--- 2,150 5% 18,172SV 118 Line 4--- 3,192 15% 25,092SV 127 Line 5--- 3,192 15% 25,092SV 144 Line 6--- 2,520 0% 23,609SV 151 Line 7--- 2,520 10% 23,609SV 103 Line 3--- 2,150 0% 12,168SV 118 Line 4--- 3,192 10% 24,624SV 127 Line 5--- 3,192 10% 24,624SV 144 Line 6--- 4,032 0% 17,496SV 151 Line 7--- 4,032 10% 17,4966Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasLow NOx Burners(lines 4, 5, 7)Indurating FurancesBurning Nat Gas7Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelLow NOx Burners(lines 4, 5, 7)Indurating FurancesBurning Solid Fuel8Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasPorted Kilns(lines 3, 4, 5)+Low NOx Burners(lines 4, 5, 7)9Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelPorted Kilns(lines 3, 4, 5)+Low NOx Burners(lines 4, 5, 7)Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling ResultsScenario # Operating Conditions Operating ConditionsClass I Areawith GreatestImpactModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasBWCA 5.508 177 7.201 168 5.962 160 6.209 5051BaselineIndurating FurnacesburningSolid FuelsBaselineIndurating FurnacesburningSolid FuelsBWCA 4.780 173 6.377 162 5.260 155 5.520 4902Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasCurrent Operationw/ line 6 BurnersIndurating FurancesBurning Nat GasBWCA 5.333 176 7.005 168 5.807 157 6.043 5013Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelCurrent Operationw/ line 6 BurnersIndurating FurnacesBurning Solid FuelBWCA 4.642 171 6.189 159 5.106 148 5.365 4784Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasPorted Kilns(lines 3, 4, 5)Indurating FurancesBurning Nat GasBWCA 5.219 174 6.871 168 5.677 156 5.931 4985Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelPorted Kilns(lines 3, 4, 5)Indurating FurancesBurning Solid FuelBWCA 4.642 171 6.189 159 5.106 148 5.365 4782002200320042002 – 2004CombinedTable 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling ResultsScenario # Operating Conditions Operating ConditionsClass I Areawith GreatestImpactModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview2002200320042002 – 2004Combined6Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasLow NOx Burners(lines 4, 5, 7)Indurating FurancesBurning Nat GasBWCA 5.088 174 6.713 166 5.542 153 5.758 4937Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelLow NOx Burners(lines 4, 5, 7)Indurating FurancesBurning Solid FuelBWCA 4.408 165 5.912 153 4.858 142 5.095 4608Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasPorted Kilns(lines 3, 4, 5)+Low NOx Burners(lines 4, 5, 7)Burning Nat GasBWCA 4.970 173 6.574 162 5.417 153 5.641 4889Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelPorted Kilns(lines 3, 4, 5)+Low NOx Burners(lines 4, 5, 7)Indurating FurancesBurning Solid FuelBWCA 4.408 165 5.912 153 4.858 142 5.095 460

# Table 5-14 Boiler NOx Control Cost Summary



# Control Technology Installed Capital Cost (MM$) Operating

Cost (MM$/yr) Annualized

Pollution Control Cost ($/ton) Low Temperature Oxidation (LoTOx) Utility Plant Heater Boiler #1 

# $1,681,680 $304,052 $23,668 Utility Plant Heater Boiler #2 

# $1,681,680 $304,052 $24,489 Utility Plant Heater Boiler #4 

# $1,914,641 $343,518 $25,720 Utility Plant Heater Boiler #5 

# $1,914,641 $343,518 $27,713 Selective Catalytic Reduction (SCR) Utility Plant Heater Boiler #1 

# $4,488,567 $592,165 $50,632 Utility Plant Heater Boiler #2 

# $4,488,567 $592,165 $52,345 Utility Plant Heater Boiler #4 

# $5,234,392 $688,384 $56,028 Utility Plant Heater Boiler #5 

# $5,234,392 $688,384 $60,211
Low NOX Burner / Flue Gas Recirculation Utility Plant Heater Boiler #1 

# $1,384,220 $166,560 $15,558 Utility Plant Heater Boiler #2 

# $1,384,220 $166,560 $16,098 Utility Plant Heater Boiler #4 

# $1,745,018 $209,678 $18,839 Utility Plant Heater Boiler #5 

# $1,745,018 $209,678 $20,299 Regenerative Selective Catalytic Reduction (R-SCR) Utility Plant Heater Boiler #1 

# $1,690,961 $238,636 $22,879 Utility Plant Heater Boiler #2 

# $1,690,961 $238,636 $23,638 Utility Plant Heater Boiler #4 

# $2,156,692 $316,281 $28,633 Utility Plant Heater Boiler #5 

# $2,156,692 $316,281 $30,710 Low NOX Burner / Overfire Air (OFA) Utility Plant Heater Boiler #1 

# $1,131,149 $136,590 $14,282 Utility Plant Heater Boiler #2 

# $1,131,149 $136,590 $14,778 Utility Plant Heater Boiler #4 

# $1,425,985 $171,954 $17,294 Utility Plant Heater Boiler #5 

# $1,425,985 $171,954 $18,634 Low NOX Burner Utility Plant Heater Boiler #1 

# $344,269 $47,480 $6,653 Utility Plant Heater Boiler #2 

# $344,269 $47,480 $6,883 Utility Plant Heater Boiler #4 

# $434,003 $59,540 $8,024 Utility Plant Heater Boiler #5 

# $434,003 $59,540 $8,646 Selective Non-Catalytic Reduction (SNCR) Utility Plant Heater Boiler #1 

# $1,084,406 $300,018 $42,037 Utility Plant Heater Boiler #2 

# $1,084,406 $300,018 $43,495 Utility Plant Heater Boiler #4 

# $1,277,232 $354,613 $47,792 Utility Plant Heater Boiler #5 

# $1,277,232 $354,613 $51,494Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission RatesScenario Control TechnologyNOxControlScenario SV #EmissionUnitNOx% Reduction Max 24-hour lbs/daySV 001 EU 001---194SV 002 EU 002---720SV 004 EU 004---231SV 005 EU 005---226SV 001 EU 00150%97SV 002 EU 00250%360SV 004 EU 00450%115SV 005 EU 00550%1130(baseline)BaselineIndurating Furnaces burning NaturalGas1Utility Plant Heating BoilersLow-NOx BurnersTable 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling ResultsScenario # SO2NOxClass I Areawith GreatestImpactModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasBWCA 5.508 177 7.201 168 5.962 160 6.209 50510BaselineIndurating Furnacesburning Natural GasUtility Plant HeatingBoilersLow-NOx BurnersBWCA 5.486 177 7.178 168 5.957 158 6.201 5032002 – 2004CombinedScenario Control Technology200220032004Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling ResultsScenario # Operating Conditions Operating ConditionsClass I Areawith GreatestImpactModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasBWCA 5.508 177 7.201 168 5.962 160 6.209 5051BaselineIndurating FurnacesburningSolid FuelsBaselineIndurating FurnacesburningSolid FuelsBWCA 4.78 173 6.377 162 5.26 155 5.52 4902Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasCurrent Operationw/ line 6 BurnersIndurating FurancesBurning Nat GasBWCA 5.333 176 7.005 168 5.807 157 6.043 5013Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelCurrent Operationw/ line 6 BurnersIndurating FurnacesBurning Solid FuelBWCA 4.642 171 6.189 159 5.106 148 5.365 4784Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasPorted Kilns(lines 3, 4, 5)Indurating FurancesBurning Nat GasBWCA 5.219 174 6.871 168 5.677 156 5.931 4985Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelPorted Kilns(lines 3, 4, 5)Indurating FurancesBurning Solid FuelBWCA 4.642 171 6.189 159 5.106 148 5.365 4782002200320042002 – 2004CombinedTable 6-1 Post-BART Modeling Scenarios - Visibility Modeling ResultsScenario # Operating Conditions Operating ConditionsClass I Areawith GreatestImpactModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview2002200320042002 – 2004Combined6Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasLow NOx Burners(lines 4, 5, 7)Indurating FurancesBurning Nat GasBWCA 5.088 174 6.713 166 5.542 153 5.758 4937Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelLow NOx Burners(lines 4, 5, 7)Indurating FurancesBurning Solid FuelBWCA 4.408 165 5.912 153 4.858 142 5.095 4608Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Nat GasPorted Kilns(lines 3, 4, 5)+Low NOx Burners(lines 4, 5, 7)Burning Nat GasBWCA 4.97173 6.574 162 5.417 153 5.641 4889Current Operationsw/ Line 3 ScrubberIndurating FurnacesBurning Solid FuelPorted Kilns(lines 3, 4, 5)+Low NOx Burners(lines 4, 5, 7)Indurating FurancesBurning Solid FuelBWCA 4.408 165 5.912 153 4.858 142 5.095 46010BaselineIndurating Furnacesburning Natural GasUtility Plant HeatingBoilersLow-NOx BurnersBWCA 5.486 177 7.178 168 5.957 158 6.201 503

# US Steel - Minntac 9/6/2006

BART Report - Attachment A: Emission Control Cost Ana lysis Table A.1: Furnaces Cost Summary

NO x 

## Control Cost Summary

Control Technology C ontrol Eff % Controlled Emissions T/y Emission

Reduction T/yr Installed Capital Cost $ Annualized

Operating Cost $/yr Pollution Control Cost $/ton Incremental

Control Cost $/ton Selective Catalytic Reduction with Reheat (SCR) Line 3 80% 269.0 1076.0 $69,222,423 $19,513,772 $18,135 n/a Line 4 80% 362.4 1449.6 $58,874,795 $28,169,433 $19,433 n/a Line 5 80% 364.0 1456.0 $58,874,795 $28,169,433 $19,347 n/a Line 6 80% 355.2 1420.8 $56,748,729 $26,419,264 $18,595 n/a Line 7 80% 385.6 1542.4 $56,748,729 $26,419,264 $17,129 n/a Lo w NO X 

### Burners + Ported Kilns L ine 3 n/a n/a n/a n/a n/a n/a n/a Line 4 15% 2908.6 248.5 $5,091,356 $480,588 $5,844 $5,076 Line 5 15% 3359.4 272.6 $6,474,892 $611,184 $5,974 $5,209 Line 6 n/a n/a n/a n/a n/a n/a n/a Line 7 n/a n/a n/a n/a n/a n/a n/a Low NO X 

### Burners L ine 3 n/a n/a n/a n/a n/a n/a n/a Line 4 10% 1630.8 181.2 $1,474,892 $139,219 $768 -$3,673 Line 5 10% 1638.0 182.0 $1,474,892 $139,219 $765 -$3,657 Line 6 n/a n/a n/a n/a n/a n/a n/a Line 7 10% 1735.2 192.8 $1,200,000 $113,272 $588 n/a Ported Kilns Line 3 5% 1277.8 67.3 $3,616,464 $341,369 $5,076 n/a Line 4 5% 1721.4 90.6 $5,000,000 $471,965 $5,209 n/a Line 5 5% 1729.0 91.0 $5,000,000 $471,965 $5,186 n/a Line 6 n/a n/a n/a n/a n/a n/a n/a Line 7 n/a n/a n/a n/a n/a n/a n/a



## SO 2 

## Control Cost Summary

Control Technology C ontrol Eff % Controlled Emissions T/y Emission

Reduction T/yr Installed Capital Cost $ Annualized

Operating Cost $/yr Pollution Control Cost $/ton Incremental

Control Cost $/ton

Line 3 80% 65.9 263.5 $27,948,027 $5,322,323 $20,201 n/a Line 4 80% 89.5 358.0 $39,347,773 $8,448,332 $23,597 n/a Line 5 80% 89.5 358.0 $39,347,773 $8,448,332 $23,597 n/a Line 6 80% 109.0 435.9 $36,370,821 $7,939,628 $18,216 n/a Line 7 80% 109.0 435.9 $37,793,453 $8,123,761 $18,638 n/a

Li ne 3 60% 131.7 197.6 $19,626,314 $2,816,433 $14,253 n/a Line 4 60% 179.0 268.5 $26,664,036 $4,123,939 $15,358 n/a Line 5 60% 179.0 268.5 $26,664,036 $4,123,939 $15,358 n/a Line 6 60% 217.9 326.9 $25,704,464 $3,953,025 $12,093 n/a Line 7 60% 217.9 326.9 $25,704,464 $3,953,025 $12,093 n/a Se condary Wet Scrubber (after existing scrubber) Wet Walled Electrostatic Precipitator (WWESP) (after existing scrubber)

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Cost Summary 9/7/2006 Page 1 of 75US Steel - MinntacBART Report - Attachment A: Emission Control Cost AnalysisTable A.2 - Summary of Utility, Chemical and Supply CostsOperating Unit:Line 3 waste gasStudy Year2006Emission Unit NumberEU 223Stack/Vent NumberSV 103Operating Unit:Line 4 waste gasEmission Unit NumberEU 259Stack/Vent NumberSV 118Operating Unit:Line 5 waste gasEmission Unit NumberEU 280Stack/Vent NumberSV 127Operating Unit:Line 6 waste gasEmission Unit NumberEU 313Stack/Vent NumberSV 144Operating Unit:Line 7 waste gasEmission Unit NumberEU 332Stack/Vent NumberSV 151ReferenceItemUnit Cost UnitsCost Year Data SourceNotesOperating Labor61 $/hrPer Chrissy Bartovich e-mailMaintenance Labor61 $/hrPer Chrissy Bartovich e-mailElectricity0.051 $/kwh2006Expected annual average industrial price ofelectricity in the West North Central Divisionfor 2007 - DOEhttp://tonto.eia.doe.gov/steo_query/app/elecpage.htmNatural Gas9.2575 $/mscf2005Energy Information Administration. AverageUS Industrial Natural Gas Prices. July '05 toJune '06.http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3m.htmWater0.08 $/mgal2006 Per Chrissy Bartovich e-mailCooling Water0.08 $/mgal2006 Per Chrissy Bartovich e-mailCompressed Air0.32 $/mscf0.25 1998EPA Air Pollution Control Cost Manual 6thEd 2002, Section 6 Chapter 1Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%inflationWastewater Disposal Neutralization1.69 $/mgal1.50 2002EPA Air Pollution Control Cost Manual 6thEd 2002, Section 2 Chapter 2.5.5.5Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch3 lists $1.30 - $2.15/1,000 galChemicals & SuppliesLime91.40 $/ton91.40 2006 Estimate from Cutler-Magney CompanyOxygen40.00 $/ton2006 BOC estimate.Ammonia (29% aqua.)0.12 $/lb0.101 2000EPA Air Pollution Control Cost Manual 6thEd 2002, Section 4 Chapter 2, page 2-50Annual costs for a retrofit SCR system example problem. '00 costsadjusted for 3% inflation.Caustic305.96 $/ton280 2003 Hawkins Chemical50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflationSCR Catalyst141.00 $/ft3Cormetech, Inc.OtherSales Tax6.5% %Interest Rate7.00% %EPA Air Pollution Control Cost ManualIntroduction, Chapter 2, section 2.4.2. Social (discount) rate used as a default.Operating InformationAnnual Op. Hrs7946 HoursEngineering EstimateUtilization Rate93%Equipment Life20 yrsEngineering EstimateY:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control CostsUtility Chem$ Data9/7/2006 Page 2 of 75Standardized Flow RateSV 103268,515 scfm @ 32o FCalculated.SV 118556,174 scfm @ 32o FCalculated.SV 127556,174 scfm @ 32o FCalculated.SV 144518,805 scfm @ 32o FCalculated.SV 151518,805 scfm @ 32o FCalculated.TemperatureSV 103130 Deg FBART spreadsheet.SV 118115 Deg FBART spreadsheet.SV 127115 Deg FBART spreadsheet.SV 144109 Deg FBART spreadsheet.SV 151109 Deg FBART spreadsheet.Moisture ContentSV 10310.5%Assumed value.SV 11810.5%Assumed value.SV 12710.5%Assumed value.SV 14410.5%Assumed value.SV 15110.5%Assumed value.Actual Flow RateSV 103322,000 acfmBART spreadsheet.SV 118650,000 acfmBART spreadsheet.SV 127650,000 acfmBART spreadsheet.SV 144600,000 acfmSame as line 7SV 151600,000 acfmBART spreadsheet.Standardized Flow RateSV 103288,163 scfm @ 68o FCalculated.SV 118596,870 scfm @ 68o FCalculated.SV 127596,870 scfm @ 68o FCalculated.SV 144556,766 scfm @ 68o FCalculated.SV 151556,766 scfm @ 68o FCalculated.Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control CostsUtility Chem$ Data9/7/2006 Page 3 of 75Dry Std Flow RateSV 103257,906 dscfm @ 68o FCalculated.SV 118534,198 dscfm @ 68o FCalculated.SV 127534,198 dscfm @ 68o FCalculated.SV 144498,306 dscfm @ 68o FCalculated.SV 151498,306 dscfm @ 68o FCalculated.24-hourMax Emis Projected future actual lb/hr ton/yearPollutantLb/Hr emissions (tpy)ppmv ppmvMax 24 hour emissions sourceProjected future actual emissions sourceNitrous Oxides (NOx)SV 103876.91,345.0 474 166.1 Based on max stack test plus 10%Based on 2005 AEI plus 10%.SV 1181353.01,812.0 353 108.0 Based on max stack test plus 10%Based on 2005 AEI plus 10%.SV 1271353.01,820.0 353 108.5 Based on max stack test plus 10%Based on 2005 AEI plus 10%.SV 1441202.31,776.0 336 113.5 Based on max stack test plus 10%Based on 2005 AEI plus 10%.SV 1511202.31,928.0 336 123.2 Based on max stack test plus 10%Based on 2005 AEI plus 10%.Sulfur Dioxides (SO2)SV 10398.6329.3 3829.2Based on max stack test plus 10%, minus30% to account for new scrubber.Based on AEI avg 2004/2005 plus 10%., minus 30% to account for newscrubber.SV 118146.3447.5 2719.2 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.SV 127146.3447.5 2719.2 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.SV 144184.8544.8 3725.0 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.SV 151184.8544.8 3725.0 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control CostsUtility Chem$ Data9/7/2006 Page 4 of 75

## US Steel - Minntac

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

## Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 3 waste gas

E mission Unit Number EU 223 Stack/Vent Number SV 103 Chemical Engineering Design Capacity 200 mmbtu/hr Standardized Flow Rate 268,515 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 130 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68o F Dry Std Flow Rate 257,906 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 28,387,757 Purchased Equipment Total SCR Only 30,232,961 SCR + Reheat 30,950,318

Total Capital Investment (TCI) = DC + IC SCR + Reheat 69,222,423
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 11,235,240 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 8,288,440 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 19,513,772



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 876.9 1,345.0 80% 269.0 1,076.0 18,135

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 = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 SCR Line3 SCR 5 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 28,387,757 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,845,204 Freight 5% of control device cost (A) NA Purchased Equipment Total 30,232,961

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 9% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 9% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 4,931,529
Total Plant Cost (D) A + B + C 37,808,389
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 756,168

Inventory Capital Reagent Vol * $/gal 102,618
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 38,667,175 Retrofit Factor (14) 60% of TCI 23,200,305 Sitework and foundations 1,400,000 Structural steel 4,800,000

Total Capital Investment Retrofit Installed 68,067,479



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 580,008 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 652 kW-hr, 7946 hr/yr, 93% utilization 245,543 SCR Catalyst 64.71 Catalyst Replacement 193,359 Ammonia (29% aqua.) 0.12 $/lb, 3,024 lb/hr, 7946 hr/yr, 93% utilization 2,694,872 Total Annual Direct Operating Costs 3,853,135

Indirect Operating Costs Overhead 60% of total labor and material costs 94,284 Administration (2% total capital costs) 2% of total capital costs (TCI) 773,343 Property tax (1% total capital costs) 1% of total capital costs (TCI) 386,672 Insurance (1% total capital costs) 1% of total capital costs (TCI) 386,672 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 6,425,089 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 8,066,059

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,919,195

See Summary page for notes and assumptions

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## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. #1 2708 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 288,163 scfm Vol #2 4408.7 ft 3 

### Amount Required 4,409 f t 3 

### Catalyst Cost 621,630 Y catalyst life factor 3 Years Annualized Cost 193,359

Equivalent Duty 1,547 Plant Cap kW A 158,727 Est power platn eff 35% Unc Nox lb/mmBtu B 0.62 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 158,727 Capital Cost $/kW D $150.00 $23,809,086.67 Total SCR Equipment Uncontrolled Nox t/y 3,840.9 Fixed O&M E $157,139.97 Annual Operating Hrs 7,946 Variable O&M F $394,208.98 Uncontrolled Nox lb/mmBtu 0.625 Ann Cap Factor G 0.82 Heat Input mmBtu/hr H 1,547

Electrical Use Equivalent Duty 1,547 MMBtu/hr kW NOx Cont Eff 80% Power 651.5 NOx in 0.62 lb/MMBtu n catalyst layers 4 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 651.5

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

### Density 87 7 lb/hr Neat 404.0 gal/hr 29% solution Volume 14 day inventory 135,729 gal $102,618 Inventory Cost 3024 lb/hr

Design Basis Max Emis Control Eff (%) lb/MMBtu 80% Nitrous Oxides (NOx) 0.625

Actual 77,372 dscf/MMBtu Method 19 Factor 10,000 dscf/MMBtu Adjusted Duty 1,547 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 580,008 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 651.5 kW-hr 4,814,574 245,543 $/kwh, 652 kW-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 193,359 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 3024 lb/hr 22,345,675 2,694,872 $/lb, 3,024 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 SCR Line3 SCR 7 of 75

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

## Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Line 3 waste gas

E mission Unit Number EU 223 Stack/Vent Number SV 103 Chemical Engineering Design Capacity 200 mmbtu/hr Standardized Flow Rate 268,515 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 130 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68o F Dry Std Flow Rate 257,906 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 590,417 Purchased Equipment Total (B) 22% of control device cost (A) 717,356

Installation - Standard Costs 30% of purchased equip cost (B) 215,207 Installation - Site Specific Costs NA Installation Total 215,207 Total Direct Capital Cost, DC 932,563 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 222,380 Total Capital Investment (TCI) = DC + IC 1,154,944
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 7,382,105 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,472 Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,594,577

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 Reheat Line3 Reheat 8 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 590,417 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 59,042 MN Sales Taxes 6.5% of control device cost (A) 38,377 Freight 5% of control device cost (A) 29,521 Purchased Equipment Total (B) 22% 717,356

Installation Foundations & supports 8% of purchased equip cost (B) 57,389 Handling & erection 14% of purchased equip cost (B) 100,430 Electrical 4% of purchased equip cost (B) 28,694 Piping 2% of purchased equip cost (B) 14,347 Insulation 1% of purchased equip cost (B) 7,174 Painting 1% of purchased equip cost (B) 7,174 Installation Subtotal Standard Expenses 30% 215,207

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 215,207 Total Direct Capital Cost, DC 932,563
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 71,736 Construction & field expenses 5% of purchased equip cost (B) 35,868 Contractor fees 10% of purchased equip cost (B) 71,736 Start-up 2% of purchased equip cost (B) 14,347 Performance test 1% of purchased equip cost (B) 7,174 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 21,521 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 222,380
Total Capital Investment (TCI) = DC + IC 1,154,944
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,154,944



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,193 kW-hr, 7946 hr/yr, 93% utilization 449,620 Natural Gas 9.26 $/mscf, 1,666 scfm, 7946 hr/yr, 93% utilization 6,837,058

Total Annual Direct Operating Costs 7,382,105

Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 23,099 Property tax (1% total capital costs) 1% of total capital costs (TCI) 11,549 Insurance (1% total capital costs) 1% of total capital costs (TCI) 11,549 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 109,019 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,472

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,594,577

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 Reheat Line3 Reheat 9 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Replacement Catalyst: Catalyst Equipment Life 3 years CRF 0.3811 Rep part cost per unit 0 $/ft 3 Amount Required 3 9 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 B lower, Thermal 322,000 19 0.6 1,193.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 322,000 23 0.6 1,444.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 1193.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1193.0 kW-hr 8,816,081 449,620 $/kwh, 1,193 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 1,666 scfm 738,543 6,837,058 $/mscf, 1,666 scfm, 7946 hr/yr, 93% utilization

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 Reheat Line3 Reheat 10 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

A uxiliary Fuel Use Equation 3.19 T wi 130 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 564 Deg F - Temperature of waste gas out of heat recovery

T fo 316 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 288,163 scfm - Flow of waste gas

Q af 1,666 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 289,828 scfm Flue Gas Cost in 1989 $'s $495,188 Current Cost Using CHE Plant Cost Index $590,417 Heat Rec % A B

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

Indurator Flue Gas Heat Capacity - Basis Typical Composition

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

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 Reheat Line3 Reheat 11 of 75

## US Steel - Minntac

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

## Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 4 waste gas

E mission Unit Number EU 259 Stack/Vent Number SV 118 Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 23,050,831 Purchased Equipment Total SCR Only 24,549,135 SCR + Reheat 25,409,745

Total Capital Investment (TCI) = DC + IC SCR + Reheat 58,874,795
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 21,125,878 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,066,876 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 28,169,433



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,812.0 80% 362.4 1,449.6 19,433

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 = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 SCR Line4 SCR 12 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,050,831 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,498,304 Freight 5% of control device cost (A) NA Purchased Equipment Total 24,549,135

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 11% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 4,078,955
Total Plant Cost (D) A + B + C 31,271,989
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 625,440
Inventory Capital Reagent Vol * $/gal 158,329
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 32,055,758 Retrofit Factor (14) 60% of TCI 19,233,455 Sitework and foundations 1,400,000 Structural steel 4,800,000

Total Capital Investment Retrofit Installed 57,489,212



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 480,836 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization 531,079 SCR Catalyst 64.71 Catalyst Replacement 400,504 Ammonia (29% aqua.) 0.12 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization 4,157,919 Total Annual Direct Operating Costs 5,709,691
Indirect Operating Costs Overhead 60% of total labor and material costs 91,281 Administration (2% total capital costs) 2% of total capital costs (TCI) 641,115 Property tax (1% total capital costs) 1% of total capital costs (TCI) 320,558 Insurance (1% total capital costs) 1% of total capital costs (TCI) 320,558 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,426,575 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,800,087

Total Annual Cost (Annualized Capital Cost + Operating Cost) 12,509,778

See Summary page for notes and assumptions

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## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. #1 2708 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 596,870 scfm Vol #2 9131.8 ft 3 

### Amount Required 9,132 f t 3 

### Catalyst Cost 1,287,579 Y catalyst life factor 3 Years Annualized Cost 400,504

Equivalent Duty 3,484 Plant Cap kW A 357,359 Est power platn eff 35% Unc Nox lb/mmBtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066 Equivalent power plant kW 357,359 Capital Cost $/kW D $64.50 $23,050,831.27 Total SCR Equipment Uncontrolled Nox t/y 1,353.0 Fixed O&M E $152,135.49 Annual Operating Hrs 8000 Variable O&M F $624,082.60 Uncontrolled Nox lb/mmBtu 0.428 Ann Cap Factor G 0.82 Heat Input mmBtu/hr H 6,000

Electrical Use Equivalent Duty 3,484 MMBtu/hr kW NOx Cont Eff 80% Power 1,409.2 NOx in 0.43 lb/MMBtu n catalyst layers 4 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 i n H 2 

### O To tal 1409.2

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

### Density 1353 lb/hr Neat 623.3 gal/hr 29% solution Volume 14 day inventory 209,416 gal $158,329 Inventory Cost 4666 lb/hr

Design Basis Max Emis Control Eff (%) lb/MMBtu 80% Nitrous Oxides (NOx) 0.428

Actual 106,840 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu Adjusted Duty 3,484 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 480,836 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1409.2 kW-hr 10,413,319 531,079 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 400,504 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 4666 lb/hr 34,477,146 4,157,919 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NO x 

## Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Line 4 waste gas

E mission Unit Number EU 259 Stack/Vent Number SV 118 Chemical Engineering Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 115 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 708,321 Purchased Equipment Total (B) 22% of control device cost (A) 860,610

Installation - Standard Costs 30% of purchased equip cost (B) 258,183 Installation - Site Specific Costs NA Installation Total 258,183 Total Direct Capital Cost, DC 1,118,793 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789 Total Capital Investment (TCI) = DC + IC 1,385,582
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,416,187 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468 Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655

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

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 708,321 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 70,832 MN Sales Taxes 6.5% of control device cost (A) 46,041 Freight 5% of control device cost (A) 35,416 Purchased Equipment Total (B) 22% 860,610

Installation Foundations & supports 8% of purchased equip cost (B) 68,849 Handling & erection 14% of purchased equip cost (B) 120,485 Electrical 4% of purchased equip cost (B) 34,424 Piping 2% of purchased equip cost (B) 17,212 Insulation 1% of purchased equip cost (B) 8,606 Painting 1% of purchased equip cost (B) 8,606 Installation Subtotal Standard Expenses 30% 258,183

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 258,183 Total Direct Capital Cost, DC 1,118,793
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 86,061 Construction & field expenses 5% of purchased equip cost (B) 43,031 Contractor fees 10% of purchased equip cost (B) 86,061 Start-up 2% of purchased equip cost (B) 17,212 Performance test 1% of purchased equip cost (B) 8,606 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,818 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789
Total Capital Investment (TCI) = DC + IC 1,385,582
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,385,582



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization 907,618 Natural Gas 9.26 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization 14,413,142

Total Annual Direct Operating Costs 15,416,187

Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,712 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,856 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,856 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,789 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468

Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655

See Summary page for notes and assumptions

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Replacement Catalyst: Catalyst Equipment Life 3 years CRF 0.3811 Rep part cost per unit 0 $/ft 3 Amount Required 3 9 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 B lower, Thermal 650,000 19 0.6 2,408.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 650,000 23 0.6 2,915.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2408.3

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2408.3 kW-hr 17,796,438 907,618 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization

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

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

A uxiliary Fuel Use Equation 3.19 T wi 115 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 560 Deg F - Temperature of waste gas out of heat recovery

T fo 306 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 596,870 scfm - Flow of waste gas

Q af 3,511 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 600,381 scfm Flue Gas Cost in 1989 $'s $594,076 Current Cost Using CHE Plant Cost Index $708,321 Heat Rec % A B

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

Indurator Flue Gas Heat Capacity - Basis Typical Composition

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

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

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## US Steel - Minntac

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

## Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 5 waste gas

E mission Unit Number EU 280 Stack/Vent Number SV 127 Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 23,050,831 Purchased Equipment Total SCR Only 24,549,135 SCR + Reheat 25,409,745

Total Capital Investment (TCI) = DC + IC SCR + Reheat 58,874,795
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 21,125,878 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,066,876 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 28,169,433



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,820.0 80% 364.0 1,456.0 19,347

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 = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,050,831 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,498,304 Freight 5% of control device cost (A) NA Purchased Equipment Total 24,549,135

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 11% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 4,078,955
Total Plant Cost (D) A + B + C 31,271,989
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 625,440
Inventory Capital Reagent Vol * $/gal 158,329
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 32,055,758 Retrofit Factor (14) 60% of TCI 19,233,455 Sitework and foundations 1,400,000 Structural steel 4,800,000

Total Capital Investment Retrofit Installed 57,489,212



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 480,836 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization 531,079 SCR Catalyst 64.71 Catalyst Replacement 400,504 Ammonia (29% aqua.) 0.12 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization 4,157,919 Total Annual Direct Operating Costs 5,709,691
Indirect Operating Costs Overhead 60% of total labor and material costs 91,281 Administration (2% total capital costs) 2% of total capital costs (TCI) 641,115 Property tax (1% total capital costs) 1% of total capital costs (TCI) 320,558 Insurance (1% total capital costs) 1% of total capital costs (TCI) 320,558 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,426,575 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,800,087

Total Annual Cost (Annualized Capital Cost + Operating Cost) 12,509,778

See Summary page for notes and assumptions

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## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. #1 2708 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 596,870 scfm Vol #2 9131.8 ft 3 

### Amount Required 9,132 f t 3 

### Catalyst Cost 1,287,579 Y catalyst life factor 3 Years Annualized Cost 400,504

Equivalent Duty 3,484 Plant Cap kW A 357,359 Est power platn eff 35% Unc Nox lb/mmBtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066 Equivalent power plant kW 357,359 Capital Cost $/kW D $64.50 $23,050,831.27 Total SCR Equipment Uncontrolled Nox t/y 1,353.0 Fixed O&M E $152,135.49 Annual Operating Hrs 8000 Variable O&M F $624,082.60 Uncontrolled Nox lb/mmBtu 0.428 Ann Cap Factor G 0.82 Heat Input mmBtu/hr H 6,000 SCR Capital Cost

Electrical Use Duty 3,484 MMBtu/hr kW NOx Cont Eff 80% Power 1,409.2 NOx in 0.43 lb/MMBtu n catalyst layers 4 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 i n H 2 

### O To tal 1409.2

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

### Density 1353 lb/hr Neat 623.3 gal/hr 29% solution Volume 14 day inventory 209,416 gal $158,329 Inventory Cost 4666 lb/hr

Design Basis Max Emis Control Eff (%) lb/MMBtu 80% Nitrous Oxides (NOx) 0.428

Actual 106,840 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu Adjusted Duty 3,484 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 480,836 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1409.2 kW-hr 10,413,319 531,079 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 400,504 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 4666 lb/hr 34,477,146 4,157,919 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NO x 

## Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Line 5 waste gas

E mission Unit Number EU 280 Stack/Vent Number SV 127 Chemical Engineering Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 115 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 708,321 Purchased Equipment Total (B) 22% of control device cost (A) 860,610

Installation - Standard Costs 30% of purchased equip cost (B) 258,183 Installation - Site Specific Costs NA Installation Total 258,183 Total Direct Capital Cost, DC 1,118,793 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789 Total Capital Investment (TCI) = DC + IC 1,385,582
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,416,187 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468 Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655

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

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 708,321 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 70,832 MN Sales Taxes 6.5% of control device cost (A) 46,041 Freight 5% of control device cost (A) 35,416 Purchased Equipment Total (B) 22% 860,610

Installation Foundations & supports 8% of purchased equip cost (B) 68,849 Handling & erection 14% of purchased equip cost (B) 120,485 Electrical 4% of purchased equip cost (B) 34,424 Piping 2% of purchased equip cost (B) 17,212 Insulation 1% of purchased equip cost (B) 8,606 Painting 1% of purchased equip cost (B) 8,606 Installation Subtotal Standard Expenses 30% 258,183

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 258,183 Total Direct Capital Cost, DC 1,118,793
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 86,061 Construction & field expenses 5% of purchased equip cost (B) 43,031 Contractor fees 10% of purchased equip cost (B) 86,061 Start-up 2% of purchased equip cost (B) 17,212 Performance test 1% of purchased equip cost (B) 8,606 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,818 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789
Total Capital Investment (TCI) = DC + IC 1,385,582
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,385,582



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization 907,618 Natural Gas 9.26 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization 14,413,142

Total Annual Direct Operating Costs 15,416,187

Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,712 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,856 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,856 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,789 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468

Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655

See Summary page for notes and assumptions

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Replacement Catalyst: Catalyst Equipment Life 3 years CRF 0.3811 Rep part cost per unit 0 $/ft 3 Amount Required 3 9 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 B lower, Thermal 650,000 19 0.6 2,408.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 650,000 23 0.6 2,915.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2408.3

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2408.3 kW-hr 17,796,438 907,618 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization

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

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

A uxiliary Fuel Use Equation 3.19 T wi 115 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 560 Deg F - Temperature of waste gas out of heat recovery

T fo 306 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 596,870 scfm - Flow of waste gas

Q af 3,511 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 600,381 scfm Flue Gas Cost in 1989 $'s $594,076 Current Cost Using CHE Plant Cost Index $708,321 Heat Rec % A B

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

Indurator Flue Gas Heat Capacity - Basis Typical Composition

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

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

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## US Steel - Minntac

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

## Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 6 waste gas

E mission Unit Number EU 313 Stack/Vent Number SV 144 Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32o F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 22,013,215 Purchased Equipment Total SCR Only 23,444,074 SCR + Reheat 24,289,858

Total Capital Investment (TCI) = DC + IC SCR + Reheat 56,748,729
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 19,634,014 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 6,807,183 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 26,419,264



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,202.3 1,776.0 80% 355.2 1,420.8 18,595

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 = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,013,215 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,430,859 Freight 5% of control device cost (A) NA Purchased Equipment Total 23,444,074

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 11% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 3,913,196
Total Plant Cost (D) A + B + C 30,001,168
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 600,023
Inventory Capital Reagent Vol * $/gal 140,694
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 30,741,886 Retrofit Factor (14) 60% of TCI 18,445,131 Sitework and foundations 1,400,000 Structural steel 4,800,000

Total Capital Investment Retrofit Installed 55,387,017



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 461,128 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization 493,304 SCR Catalyst 64.71 Catalyst Replacement 373,594 Ammonia (29% aqua.) 0.12 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization 3,694,801 Total Annual Direct Operating Costs 5,162,181
Indirect Operating Costs Overhead 60% of total labor and material costs 87,172 Administration (2% total capital costs) 2% of total capital costs (TCI) 614,838 Property tax (1% total capital costs) 1% of total capital costs (TCI) 307,419 Insurance (1% total capital costs) 1% of total capital costs (TCI) 307,419 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,228,143 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,544,990

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,707,171

See Summary page for notes and assumptions

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## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. #1 2708 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 556,766 scfm Vol #2 8518.2 ft 3 

### Amount Required 8,518 f t 3 

### Catalyst Cost 1,201,067 Y catalyst life factor 3 Years Annualized Cost 373,594

Equivalent Duty 3,250 Plant Cap kW A 333,349 Est power platn eff 35% Unc Nox lb/mmBtu B 0.41 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 333,349 Capital Cost $/kW D $66.04 $22,013,215.04 Total SCR Equipment Uncontrolled Nox t/y 1,202.3 Fixed O&M E $145,287.22 Annual Operating Hrs 8000 Variable O&M F $586,106.42 Uncontrolled Nox lb/mmBtu 0.408 Ann Cap Factor G 0.82 Heat Input mmBtu/hr H 6,000 SCR Capital Cost

Electrical Use Duty 3,250 MMBtu/hr kW NOx Cont Eff 80% Power 1,308.9 NOx in 0.41 lb/MMBtu n catalyst layers 4 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 i n H 2 

### O To tal 1308.9

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

### Density 1202 lb/hr Neat 553.8 gal/hr 29% solution Volume 14 day inventory 186,091 gal $140,694 Inventory Cost 4146 lb/hr

Design Basis Max Emis Control Eff (%) lb/MMBtu 80% Nitrous Oxides (NOx) 0.408

Actual 99,661 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu Adjusted Duty 3,250 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 461,128 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1308.9 kW-hr 9,672,634 493,304 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 373,594 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 4146 lb/hr 30,637,009 3,694,801 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NO x 

## Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Line 6 waste gas

E mission Unit Number EU 313 Stack/Vent Number SV 144 Chemical Engineering Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 109 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 696,118 Purchased Equipment Total (B) 22% of control device cost (A) 845,784

Installation - Standard Costs 30% of purchased equip cost (B) 253,735 Installation - Site Specific Costs NA Installation Total 253,735 Total Direct Capital Cost, DC 1,099,519 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193 Total Capital Investment (TCI) = DC + IC 1,361,712
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,471,833 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260 Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093

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

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 696,118 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 69,612 MN Sales Taxes 6.5% of control device cost (A) 45,248 Freight 5% of control device cost (A) 34,806 Purchased Equipment Total (B) 22% 845,784

Installation Foundations & supports 8% of purchased equip cost (B) 67,663 Handling & erection 14% of purchased equip cost (B) 118,410 Electrical 4% of purchased equip cost (B) 33,831 Piping 2% of purchased equip cost (B) 16,916 Insulation 1% of purchased equip cost (B) 8,458 Painting 1% of purchased equip cost (B) 8,458 Installation Subtotal Standard Expenses 30% 253,735

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 253,735 Total Direct Capital Cost, DC 1,099,519
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 84,578 Construction & field expenses 5% of purchased equip cost (B) 42,289 Contractor fees 10% of purchased equip cost (B) 84,578 Start-up 2% of purchased equip cost (B) 16,916 Performance test 1% of purchased equip cost (B) 8,458 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,374 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193
Total Capital Investment (TCI) = DC + IC 1,361,712
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,361,712



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization 837,802 Natural Gas 9.26 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization 13,538,605

Total Annual Direct Operating Costs 14,471,833

Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,234 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,617 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,617 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 128,536 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093

See Summary page for notes and assumptions

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Replacement Catalyst: Catalyst Equipment Life 3 years CRF 0.3811 Rep part cost per unit 0 $/ft 3 Amount Required 3 9 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 B lower, Thermal 600,000 19 0.6 2,223.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 600,000 23 0.6 2,691.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2223.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2223.0 kW-hr 16,427,481 837,802 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 3,298 scfm 1,462,447 13,538,605 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization

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

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

A uxiliary Fuel Use Equation 3.19 T wi 109 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 558 Deg F - Temperature of waste gas out of heat recovery

T fo 301 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 556,766 scfm - Flow of waste gas

Q af 3,298 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 560,065 scfm Flue Gas Cost in 1989 $'s $583,841 Current Cost Using CHE Plant Cost Index $696,118 Heat Rec % A B

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

Indurator Flue Gas Heat Capacity - Basis Typical Composition

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

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

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## US Steel - Minntac

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

## Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 7 waste gas

E mission Unit Number EU 332 Stack/Vent Number SV 151 Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32o F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 22,013,215 Purchased Equipment Total SCR Only 23,444,074 SCR + Reheat 24,289,858

Total Capital Investment (TCI) = DC + IC SCR + Reheat 56,748,729
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 19,634,014 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 6,807,183 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 26,419,264



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,202.3 1,928.0 80% 385.6 1,542.4 17,129

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 = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,013,215 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,430,859 Freight 5% of control device cost (A) NA Purchased Equipment Total 23,444,074

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 11% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 3,913,196
Total Plant Cost (D) A + B + C 30,001,168
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 600,023
Inventory Capital Reagent Vol * $/gal 140,694
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 30,741,886 Retrofit Factor (14) 60% of TCI 18,445,131 Sitework and foundations 1,400,000 Structural steel 4,800,000

Total Capital Investment Retrofit Installed 55,387,017



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 461,128 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization 493,304 SCR Catalyst 64.71 Catalyst Replacement 373,594 Ammonia (29% aqua.) 0.12 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization 3,694,801 Total Annual Direct Operating Costs 5,162,181
Indirect Operating Costs Overhead 60% of total labor and material costs 87,172 Administration (2% total capital costs) 2% of total capital costs (TCI) 614,838 Property tax (1% total capital costs) 1% of total capital costs (TCI) 307,419 Insurance (1% total capital costs) 1% of total capital costs (TCI) 307,419 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,228,143 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,544,990

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,707,171

See Summary page for notes and assumptions

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## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. #1 2708 ft 3 

### Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 556,766 scfm Vol #2 8518.2 ft 3 

### Amount Required 8,518 f t 3 

### Catalyst Cost 1,201,067 Y catalyst life factor 3 Years Annualized Cost 373,594

Equivalent Duty 3,250 Plant Cap kW A 333,349 Est power platn eff 35% Unc Nox lb/mmBtu B 0.41 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 333,349 Capital Cost $/kW D $66.04 $22,013,215.04 Total SCR Equipment Uncontrolled Nox t/y 1,202.3 Fixed O&M E $145,287.22 Annual Operating Hrs 8000 Variable O&M F $586,106.42 Uncontrolled Nox lb/mmBtu 0.408 Ann Cap Factor G 0.82 Heat Input mmBtu/hr H 6,000 SCR Capital Cost

Electrical Use Duty 3,250 MMBtu/hr kW NOx Cont Eff 80% Power 1,308.9 NOx in 0.41 lb/MMBtu n catalyst layers 4 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 i n H 2 

### O To tal 1308.9

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

### Density 1202 lb/hr Neat 553.8 gal/hr 29% solution Volume 14 day inventory 186,091 gal $140,694 Inventory Cost 4146 lb/hr

Design Basis Max Emis Control Eff (%) lb/MMBtu 80% Nitrous Oxides (NOx) 0.408

Actual 99,661 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu Adjusted Duty 3,250 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 461,128 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1308.9 kW-hr 9,672,634 493,304 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 373,594 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 4146 lb/hr 30,637,009 3,694,801 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 SCR Line7 SCR 35 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NO x 

## Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 7 waste gas

E mission Unit Number EU 332 Stack/Vent Number SV 151 Chemical Engineering Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 109 Deg F 1998/1999 390 Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 696,118 Purchased Equipment Total (B) 22% of control device cost (A) 845,784

Installation - Standard Costs 30% of purchased equip cost (B) 253,735 Installation - Site Specific Costs NA Installation Total 253,735 Total Direct Capital Cost, DC 1,099,519 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193 Total Capital Investment (TCI) = DC + IC 1,361,712
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,471,833 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260 Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 Reheat Line7 Reheat 36 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 696,118 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 69,612 MN Sales Taxes 6.5% of control device cost (A) 45,248 Freight 5% of control device cost (A) 34,806 Purchased Equipment Total (B) 22% 845,784

Installation Foundations & supports 8% of purchased equip cost (B) 67,663 Handling & erection 14% of purchased equip cost (B) 118,410 Electrical 4% of purchased equip cost (B) 33,831 Piping 2% of purchased equip cost (B) 16,916 Insulation 1% of purchased equip cost (B) 8,458 Painting 1% of purchased equip cost (B) 8,458 Installation Subtotal Standard Expenses 30% 253,735

Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 253,735 Total Direct Capital Cost, DC 1,099,519
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 84,578 Construction & field expenses 5% of purchased equip cost (B) 42,289 Contractor fees 10% of purchased equip cost (B) 84,578 Start-up 2% of purchased equip cost (B) 16,916 Performance test 1% of purchased equip cost (B) 8,458 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,374 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193
Total Capital Investment (TCI) = DC + IC 1,361,712
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,361,712



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization 837,802 Natural Gas 9.26 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization 13,538,605

Total Annual Direct Operating Costs 14,471,833

Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,234 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,617 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,617 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 128,536 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 Reheat Line7 Reheat 37 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

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

Replacement Catalyst: Catalyst Equipment Life 3 years CRF 0.3811 Rep part cost per unit 0 $/ft 3 Amount Required 3 9 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 B lower, Thermal 600,000 19 0.6 2,223.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 600,000 23 0.6 2,691.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2223.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2223.0 kW-hr 16,427,481 837,802 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 3,298 scfm 1,462,447 13,538,605 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 Reheat Line7 Reheat 38 of 75

## US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

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

A uxiliary Fuel Use Equation 3.19 T wi 109 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 558 Deg F - Temperature of waste gas out of heat recovery

T fo 301 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 556,766 scfm - Flow of waste gas

Q af 3,298 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 560,065 scfm Flue Gas Cost in 1989 $'s $583,841 Current Cost Using CHE Plant Cost Index $696,118 Heat Rec % A B

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

Indurator Flue Gas Heat Capacity - Basis Typical Composition

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

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 Reheat Line7 Reheat 39 of 75

# US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.4.a: NO X 

# Control - Low-NO X 

# Burners

Operating Unit: L ine 4 waste gas

Em ission Unit Number EU 259 Stack/Vent Number SV 118 Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS Capital Costs (1)



### Total Capital Investment (TCI) = DC + IC 1,474,892
Operating Costs (2) 

### Total Annual Cost (Annualized Capital Cost) 139,219

Capital Recovery Factor

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944 Capital Recovery Cost 139,219

Actual 

## Emission Control Cost Calculation Emis Ma x Emis Annual Control Eff (3) 

### Exit Conc. Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,812.0 10% 1630.8 181.2 768 Sulfur Dioxide (SO 2 

### ) 146.3 447.5 0% NA NA NA

Notes & Assumptions 1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section Cost is ratioed to Line 4 burner size using 6/10 rule based on Line 6 burner size of 117 mmbtu/hr and Line 6 cost of $1.2 million 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on estimated reduction of line 6 total NO X 

### emissions based on NO X 

### CEMS

# US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.4.b: NO X 

# Control - Low-NO X 

# Burners

Operating Unit: L ine 5 waste gas

Em ission Unit Number EU 280 Stack/Vent Number SV 127 Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS Capital Costs (1)



### Total Capital Investment (TCI) = DC + IC 1,474,892
Operating Costs (2) 

### Total Annual Cost (Annualized Capital Cost) 139,219

Capital Recovery Factor

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944 Capital Recovery Cost 139,219

Actual 

## Emission Control Cost Calculation Emis Ma x Emis Annual Control Eff (3) 

### Exit Conc. Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,820.0 10% 1638.0 182.0 765 Sulfur Dioxide (SO 2 

### ) 146.3 447.5 0% NA NA NA

Notes & Assumptions 1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section Cost is ratioed to Line 5 burner size using 6/10 rule based on Line 6 burner size of 117 mmbtu/hr and Line 6 cost of $1.2 million 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on estimated reduction of line 6 total NO X 

### emissions based on NO X 

### CEMS

# US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.4.c: NO X 

# Control - Low-NO X 

# Burners

Operating Unit: L ine 7 waste gas

Em ission Unit Number EU 332 Stack/Vent Number SV 151 Standardized Flow Rate 518,805 scfm @ 32o F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS Capital Costs (1)



### Total Capital Investment (TCI) = DC + IC 1,200,000
Operating Costs (2) 

### Total Annual Cost (Annualized Capital Cost) 113,272

Capital Recovery Factor

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944 Capital Recovery Cost 113,272

Actual 

## Emission Control Cost Calculation Emis Ma x Emis Annual Control Eff (3) 

### Exit Conc. Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,202.3 1,928.0 10% 1735.2 192.8 588 Sulfur Dioxide (SO 2 

### ) 184.8 544.8 0% NA NA NA

Notes & Assumptions 1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on estimated reduction of line 6 total NO X 

### emissions based on NO X 

### CEMS

# US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.5.a: NO X 

# Control - Ported Kilns

Operating Unit: L ine 3 waste gas

Em ission Unit Number EU 223 Stack/Vent Number SV 103 Standardized Flow Rate 268,515 scfm @ 32o F Expected Utilization Rate 93% Temperature 130 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68o F Dry Std Flow Rate 257,906 dscfm @ 68o F Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS Capital Costs (1) 

### Minntac Line 4/5 Budget Estimate = 5,000,000 $ Total Capital Investment (TCI) = DC + IC 3,616,464 Minntac Line 4/5 volumetric flow = 650,000 acfm Operating Costs (2) 

### Minntac Line 3 volumetric flow = 378,824 acfm Total Annual Cost (Annualized Capital Cost) 341,369 Use "6/10 Rule" to calculate Line 3 Cost = 3,616,464 $

Capital Recovery Factor

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944 Capital Recovery Cost 341,369

Actual 

## Emission Control Cost Calculation Emis Ma x Emis Annual Control Eff (3) 

### Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 876.9 1,345.0 5% 1277.8 67.3 5,076

Notes & Assumptions 1 Capital costs based on Minntac Line 4/5 budget estimate and scaled to Line 3 stack flow rate. 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on report, "NO X 

### Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."

# US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.5.b: NO X 

# Control - Ported Kilns

Operating Unit: L ine 4 waste gas

Em ission Unit Number EU 259 Stack/Vent Number SV 118 Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS Capital Costs (1)



### Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = 5,000,000 $

Operating Costs (2) 

### Total Annual Cost (Annualized Capital Cost) 471,965

Capital Recovery Factor

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944 Capital Recovery Cost 471,965

Actual 

## Emission Control Cost Calculation Emis Ma x Emis Annual Control Eff (3) 

### Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,812.0 5% 1721.4 90.6 5,209

Notes & Assumptions 1 Capital costs based on Minntac Line 4/5 budget estimate. 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on report, "NO X 

### Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."

# US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.5.c: NO X 

# Control - Ported Kilns

Operating Unit: L ine 5 waste gas

Em ission Unit Number EU 280 Stack/Vent Number SV 127 Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS Capital Costs (1)



### Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = 5,000,000 $

Operating Costs (2) 

### Total Annual Cost (Annualized Capital Cost) 471,965

Capital Recovery Factor

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944 Capital Recovery Cost 471,965

Actual 

## Emission Control Cost Calculation Emis Ma x Emis Annual Control Eff (3) 

### Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,820.0 5% 1729.0 91.0 5,186

Notes & Assumptions 1 Capital costs based on Minntac Line 4/5 budget estimate. 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on report, "NO X 

### Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.a: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 3 waste gas

E mission Unit Number EU 223 Stack/Vent Number SV 103 Standardized Flow Rate 268,515 scfm @ 32o F Expected Utilization Rate 93% Temperature 130 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68o F Dry Std Flow Rate 257,906 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 4,994,311 Purchased Equipment Total (B) 22% of control device cost (A) 6,068,088

Installation - Standard Costs 67% of purchased equip cost (B) 4,065,619 Installation - Site Specific Costs 6,200,000 Installation Total 4,065,619 Total Direct Capital Cost, DC 10,133,707 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810 Total Capital Investment (TCI) = DC + IC 27,948,027
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,023,179 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,299,144 Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,322,323

Actual 

### Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 876.9 1,345.0 0% 1345.0

- NA Sulfur Dioxide (SO 2 ) 98.6 329.3 80% 65.9 263.5 20,201

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

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## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 4,994,311 Instrumentation 10% of control device cost (A) 499,431 MN Sales Taxes 6.5% of control device cost (A) 324,630 Freight 5% of control device cost (A) 249,716 Purchased Equipment Total (B) 22% 6,068,088

Installation Foundations & supports 4% of purchased equip cost (B) 242,724 Handling & erection 50% of purchased equip cost (B) 3,034,044 Electrical 8% of purchased equip cost (B) 485,447 Piping 1% of purchased equip cost (B) 60,681 Insulation 2% of purchased equip cost (B) 121,362 Painting 2% of purchased equip cost (B) 121,362 Installation Subtotal Standard Expenses 67% 4,065,619
Total Direct Capital Cost, DC 10,133,707
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,213,618 Construction & field expenses 20% of purchased equip cost (B) 1,213,618 Contractor fees 10% of purchased equip cost (B) 606,809 Start-up 1% of purchased equip cost (B) 60,681 Performance test 1% of purchased equip cost (B) 60,681 Model Studies 2% of purchased equip cost (B) 121,362 Contingencies 3% of purchased equip cost (B) 182,043 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810
Total Capital Investment (TCI) = DC + IC 13,592,517 Retrofit multiplier 3 60% of TCI 8,155,510

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 27,948,027



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 6,283 Maintenance Materials 1.00 % of Maintenance Labor 49,943 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization 286,765 Water 0.08 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization 57,108 WW Treat Neutralization 1.69 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization 1,205,171 Caustic 305.96 $/ton, 246 lb/hr, 7946 hr/yr, 93% utilization 278,556 Total Annual Direct Operating Costs 2,023,179
Indirect Operating Costs Overhead 60% of total labor and material costs 117,347 Administration (2% total capital costs) 2% of total capital costs (TCI) 271,850 Property tax (1% total capital costs) 1% of total capital costs (TCI) 135,925 Insurance (1% total capital costs) 1% of total capital costs (TCI) 135,925 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,638,096 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,299,144

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,322,323

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 WWESP 9/7/2006 Page 47 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator

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

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0

Electrical Use Flow acfm D P in H2O kW Fan Power 322,000 10 582.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 30.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 76,157 147.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 760.9

Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm 1610.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 246.40 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 15.0 hr/wk 660 6,283 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 49,943 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 760.9 kW-hr 5,622,840 286,765 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 1,610.0 gpm 713,853 57,108 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 1,610.0 gpm 713,853 1,205,171 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization Caustic 305.96 $/ton 246.4 lb/hr 910 278,556 $/ton, 246 lb/hr, 7946 hr/yr, 93% utilization

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 WWESP 9/7/2006 Page 48 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.b: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 4 waste gas

E mission Unit Number EU 259 Stack/Vent Number SV 118 Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 7,612,198 Purchased Equipment Total (B) 22% of control device cost (A) 9,248,821

Installation - Standard Costs 67% of purchased equip cost (B) 6,196,710 Installation - Site Specific Costs 6,200,000 Installation Total 6,196,710 Total Direct Capital Cost, DC 15,445,530 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828 Total Capital Investment (TCI) = DC + IC 39,347,773
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,768,592 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332

Actual 

### Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,812.0 0% 1812.0

- NA Sulfur Dioxide (SO 2 ) 146.3 447.5 80% 89.5 358.0 23,597

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 WWESP 9/7/2006 Page 49 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 7,612,198 Instrumentation 10% of control device cost (A) 761,220 MN Sales Taxes 6.5% of control device cost (A) 494,793 Freight 5% of control device cost (A) 380,610 Purchased Equipment Total (B) 22% 9,248,821

Installation Foundations & supports 4% of purchased equip cost (B) 369,953 Handling & erection 50% of purchased equip cost (B) 4,624,410 Electrical 8% of purchased equip cost (B) 739,906 Piping 1% of purchased equip cost (B) 92,488 Insulation 2% of purchased equip cost (B) 184,976 Painting 2% of purchased equip cost (B) 184,976 Installation Subtotal Standard Expenses 67% 6,196,710
Total Direct Capital Cost, DC 15,445,530
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,849,764 Construction & field expenses 20% of purchased equip cost (B) 1,849,764 Contractor fees 10% of purchased equip cost (B) 924,882 Start-up 1% of purchased equip cost (B) 92,488 Performance test 1% of purchased equip cost (B) 92,488 Model Studies 2% of purchased equip cost (B) 184,976 Contingencies 3% of purchased equip cost (B) 277,465 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828
Total Capital Investment (TCI) = DC + IC 20,717,358 Retrofit multiplier 3 60% of TCI 12,430,415

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 39,347,773



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 12,683 Maintenance Materials 1.00 % of Maintenance Labor 76,122 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization 578,873 Water 0.08 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 115,281 WW Treat Neutralization 1.69 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 2,432,799 Caustic 305.96 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization 413,481 Total Annual Direct Operating Costs 3,768,592
Indirect Operating Costs Overhead 60% of total labor and material costs 136,895 Administration (2% total capital costs) 2% of total capital costs (TCI) 414,347 Property tax (1% total capital costs) 1% of total capital costs (TCI) 207,174 Insurance (1% total capital costs) 1% of total capital costs (TCI) 207,174 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,714,151 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 WWESP 9/7/2006 Page 50 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator

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

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0

Electrical Use Flow acfm D P in H2O kW Fan Power 650,000 10 1,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 61.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 153,733 298.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,536.0

Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm 3250.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 365.75 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 15.0 hr/wk 660 12,683 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 76,122 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1536.0 kW-hr 11,350,454 578,873 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 3,250.0 gpm 1,441,007 115,281 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 3,250.0 gpm 1,441,007 2,432,799 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization Caustic 305.96 $/ton 365.8 lb/hr 1,351 413,481 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 WWESP 9/7/2006 Page 51 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.c: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 5 waste gas

E mission Unit Number EU 280 Stack/Vent Number SV 127 Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 7,612,198 Purchased Equipment Total (B) 22% of control device cost (A) 9,248,821

Installation - Standard Costs 67% of purchased equip cost (B) 6,196,710 Installation - Site Specific Costs 6,200,000 Installation Total 6,196,710 Total Direct Capital Cost, DC 15,445,530 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828 Total Capital Investment (TCI) = DC + IC 39,347,773
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,768,592 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332

Actual 

### Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,820.0 0% 1820.0

- NA Sulfur Dioxide (SO 2 ) 146.3 447.5 80% 89.5 358.0 23,597

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 WWESP 9/7/2006 Page 52 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 7,612,198 Instrumentation 10% of control device cost (A) 761,220 MN Sales Taxes 6.5% of control device cost (A) 494,793 Freight 5% of control device cost (A) 380,610 Purchased Equipment Total (B) 22% 9,248,821

Installation Foundations & supports 4% of purchased equip cost (B) 369,953 Handling & erection 50% of purchased equip cost (B) 4,624,410 Electrical 8% of purchased equip cost (B) 739,906 Piping 1% of purchased equip cost (B) 92,488 Insulation 2% of purchased equip cost (B) 184,976 Painting 2% of purchased equip cost (B) 184,976 Installation Subtotal Standard Expenses 67% 6,196,710
Total Direct Capital Cost, DC 15,445,530
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,849,764 Construction & field expenses 20% of purchased equip cost (B) 1,849,764 Contractor fees 10% of purchased equip cost (B) 924,882 Start-up 1% of purchased equip cost (B) 92,488 Performance test 1% of purchased equip cost (B) 92,488 Model Studies 2% of purchased equip cost (B) 184,976 Contingencies 3% of purchased equip cost (B) 277,465 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828
Total Capital Investment (TCI) = DC + IC 20,717,358 Retrofit multiplier 3 60% of TCI 12,430,415

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 39,347,773



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 12,683 Maintenance Materials 1.00 % of Maintenance Labor 76,122 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization 578,873 Water 0.08 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 115,281 WW Treat Neutralization 1.69 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 2,432,799 Caustic 305.96 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization 413,481 Total Annual Direct Operating Costs 3,768,592
Indirect Operating Costs Overhead 60% of total labor and material costs 136,895 Administration (2% total capital costs) 2% of total capital costs (TCI) 414,347 Property tax (1% total capital costs) 1% of total capital costs (TCI) 207,174 Insurance (1% total capital costs) 1% of total capital costs (TCI) 207,174 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,714,151 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 WWESP 9/7/2006 Page 53 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator

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

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0

Electrical Use Flow acfm D P in H2O kW Fan Power 650,000 10 1,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 61.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 153,733 298.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,536.0

Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm 3250.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 365.75 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 15.0 hr/wk 660 12,683 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 76,122 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1536.0 kW-hr 11,350,454 578,873 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 3,250.0 gpm 1,441,007 115,281 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 3,250.0 gpm 1,441,007 2,432,799 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization Caustic 305.96 $/ton 365.8 lb/hr 1,351 413,481 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 WWESP 9/7/2006 Page 54 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.d: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 6 waste gas

E mission Unit Number EU 313 Stack/Vent Number SV 144 Standardized Flow Rate 518,805 scfm @ 32o F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 6,928,558 Purchased Equipment Total (B) 22% of control device cost (A) 8,418,198

Installation - Standard Costs 67% of purchased equip cost (B) 5,640,193 Installation - Site Specific Costs 6,200,000 Installation Total 5,640,193 Total Direct Capital Cost, DC 14,058,391 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,798,373 Total Capital Investment (TCI) = DC + IC 36,370,821
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,620,521 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,319,107 Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,939,628

Actual 

### Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,202.3 1,776.0 0% 1776.0

- NA Sulfur Dioxide (SO 2 ) 184.8 544.8 80% 109.0 435.9 18,216

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 WWESP 9/7/2006 Page 55 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 6,928,558 Instrumentation 10% of control device cost (A) 692,856 MN Sales Taxes 6.5% of control device cost (A) 450,356 Freight 5% of control device cost (A) 346,428 Purchased Equipment Total (B) 22% 8,418,198

Installation Foundations & supports 4% of purchased equip cost (B) 336,728 Handling & erection 50% of purchased equip cost (B) 4,209,099 Electrical 8% of purchased equip cost (B) 673,456 Piping 1% of purchased equip cost (B) 84,182 Insulation 2% of purchased equip cost (B) 168,364 Painting 2% of purchased equip cost (B) 168,364 Installation Subtotal Standard Expenses 67% 5,640,193
Total Direct Capital Cost, DC 14,058,391
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,683,640 Construction & field expenses 20% of purchased equip cost (B) 1,683,640 Contractor fees 10% of purchased equip cost (B) 841,820 Start-up 1% of purchased equip cost (B) 84,182 Performance test 1% of purchased equip cost (B) 84,182 Model Studies 2% of purchased equip cost (B) 168,364 Contingencies 3% of purchased equip cost (B) 252,546 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,798,373
Total Capital Investment (TCI) = DC + IC 18,856,763 Retrofit multiplier 3 60% of TCI 11,314,058

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 36,370,821



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 10,842 Maintenance Materials 1.00 % of Maintenance Labor 69,286 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,397 kW-hr, 7946 hr/yr, 93% utilization 526,675 Water 0.08 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 106,413 WW Treat Neutralization 1.69 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 2,245,661 Caustic 305.96 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization 522,292 Total Annual Direct Operating Costs 3,620,521
Indirect Operating Costs Overhead 60% of total labor and material costs 131,688 Administration (2% total capital costs) 2% of total capital costs (TCI) 377,135 Property tax (1% total capital costs) 1% of total capital costs (TCI) 188,568 Insurance (1% total capital costs) 1% of total capital costs (TCI) 188,568 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,433,148 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,319,107

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,939,628

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 WWESP 9/7/2006 Page 56 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator

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

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0

Electrical Use Flow acfm D P in H2O kW Fan Power 600,000 10 1,086.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 56.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 131,418 255.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,397.5

Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm 3000.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 462.00 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 15.0 hr/wk 660 10,842 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 69,286 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1397.5 kW-hr 10,326,966 526,675 $/kwh, 1,397 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 3,000.0 gpm 1,330,160 106,413 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 3,000.0 gpm 1,330,160 2,245,661 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization Caustic 305.96 $/ton 462.0 lb/hr 1,707 522,292 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 WWESP 9/7/2006 Page 57 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.e: SO 2 

## Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 7 waste gas

E mission Unit Number EU 332 Stack/Vent Number SV 151 Standardized Flow Rate 518,805 scfm @ 32o F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 7,255,257 Purchased Equipment Total (B) 22% of control device cost (A) 8,815,138

Installation - Standard Costs 67% of purchased equip cost (B) 5,906,142 Installation - Site Specific Costs 6,200,000 Installation Total 5,906,142 Total Direct Capital Cost, DC 14,721,280 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,024,628 Total Capital Investment (TCI) = DC + IC 37,793,453
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,632,323 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,491,439 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,123,761

Actual 

### Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,202.3 1,928.0 0% 1928.0

- NA Sulfur Dioxide (SO 2 ) 184.8 544.8 80% 109.0 435.9 18,638

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 WWESP 9/7/2006 Page 58 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 7,255,257 Instrumentation 10% of control device cost (A) 725,526 MN Sales Taxes 6.5% of control device cost (A) 471,592 Freight 5% of control device cost (A) 362,763 Purchased Equipment Total (B) 22% 8,815,138

Installation Foundations & supports 4% of purchased equip cost (B) 352,606 Handling & erection 50% of purchased equip cost (B) 4,407,569 Electrical 8% of purchased equip cost (B) 705,211 Piping 1% of purchased equip cost (B) 88,151 Insulation 2% of purchased equip cost (B) 176,303 Painting 2% of purchased equip cost (B) 176,303 Installation Subtotal Standard Expenses 67% 5,906,142
Total Direct Capital Cost, DC 14,721,280
Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,763,028 Construction & field expenses 20% of purchased equip cost (B) 1,763,028 Contractor fees 10% of purchased equip cost (B) 881,514 Start-up 1% of purchased equip cost (B) 88,151 Performance test 1% of purchased equip cost (B) 88,151 Model Studies 2% of purchased equip cost (B) 176,303 Contingencies 3% of purchased equip cost (B) 264,454 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,024,628
Total Capital Investment (TCI) = DC + IC 19,745,908 Retrofit multiplier 3 60% of TCI 11,847,545

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 37,793,453



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 11,707 Maintenance Materials 1.00 % of Maintenance Labor 72,553 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,418 kW-hr, 7946 hr/yr, 93% utilization 534,344 Water 0.08 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 106,413 WW Treat Neutralization 1.69 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 2,245,661 Caustic 305.96 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization 522,292 Total Annual Direct Operating Costs 3,632,323
Indirect Operating Costs Overhead 60% of total labor and material costs 134,168 Administration (2% total capital costs) 2% of total capital costs (TCI) 394,918 Property tax (1% total capital costs) 1% of total capital costs (TCI) 197,459 Insurance (1% total capital costs) 1% of total capital costs (TCI) 197,459 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,567,435 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,491,439

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,123,761

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 WWESP 9/7/2006 Page 59 of 75

## US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis Table A.6.e: 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 600,000 10 1,086.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 56.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 141,907 275.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,417.8

Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm 3000.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 462.00 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 15.0 hr/wk 660 11,707 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 72,553 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1417.8 kW-hr 10,477,342 534,344 $/kwh, 1,418 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 3,000.0 gpm 1,330,160 106,413 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 3,000.0 gpm 1,330,160 2,245,661 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization Caustic 305.96 $/ton 462.0 lb/hr 1,707 522,292 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 WWESP 9/7/2006 Page 60 of 75

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.a: SO 2 

### Control - Wet Scrubber

Operating Unit: Line 3 waste gas

Em ission Unit Number EU 223 Stack/Vent Number SV 103 Standardized Flow Rate 268,515 scfm @ 32o F Expected Utilization Rate 93% Temperature 130 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68o F Dry Std Flow Rate 257,906 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 3,453,270 Purchased Equipment Total (B) 22% of control device cost (A) 4,195,723

Installation - Standard Costs 85% of purchased equip cost (B) 3,566,365 Installation - Site Specific Costs 6,200,000 Installation Total 3,566,365 Total Direct Capital Cost, DC 7,762,088 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 629,358 Total Capital Investment (TCI) = DC + IC 19,626,314
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 570,934 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,245,499 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,816,433

Actual Emission Control Cost Calculation Emis Ma x Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 876.9 1,345.0 0% 1345.0

- NA Sulfur Dioxide (SO 2 ) 98.6 329.3 60% 131.7 197.6 14,253

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

Line3 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.a: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 3,453,270 Instrumentation 10% of control device cost (A) 345,327 MN Sales Taxes 6.5% of control device cost (A) 224,463 Freight 5% of control device cost (A) 172,663 Purchased Equipment Total (B) 22% 4,195,723

Installation Foundations & supports 12% of purchased equip cost (B) 503,487 Handling & erection 40% of purchased equip cost (B) 1,678,289 Electrical 1% of purchased equip cost (B) 41,957 Piping 30% of purchased equip cost (B) 1,258,717 Insulation 1% of purchased equip cost (B) 41,957 Painting 1% of purchased equip cost (B) 41,957 Installation Subtotal Standard Expenses 85% 3,566,365
Total Direct Capital Cost, DC 7,762,088
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 209,786 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 209,786 Start-up 1% of purchased equip cost (B) 41,957 Performance test 1% of purchased equip cost (B) 41,957 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 125,872 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 629,358
Total Capital Investment (TCI) = DC + IC 8,391,446 Retrofit multiplier 5 60% of TCI 5,034,868

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 19,626,314

OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 662 kW-hr, 7946 hr/yr, 93% utilization 249,567 Water 0.08 $/kgal, 302 gpm, 7946 hr/yr, 93% utilization 10,717 WW Treat Neutralization 1.69 $/kgal, 245 gpm, 7946 hr/yr, 93% utilization 183,186 Lime 91.40 $/ton, 95 lb/hr, 7946 hr/yr, 93% utilization 32,037 Total Annual Direct Operating Costs 570,934
Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 167,829 Property tax (1% total capital costs) 1% of total capital costs (TCI) 83,914 Insurance (1% total capital costs) 1% of total capital costs (TCI) 83,914 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,852,585 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,245,499

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,816,433

See Summary page for notes and assumptions

Line3 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.a: SO2 Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Equipment Life 20 years CRF 0.0000 Rep part cost per unit 0 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm ∆ P in H2O Efficiency Hp kW Blower, Scrubber 322,000 8.55 0.7

- 460.2 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 12,236 gpm 1 60 0.7

- 197.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 302 gpm 1 60 0.7

- 4.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 662.2

Reagent Use & Other Operating Costs Caustic Use 98.56 lb/hr SO2 2.50 lb NaOH/lb SO2 246.40 lb/hr Caustic Lime Use 98.56 lb/hr SO2 0.96 lb Lime/lb SO2 94.86 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 12,236 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 302 gpm Evaporation Loss 4 = 57.42 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 662.2 kW-hr 4,893,479 249,567 $/kwh, 662 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal 302.1 gpm 133,963 10,717 $/kgal, 302 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/kgal 244.7 gpm 108,506 183,186 $/kgal, 245 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton 94.9 lb/hr 351 32,037 $/ton, 95 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line3 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.b: SO 2 

### Control - Wet Scrubber

Operating Unit: Line 4 waste gas

Em ission Unit Number EU 259 Stack/Vent Number SV 118 Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 5,263,384 Purchased Equipment Total (B) 22% of control device cost (A) 6,395,011

Installation - Standard Costs 85% of purchased equip cost (B) 5,435,759 Installation - Site Specific Costs 6,200,000 Installation Total 5,435,759 Total Direct Capital Cost, DC 11,830,771 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252 Total Capital Investment (TCI) = DC + IC 26,664,036
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,038,186 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939

Actual Emission Control Cost Calculation Emis Ma x Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,812.0 0% 1812.0

- NA Sulfur Dioxide (SO 2 ) 146.3 447.5 60% 179.0 268.5 15,358

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

Line4 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.b: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,263,384 Instrumentation 10% of control device cost (A) 526,338 MN Sales Taxes 7% of control device cost (A) 342,120 Freight 5% of control device cost (A) 263,169 Purchased Equipment Total (B) 22% 6,395,011

Installation Foundations & supports 12% of purchased equip cost (B) 767,401 Handling & erection 40% of purchased equip cost (B) 2,558,004 Electrical 1% of purchased equip cost (B) 63,950 Piping 30% of purchased equip cost (B) 1,918,503 Insulation 1% of purchased equip cost (B) 63,950 Painting 1% of purchased equip cost (B) 63,950 Installation Subtotal Standard Expenses 85% 5,435,759
Total Direct Capital Cost, DC 11,830,771
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 319,751 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 319,751 Start-up 1% of purchased equip cost (B) 63,950 Performance test 1% of purchased equip cost (B) 63,950 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 191,850 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252
Total Capital Investment (TCI) = DC + IC 12,790,022 Retrofit multiplier 5 60% of TCI 7,674,013

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 26,664,036

OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization 503,785 Water 0.08 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization 21,634 WW Treat Neutralization 1.69 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization 369,785 Lime 91.40 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555 Total Annual Direct Operating Costs 1,038,186
Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 255,800 Property tax (1% total capital costs) 1% of total capital costs (TCI) 127,900 Insurance (1% total capital costs) 1% of total capital costs (TCI) 127,900 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,516,896 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939

See Summary page for notes and assumptions

Line4 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.b: SO2 Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Equipment Life 20 years CRF 0.0000 Rep part cost per unit 0 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm ∆ P in H2O Efficiency Hp kW Blower, Scrubber 650,000 8.55 0.7

- 928.9 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 24,700 gpm 1 60 0.7

- 398.0 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 610 gpm 1 60 0.7

- 9.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 1336.7

Reagent Use & Other Operating Costs Caustic Use 146.30 lb/hr SO2 2.50 lb NaOH/lb SO2 365.75 lb/hr Caustic Lime Use 146.30 lb/hr SO2 0.96 lb Lime/lb SO2 140.81 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 24,700 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 610 gpm Evaporation Loss 4 = 115.90 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1336.7 kW-hr 9,878,141 503,785 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal 609.9 gpm 270,423 21,634 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/kgal 494.0 gpm 219,033 369,785 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton 140.8 lb/hr 520 47,555 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line4 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.c: SO 2 

### Control - Wet Scrubber

Operating Unit: Line 5 waste gas

Em ission Unit Number EU 280 Stack/Vent Number SV 127 Standardized Flow Rate 556,174 scfm @ 32o F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 5,263,384 Purchased Equipment Total (B) 22% of control device cost (A) 6,395,011

Installation - Standard Costs 85% of purchased equip cost (B) 5,435,759 Installation - Site Specific Costs 6,200,000 Installation Total 5,435,759 Total Direct Capital Cost, DC 11,830,771 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252 Total Capital Investment (TCI) = DC + IC 26,664,036
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,038,186 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939

Actual Emission Control Cost Calculation Emis Ma x Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,353.0 1,820.0 0% 1820.0

- NA Sulfur Dioxide (SO 2 ) 146.3 447.5 60% 179.0 268.5 15,358

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

Line5 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.c: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,263,384 Instrumentation 10% of control device cost (A) 526,338 MN Sales Taxes 7% of control device cost (A) 342,120 Freight 5% of control device cost (A) 263,169 Purchased Equipment Total (B) 22% 6,395,011

Installation Foundations & supports 12% of purchased equip cost (B) 767,401 Handling & erection 40% of purchased equip cost (B) 2,558,004 Electrical 1% of purchased equip cost (B) 63,950 Piping 30% of purchased equip cost (B) 1,918,503 Insulation 1% of purchased equip cost (B) 63,950 Painting 1% of purchased equip cost (B) 63,950 Installation Subtotal Standard Expenses 85% 5,435,759
Total Direct Capital Cost, DC 11,830,771
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 319,751 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 319,751 Start-up 1% of purchased equip cost (B) 63,950 Performance test 1% of purchased equip cost (B) 63,950 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 191,850 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252
Total Capital Investment (TCI) = DC + IC 12,790,022 Retrofit multiplier 5 60% of TCI 7,674,013

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 26,664,036

OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization 503,785 Water 0.08 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization 21,634 WW Treat Neutralization 1.69 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization 369,785 Lime 91.40 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555 Total Annual Direct Operating Costs 1,038,186
Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 255,800 Property tax (1% total capital costs) 1% of total capital costs (TCI) 127,900 Insurance (1% total capital costs) 1% of total capital costs (TCI) 127,900 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,516,896 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939

See Summary page for notes and assumptions

Line5 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.c: SO2 Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Equipment Life 20 years CRF 0.0000 Rep part cost per unit 0 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm ∆ P in H2O Efficiency Hp kW Blower, Scrubber 650,000 8.55 0.7

- 928.9 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 24,700 gpm 1 60 0.7

- 398.0 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 610 gpm 1 60 0.7

- 9.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 1336.7

Reagent Use & Other Operating Costs Caustic Use 146.30 lb/hr SO2 2.50 lb NaOH/lb SO2 365.75 lb/hr Caustic Lime Use 146.30 lb/hr SO2 0.96 lb Lime/lb SO2 140.81 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 24,700 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 610 gpm Evaporation Loss 4 = 115.90 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1336.7 kW-hr 9,878,141 503,785 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal 609.9 gpm 270,423 21,634 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/kgal 494.0 gpm 219,033 369,785 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton 140.8 lb/hr 520 47,555 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line5 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.d: SO 2 

### Control - Wet Scrubber

Operating Unit: Line 6 waste gas

Em ission Unit Number EU 313 Stack/Vent Number SV 144 Standardized Flow Rate 518,805 scfm @ 32o F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 5,016,580 Purchased Equipment Total (B) 22% of control device cost (A) 6,095,145

Installation - Standard Costs 85% of purchased equip cost (B) 5,180,873 Installation - Site Specific Costs 6,200,000 Installation Total 5,180,873 Total Direct Capital Cost, DC 11,276,018 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272 Total Capital Investment (TCI) = DC + IC 25,704,464
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 981,838 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025

Actual Emission Control Cost Calculation Emis Ma x Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,202.3 1,776.0 0% 1776.0

- NA Sulfur Dioxide (SO 2 ) 184.8 544.8 60% 217.9 326.9 12,093

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

Line6 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.d: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,016,580 Instrumentation 10% of control device cost (A) 501,658 MN Sales Taxes 7% of control device cost (A) 326,078 Freight 5% of control device cost (A) 250,829 Purchased Equipment Total (B) 22% 6,095,145

Installation Foundations & supports 12% of purchased equip cost (B) 731,417 Handling & erection 40% of purchased equip cost (B) 2,438,058 Electrical 1% of purchased equip cost (B) 60,951 Piping 30% of purchased equip cost (B) 1,828,543 Insulation 1% of purchased equip cost (B) 60,951 Painting 1% of purchased equip cost (B) 60,951 Installation Subtotal Standard Expenses 85% 5,180,873
Total Direct Capital Cost, DC 11,276,018
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 304,757 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 304,757 Start-up 1% of purchased equip cost (B) 60,951 Performance test 1% of purchased equip cost (B) 60,951 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 182,854 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272
Total Capital Investment (TCI) = DC + IC 12,190,290 Retrofit multiplier 5 60% of TCI 7,314,174

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 25,704,464

OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization 465,032 Water 0.08 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization 19,970 WW Treat Neutralization 1.69 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization 341,340 Lime 91.40 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization 60,069 Total Annual Direct Operating Costs 981,838
Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 243,806 Property tax (1% total capital costs) 1% of total capital costs (TCI) 121,903 Insurance (1% total capital costs) 1% of total capital costs (TCI) 121,903 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,426,320 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025

See Summary page for notes and assumptions

Line6 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.d: SO2 Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Equipment Life 20 years CRF 0.0000 Rep part cost per unit 0 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm ∆ P in H2O Efficiency Hp kW Blower, Scrubber 600,000 8.55 0.7

- 857.4 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 22,800 gpm 1 60 0.7

- 367.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 563 gpm 1 60 0.7

- 9.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 1233.9

Reagent Use & Other Operating Costs Caustic Use 184.80 lb/hr SO2 2.50 lb NaOH/lb SO2 462.00 lb/hr Caustic Lime Use 184.80 lb/hr SO2 0.96 lb Lime/lb SO2 177.87 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 22,800 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 563 gpm Evaporation Loss 4 = 106.99 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1233.9 kW-hr 9,118,284 465,032 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal 563.0 gpm 249,621 19,970 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/kgal 456.0 gpm 202,184 341,340 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton 177.9 lb/hr 657 60,069 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line6 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.e: SO 2 

### Control - Wet Scrubber

Operating Unit: Line 7 waste gas

Em ission Unit Number EU 332 Stack/Vent Number SV 151 Standardized Flow Rate 518,805 scfm @ 32o F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 5,016,580 Purchased Equipment Total (B) 22% of control device cost (A) 6,095,145

Installation - Standard Costs 85% of purchased equip cost (B) 5,180,873 Installation - Site Specific Costs 6,200,000 Installation Total 5,180,873 Total Direct Capital Cost, DC 11,276,018 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272 Total Capital Investment (TCI) = DC + IC 25,704,464
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 981,838 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025

Actual Emission Control Cost Calculation Emis Ma x Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,202.3 1,928.0 0% 1928.0

- NA Sulfur Dioxide (SO 2 ) 184.8 544.8 60% 217.9 326.9 12,093

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

Line7 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.e: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,016,580 Instrumentation 10% of control device cost (A) 501,658 MN Sales Taxes 7% of control device cost (A) 326,078 Freight 5% of control device cost (A) 250,829 Purchased Equipment Total (B) 22% 6,095,145

Installation Foundations & supports 12% of purchased equip cost (B) 731,417 Handling & erection 40% of purchased equip cost (B) 2,438,058 Electrical 1% of purchased equip cost (B) 60,951 Piping 30% of purchased equip cost (B) 1,828,543 Insulation 1% of purchased equip cost (B) 60,951 Painting 1% of purchased equip cost (B) 60,951 Installation Subtotal Standard Expenses 85% 5,180,873
Total Direct Capital Cost, DC 11,276,018
Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 304,757 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 304,757 Start-up 1% of purchased equip cost (B) 60,951 Performance test 1% of purchased equip cost (B) 60,951 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 182,854 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272
Total Capital Investment (TCI) = DC + IC 12,190,290 Retrofit multiplier 5 60% of TCI 7,314,174

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 25,704,464

OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization 465,032 Water 0.08 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization 19,970 WW Treat Neutralization 1.69 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization 341,340 Lime 91.40 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization 60,069 Total Annual Direct Operating Costs 981,838
Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 243,806 Property tax (1% total capital costs) 1% of total capital costs (TCI) 121,903 Insurance (1% total capital costs) 1% of total capital costs (TCI) 121,903 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,426,320 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025

See Summary page for notes and assumptions

Line7 Wet Scrubber

### US Steel - Minntac BART Report - Attachment A: Emission Control Cost Analysis Table A.7.e: SO2 Control - Wet Scrubber

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catalyst: Equipment Life 20 years CRF 0.0000 Rep part cost per unit 0 $/ft 3 Amount Required 0 ft 3 Packing Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0
Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use Flow acfm ∆ P in H2O Efficiency Hp kW Blower, Scrubber 600,000 8.55 0.7

- 857.4 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 22,800 gpm 1 60 0.7

- 367.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 563 gpm 1 60 0.7

- 9.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 1233.9

Reagent Use & Other Operating Costs Caustic Use 184.80 lb/hr SO2 2.50 lb NaOH/lb SO2 462.00 lb/hr Caustic Lime Use 184.80 lb/hr SO2 0.96 lb Lime/lb SO2 177.87 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 22,800 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 563 gpm Evaporation Loss 4 = 106.99 gpm

Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1233.9 kW-hr 9,118,284 465,032 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal 563.0 gpm 249,621 19,970 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/kgal 456.0 gpm 202,184 341,340 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton 177.9 lb/hr 657 60,069 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line7 Wet ScrubberUS Steel - MinntacBART Report - Attachment A: Emission Control Cost AnalysisTable A.8: Utility Plant Heater Boilers Cost SummaryNOxControl Cost SummaryControl TechnologyControl Eff%ControlledEmissionsT/yEmissionReductionT/yrInstalledCapital Cost $AnnualizedOperatingCost $/yrPollutionControlCost $/tonLow Temperature Oxidation (LoTOx)Utility Plant Heater Boiler #190%1.4312.85$1,681,680$304,052$23,668Utility Plant Heater Boiler #290%1.3812.42$1,681,680$304,052$24,489Utility Plant Heater Boiler #490%1.4813.36$1,914,641$343,518$25,720Utility Plant Heater Boiler #590% 1.38 12.40 $1,914,641 $343,518$27,713Selective Catalytic Reduction (SCR)Utility Plant Heater Boiler #180%2.9211.70$4,488,567$592,165$50,632Utility Plant Heater Boiler #280%2.8311.31$4,488,567$592,165$52,345Utility Plant Heater Boiler #480%3.0712.29$5,234,392$688,384$56,028Utility Plant Heater Boiler #580% 2.86 11.43 $5,234,392 $688,384$60,211Low NOXBurner / Flue Gas RecirculationUtility Plant Heater Boiler #175%3.5710.71$1,384,220$166,560$15,558Utility Plant Heater Boiler #275%3.4510.35$1,384,220$166,560$16,098Utility Plant Heater Boiler #475%3.7111.13$1,745,018$209,678$18,839Utility Plant Heater Boiler #575% 3.44 10.33 $1,745,018 $209,678$20,299Regenerative Selective Catalytic Reduction (R-SCR)Utility Plant Heater Boiler #170%4.4710.43$1,690,961$238,636$22,879Utility Plant Heater Boiler #270%4.3310.10$1,690,961$238,636$23,638Utility Plant Heater Boiler #470%4.7311.05$2,156,692$316,281$28,633Utility Plant Heater Boiler #570% 4.41 10.30 $2,156,692 $316,281$30,710Low NOXBurner / Overfire Air (OFA)Utility Plant Heater Boiler #167%4.719.56$1,131,149$136,590$14,282Utility Plant Heater Boiler #267%4.559.24$1,131,149$136,590$14,778Utility Plant Heater Boiler #467%4.909.94$1,425,985$171,954$17,294Utility Plant Heater Boiler #567% 4.55 9.23 $1,425,985 $171,954$18,634Low NOXBurnerUtility Plant Heater Boiler #150%7.147.14$344,269$47,480$6,653Utility Plant Heater Boiler #250%6.906.90$344,269$47,480$6,883Utility Plant Heater Boiler #450%7.427.42$434,003$59,540$8,024Utility Plant Heater Boiler #550% 6.89 6.89 $434,003 $59,540 $8,646Selective Non-Catalytic Reduction (SNCR)Utility Plant Heater Boiler #150%7.147.14$1,084,406$300,018$42,037Utility Plant Heater Boiler #250%6.906.90$1,084,406$300,018$43,495Utility Plant Heater Boiler #450%7.427.42$1,277,232$354,613$47,792Utility Plant Heater Boiler #550% 6.89 6.89 $1,277,232 $354,613$51,494P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BARTCost SummaryCost Summary1 of 106US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.9: Summary of Utility, Chemical and Supply Costs
Operating Unit: Utility Plant Heater Boiler #1 S tudy Year 2006 Emission Unit Number EU 001 Stack/Vent Number SV 001 Operating Unit: Utility Plant Heater Boiler #2 E mission Unit Number EU 002 Stack/Vent Number SV 002 Operating Unit: Utility Plant Heater Boiler #3 E mission Unit Number EU 003 Stack/Vent Number SV 003 Operating Unit: Utility Plant Heater Boiler #4 E mission Unit Number EU 004 Stack/Vent Number SV 004 Operating Unit: Utility Plant Heater Boiler #5 E mission Unit Number EU 005 Stack/Vent Number SV 005 Reference Item Unit Cost Units Cost Year Data Source Notes Operating Labor 61.00 $/hr Per Chrissy Bartovich e-mail Maintenance Labor 61.00 $/hr Per Chrissy Bartovich e-mail

Electricity 0.051 $/kwh 2006 Expected annual average industrial price of electricity in the West North Central Division for 2007 - DOE http://tonto.eia.doe.gov/steo_query/app/elecpage.htm

Natural Gas 9.2575 $/mscf 2005 Energy Information Administration. Average US Industrial Natural Gas Prices. July '05 to June '06. http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3m.htm Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail
Cooling Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail Ch 1 Carbon Adsrobers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 3% inflation
Compressed Air 0.32 $/kscf 0.25 1998 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation

Wastewater Disposal Bio-Treat 4.28 $/kgal 3.80 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation

Hazardous Waste Disposal 281.38 $/ton 250.00 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5 Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3% inflation
Waste Transport 0.56 $/ton-mi 0.50 2002 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation

Chemicals & Supplies

Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery
Oxygen 40.00 $/ton BOC

Ammonia (29% aqua.) 0.12 $/lb 0.101 2000 EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2, page 2-50 Annual costs for a retrofit SCR system example problem. '00 costs adjusted for 3% inflation.

Catayst & Replacement Parts SCR Catalyst 141.00 $/ft 3 Cormetech, Inc.

Other Sales Tax 6.5 % Interest Rate 7.0% %
Please note, for units of measure, k = 1,000 units, MM = 1,000,000 units e.g. kgal = 1,000 gal
Operating Information
Annual Op. Hrs
Utility Plant Heater Boiler #1 3,156 Hours Average actual operating hours based on 2004 and 2005 emission inventories Utility Plant Heater Boiler #2 3,156 Hours Utility Plant Heater Boiler #3 3,156 Hours Utility Plant Heater Boiler #4 3,156 Hours Utility Plant Heater Boiler #5 3,156 Hours

Utilization Rate
Utility Plant Heater Boiler #1 28% Average actual utilization rate based on 2004 and 2005 emission inventories Utility Plant Heater Boiler #2 28% Utility Plant Heater Boiler #3 28% Utility Plant Heater Boiler #4 28% Utility Plant Heater Boiler #5 28%
Equipment Life 20 yrs Engineering Estimate
Desgin Capacity Utility Plant Heater Boiler #1 104 MMBtu/hr Utility Plant Heater Boiler #2 104 MMBtu/hr Utility Plant Heater Boiler #3 125 MMBtu/hr Utility Plant Heater Boiler #4 153 MMBtu/hr Utility Plant Heater Boiler #5 153 MMBtu/hr

Standardized Flow Rate Utility Plant Heater Boiler #1 11,005 scfm @ 32o F Utility Plant Heater Boiler #2 11,005 scfm @ 32o F Utility Plant Heater Boiler #3 13,465 scfm @ 32o F Utility Plant Heater Boiler #4 16,508 scfm @ 32o F Utility Plant Heater Boiler #5 16,508 scfm @ 32o F
Temperature Utility Plant Heater Boiler #1 380 Deg F Utility Plant Heater Boiler #2 380 Deg F Utility Plant Heater Boiler #3 380 Deg F Utility Plant Heater Boiler #4 380 Deg F Utility Plant Heater Boiler #5 380 Deg F

Moisture Content Utility Plant Heater Boiler #1 13.3% Utility Plant Heater Boiler #2 13.3% Utility Plant Heater Boiler #3 13.3% Utility Plant Heater Boiler #4 13.3% Utility Plant Heater Boiler #5 13.3%

Actual Flow Rate Utility Plant Heater Boiler #1 17,000 acfm Utility Plant Heater Boiler #2 17,000 acfm Utility Plant Heater Boiler #3 20,800 acfm Utility Plant Heater Boiler #4 25,500 acfm Utility Plant Heater Boiler #5 25,500 acfm

Standardized Flow Rate Utility Plant Heater Boiler #1 11,811 scfm @ 68o F Utility Plant Heater Boiler #2 11,811 scfm @ 68o F Utility Plant Heater Boiler #3 14,451 scfm @ 68o F Utility Plant Heater Boiler #4 17,716 scfm @ 68o F Utility Plant Heater Boiler #5 17,716 scfm @ 68o F
Dry Std Flow Rate Utility Plant Heater Boiler #1 10,240 dscfm @ 68o F Utility Plant Heater Boiler #2 10,240 dscfm @ 68o F Utility Plant Heater Boiler #3 12,529 dscfm @ 68o F Utility Plant Heater Boiler #4 15,360 dscfm @ 68o F Utility Plant Heater Boiler #5 15,360 dscfm @ 68o F
Design Basis Baseline Emis. Baseline Emis. Max Emis. (Model) Max Emis. Pollutant T/yr lb/MMBtu lb/hr lb/mmbtu
Nitrous Oxides (NOx) Utility Plant Heater Boiler #1 14.3 0.03 29.2 0.28 Utility Plant Heater Boiler #2 13.8 0.03 29.2 0.28 Utility Plant Heater Boiler #3 1.7 0.00 34.9 0.28 Utility Plant Heater Boiler #4 14.8 0.02 42.9 0.28 Utility Plant Heater Boiler #5 13.8 0.02 42.9 0.28 Max emissions based on limited potential emissions as reported in the BART spreadsheet. Baseline emissions are based on 2005 emission inventory.

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Utility Chem$ Data Utility Chem$ Data 2 of 106

## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Utility Plant Heater Boiler #1

E mission Unit Number EU 001 Stack/Vent Number SV 001 Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 768,944 Purchased Equipment Total (B) 22% of control device cost (A) 934,267

Installation - Standard Costs 45% of purchased equip cost (B) 420,420

Total Direct Capital Cost, DC 1,354,687 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993 Total Capital Investment (TCI) = DC + IC 1,681,680
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 55,305 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747 Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.3 90% 1.4 12.8 23,668

Notes & Assumptions 1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter. Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers) 2 Handling and erection of ozone generators included in estimate from PCI Wedeco 3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project. 4 Oxygen plant site prep costs divided between all 5 lines 5 In order for LoTOx to work, a scrubber needs to be installed to capture NO X 

### that has been converted to HNO 3 

### and N 2 

### O 5 

### . This analysis does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs; however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LoTOx #1 LoTOx 3 of 106

## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 

### Purchased Equipment Costs (A) - Ozone generator (esti mate from PCI Wedeco) 768,944 Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 76,894 MN Sales Taxes 6.5% of control device cost (A) 49,981 Freight 5% of control device cost (A) 38,447 Purchased Equipment Total (B) 22% 934,267

Installation Foundations & supports 12% of purchased equip cost (B) 112,112 Handling & erection (2) 

### 0% of purchased equip cost (B) 0 Electrical 1% of purchased equip cost (B) 9,343 Piping 30% of purchased equip cost (B) 280,280 Insulation 1% of purchased equip cost (B) 9,343 Painting 1% of purchased equip cost (B) 9,343 Installation Subtotal Standard Expenses 45% 420,420

Total Direct Capital Cost, DC 1,354,687
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 93,427 Construction & field expenses 10% of purchased equip cost (B) 93,427 Contractor fees 10% of purchased equip cost (B) 93,427 Start-up 1% of purchased equip cost (B) 9,343 Performance test 1% of purchased equip cost (B) 9,343 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 28,028 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993

Total Capital Investment (TCI) = DC + IC 1,681,680

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,681,680



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization 8,534 Cooling Water 0.08 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization 502 Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 8,367 Total Annual Direct Operating Costs 55,305
Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 33,634 Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,817 Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,817 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 158,739 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747

Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)

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

Electrical Use Flow acfm ∆ P in H2O 

### Efficiency Hp kW Blower, Scrubber 17,000 No extra load on blower Flow Liquid SPGR ∆ P ft H2O 

### Efficiency Hp kW C irc Pump 126 gpm No extra load on circulation pump H2O WW Disch 

### 2 gpm No extra load on discharge pump kW-hr LoTOx Electric Use 4 kW/lb O 3 

### 189 per estimate from PCI Wedeco To tal Oxygen Plant Electric Use 12,900 kW

- cost accounted for in $/ton of O 2 

### Total 189
Reagent Use & Other Operating Costs Ozone Needed 1.62 lb O3/lb NOx 

### 47.3 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC Oxygen Needed 10% wt O2 to O3 conversion 473.4 lb/hr O2 5,311 scfh O2 Ozone generators Cooling Water 150 gal/lb O3 118 gpm per estimate from PCI Wedeco

Circulating Water Rate 126.3 gpm Water Makeup Rate 5.8 gpm WW Discharge (blowdown) 2.2 gpm
Nitrate loading (as NaNO 3 

### ) in scrubber water 49 lb/hr NaNO 3



### Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 189.4 kW-hr 167,342 8,534 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization Cooling Water 0.08 $/mgal 118.4 gpm 6,275 502 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization Oxygen 40.00 $/ton 0.2 ton/hr 209 8,367 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Utility Plant Heater Boiler #2

E mission Unit Number EU 002 Stack/Vent Number SV 002 Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 768,944 Purchased Equipment Total (B) 22% of control device cost (A) 934,267

Installation - Standard Costs 45% of purchased equip cost (B) 420,420

Total Direct Capital Cost, DC 1,354,687 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993 Total Capital Investment (TCI) = DC + IC 1,681,680
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 55,305 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747 Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 13.8 90% 1.4 12.4 24,489

Notes & Assumptions 1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter. Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers) 2 Handling and erection of ozone generators included in estimate from PCI Wedeco 3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project. 4 Oxygen plant site prep costs divided between all 5 lines 5 In order for LoTOx to work, a scrubber needs to be installed to capture NO X 

### that has been converted to HNO 3 

### and N 2 

### O 5 

### . This analysis does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs; however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LoTOx #2 LoTOx 6 of 106

## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 

### Purchased Equipment Costs (A) - Ozone generator (esti mate from PCI Wedeco) 768,944 Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 76,894 MN Sales Taxes 6.5% of control device cost (A) 49,981 Freight 5% of control device cost (A) 38,447 Purchased Equipment Total (B) 22% 934,267

Installation Foundations & supports 12% of purchased equip cost (B) 112,112 Handling & erection (2) 

### 0% of purchased equip cost (B) 0 Electrical 1% of purchased equip cost (B) 9,343 Piping 30% of purchased equip cost (B) 280,280 Insulation 1% of purchased equip cost (B) 9,343 Painting 1% of purchased equip cost (B) 9,343 Installation Subtotal Standard Expenses 45% 420,420

Installation Total Total Direct Capital Cost, DC 1,354,687
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 93,427 Construction & field expenses 10% of purchased equip cost (B) 93,427 Contractor fees 10% of purchased equip cost (B) 93,427 Start-up 1% of purchased equip cost (B) 9,343 Performance test 1% of purchased equip cost (B) 9,343 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 28,028 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993

Total Capital Investment (TCI) = DC + IC 1,681,680

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,681,680



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization 8,534 Cooling Water 0.08 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization 502 Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 8,367 Total Annual Direct Operating Costs 55,305
Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 33,634 Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,817 Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,817 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 158,739 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747

Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)

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

Electrical Use Flow acfm ∆ P in H2O 

### Efficiency Hp kW Blower, Scrubber 17,000 No extra load on blower Flow Liquid SPGR ∆ P ft H2O 

### Efficiency Hp kW C irc Pump 126 gpm No extra load on circulation pump H2O WW Disch 

### 2 gpm No extra load on discharge pump kW-hr LoTOx Electric Use 4 kW/lb O 3 

### 189 per estimate from PCI Wedeco To tal Oxygen Plant Electric Use 12,900 kW

- cost accounted for in $/ton of O 2 

### Total 189
Reagent Use & Other Operating Costs Ozone Needed 1.62 lb O3/lb NOx 

### 47.3 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC Oxygen Needed 10% wt O2 to O3 conversion 473.4 lb/hr O2 5,311 scfh O2 Ozone generators Cooling Water 150 gal/lb O3 118 gpm per estimate from PCI Wedeco

Circulating Water Rate 126.3 gpm Water Makeup Rate 5.8 gpm WW Discharge (blowdown) 2.2 gpm
Nitrate loading (as NaNO 3 

### ) in scrubber water 49 lb/hr NaNO 3



### Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 189.4 kW-hr 167,342 8,534 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization Cooling Water 0.08 $/mgal 118.4 gpm 6,275 502 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization Oxygen 40.00 $/ton 0.2 ton/hr 209 8,367 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Utility Plant Heater Boiler #4

E mission Unit Number EU 004 Stack/Vent Number SV 004 Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 875,464 Purchased Equipment Total (B) 22% of control device cost (A) 1,063,689

Installation - Standard Costs 45% of purchased equip cost (B) 478,660

Total Direct Capital Cost, DC 1,542,349 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291 Total Capital Investment (TCI) = DC + IC 1,914,641
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 63,463 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055 Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 14.8 90% 1.5 13.4 25,720

Notes & Assumptions 1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter. Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers) 2 Handling and erection of ozone generators included in estimate from PCI Wedeco 3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project. 4 Oxygen plant site prep costs divided between all 5 lines 5 In order for LoTOx to work, a scrubber needs to be installed to capture NO X 

### that has been converted to HNO 3 

### and N 2 

### O 5 

### . This analysis does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs; however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LoTOx #4 LoTOx 9 of 106

## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 

### Purchased Equipment Costs (A) - Ozone generator (esti mate from PCI Wedeco) 875,464 Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 87,546 MN Sales Taxes 6.5% of control device cost (A) 56,905 Freight 5% of control device cost (A) 43,773 Purchased Equipment Total (B) 22% 1,063,689

Installation Foundations & supports 12% of purchased equip cost (B) 127,643 Handling & erection (2) 

### 0% of purchased equip cost (B) 0 Electrical 1% of purchased equip cost (B) 10,637 Piping 30% of purchased equip cost (B) 319,107 Insulation 1% of purchased equip cost (B) 10,637 Painting 1% of purchased equip cost (B) 10,637 Installation Subtotal Standard Expenses 45% 478,660
Total Direct Capital Cost, DC 1,542,349
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 106,369 Construction & field expenses 10% of purchased equip cost (B) 106,369 Contractor fees 10% of purchased equip cost (B) 106,369 Start-up 1% of purchased equip cost (B) 10,637 Performance test 1% of purchased equip cost (B) 10,637 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 31,911 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291

Total Capital Investment (TCI) = DC + IC 1,914,641

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,914,641



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization 12,535 Cooling Water 0.08 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization 737 Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 12,289 Total Annual Direct Operating Costs 63,463
Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 38,293 Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,146 Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,146 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 180,729 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055

Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)

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

Electrical Use Flow acfm ∆ P in H2O 

### Efficiency Hp kW Blower, Scrubber 25,500 No extra load on blower Flow Liquid SPGR ∆ P ft H2O 

### Efficiency Hp kW C irc Pump 189 gpm No extra load on circulation pump H2O WW Disch 

### 3 gpm No extra load on discharge pump kW-hr LoTOx Electric Use 4 kW/lb O 3 

### 278 per estimate from PCI Wedeco To tal Oxygen Plant Electric Use 12,900 kW

- cost accounted for in $/ton of O 2 

### Total 278
Reagent Use & Other Operating Costs Ozone Needed 1.62 lb O3/lb NOx 

### 69.5 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC Oxygen Needed 10% wt O2 to O3 conversion 695.3 lb/hr O2 7,801 scfh O2 Ozone generators Cooling Water 150 gal/lb O3 174 gpm per estimate from PCI Wedeco

Circulating Water Rate 189.4 gpm Water Makeup Rate 8.7 gpm WW Discharge (blowdown) 3.2 gpm
Nitrate loading (as NaNO 3 

### ) in scrubber water 71 lb/hr NaNO 3



### Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 278.1 kW-hr 245,784 12,535 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization Cooling Water 0.08 $/mgal 173.8 gpm 9,217 737 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization Oxygen 40.00 $/ton 0.3 ton/hr 307 12,289 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Utility Plant Heater Boiler #5

E mission Unit Number EU 005 Stack/Vent Number SV 005 Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 875,464 Purchased Equipment Total (B) 22% of control device cost (A) 1,063,689

Installation - Standard Costs 45% of purchased equip cost (B) 478,660

Total Direct Capital Cost, DC 1,542,349 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291 Total Capital Investment (TCI) = DC + IC 1,914,641
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 63,463 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055 Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 13.8 90% 1.4 12.4 27,713

Notes & Assumptions 1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter. Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers) 2 Handling and erection of ozone generators included in estimate from PCI Wedeco 3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project. 4 Oxygen plant site prep costs divided between all 5 lines 5 In order for LoTOx to work, a scrubber needs to be installed to capture NO X 

### that has been converted to HNO 3 

### and N 2 

### O 5 

### . This analysis does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs; however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LoTOx #5 LoTOx 12 of 106

## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 

### Purchased Equipment Costs (A) - Ozone generator (esti mate from PCI Wedeco) 875,464 Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 87,546 MN Sales Taxes 6.5% of control device cost (A) 56,905 Freight 5% of control device cost (A) 43,773 Purchased Equipment Total (B) 22% 1,063,689

Installation Foundations & supports 12% of purchased equip cost (B) 127,643 Handling & erection (2) 

### 0% of purchased equip cost (B) 0 Electrical 1% of purchased equip cost (B) 10,637 Piping 30% of purchased equip cost (B) 319,107 Insulation 1% of purchased equip cost (B) 10,637 Painting 1% of purchased equip cost (B) 10,637 Installation Subtotal Standard Expenses 45% 478,660
Total Direct Capital Cost, DC 1,542,349
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 106,369 Construction & field expenses 10% of purchased equip cost (B) 106,369 Contractor fees 10% of purchased equip cost (B) 106,369 Start-up 1% of purchased equip cost (B) 10,637 Performance test 1% of purchased equip cost (B) 10,637 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 31,911 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291

Total Capital Investment (TCI) = DC + IC 1,914,641

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,914,641



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization 12,535 Cooling Water 0.08 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization 737 Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 12,289 Total Annual Direct Operating Costs 63,463
Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 38,293 Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,146 Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,146 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 180,729 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055

Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)

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

Electrical Use Flow acfm ∆ P in H2O 

### Efficiency Hp kW Blower, Scrubber 25,500 No extra load on blower Flow Liquid SPGR ∆ P ft H2O 

### Efficiency Hp kW C irc Pump 189 gpm No extra load on circulation pump H2O WW Disch 

### 3 gpm No extra load on discharge pump kW-hr LoTOx Electric Use 4 kW/lb O 3 

### 278 per estimate from PCI Wedeco To tal Oxygen Plant Electric Use 12,900 kW

- cost accounted for in $/ton of O 2 

### Total 278
Reagent Use & Other Operating Costs Ozone Needed 1.62 lb O3/lb NOx 

### 69.5 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC Oxygen Needed 10% wt O2 to O3 conversion 695.3 lb/hr O2 7,801 scfh O2 Ozone generators Cooling Water 150 gal/lb O3 174 gpm per estimate from PCI Wedeco

Circulating Water Rate 189.4 gpm Water Makeup Rate 8.7 gpm WW Discharge (blowdown) 3.2 gpm
Nitrate loading (as NaNO 3 

### ) in scrubber water 71 lb/hr NaNO 3



### Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 278.1 kW-hr 245,784 12,535 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization Cooling Water 0.08 $/mgal 173.8 gpm 9,217 737 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization Oxygen 40.00 $/ton 0.3 ton/hr 307 12,289 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Operating Unit: Utility Plant Heater Boiler #1

E mission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs 2000 2,173,722 Purchased Equipment (A) 2005 2,585,117 Purchased Equipment Total (B) SCR + Reheat 2,907,528

Total Capital Investment (TCI) = DC + IC SCR + Reheat 4,488,567

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 124,972 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 467,193 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 592,165



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.6 80% 2.92 11.7 50,632

Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43 4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35 5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24 6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31 7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53 8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48 9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 2,585,117 Instrumentation 0% of control device cost (A) NA ND Sales Taxes 0.0% of control device cost (A) NA Freight 0% of control device cost (A) NA Purchased Equipment Total (A) 0% 2,585,117

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 31% Replacement Power, two weeks 796,012
Total Indirect Installation Costs (B) 31% of purchased equip cost (A) 796,012

Project Contingeny (C) 15% of (A + B) 507,169

Total Plant Cost (D) A + B + C 3,888,299
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 77,766

Inventory Capital Reagent Vol * $/gal 3,420

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 3,969,484

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 59,542 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization 3,565 Cat. Replacement 346.28 Catalyst Replacement 2,705 Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739
Total Annual Direct Operating Costs 76,551
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 374,691 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 374,691

Total Annual Cost (Annualized Capital Cost + Operating Cost) 451,242

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Equipment Life 24,000 hours FCW 0.0975 Rep part cost per unit 141 $/ft 3 

### # of Layers 10 Re placement Factor 8 Layers replaced per year = 3.3 Amount Required 197 ft 3 

### Catalyst Cost 27,753 Y catalyst life factor 8 Years Annualized Cost 2,705

SCR Capital Cost per EPRI Method 2,173,722 Duty 104 MMBtu/hr Catalyst Area 

### 50 f t 2 

### 308 f (h SCR) Q flue gas 48,166 acfm Rx Area 58 1,273 f (h NH 3 

### ) NO x Cont Eff 80% (as faction) Rx Height 7.6 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 11 layers 362,172 f (vol catalyst) Temperature 380 Deg F h SCR 81 ft f (h SCR) Catalyst Volume 1,509 ft 3 New/Retrofit 

### R N or R

E lectrical Use Duty 104 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 79.1 NOx in 0.28 lb/MMBtu n catalyst layers 11 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 79.1

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

### Density

29 lb/hr Neat 13.5 gal/hr 29% solution Volume 14 day inventory 4,523 gal $3,420 Inventory Cost 101 lb/hr

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 59,542 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 79.1 kW-hr 69,892 3,565 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization Cat. Replacement 346 $/ft3 2,705 Catalyst Replacement Ammonia (29% aqua.) 0.12059928 $/lb 101 lb/hr 89,050 10,739 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Utility Plant Heater Boiler #1

E mission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 265,359 Purchased Equipment Total (B) 22% of control device cost (A) 322,412

Installation - Standard Costs 30% of purchased equip cost (B) 96,724 Installation - Site Specific Costs NA Installation Total 96,724 Total Direct Capital Cost, DC 419,135 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948 Total Capital Investment (TCI) = DC + IC 519,083
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 48,421 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502 Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923

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

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 265,359 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 26,536 ND Sales Taxes 6.5% of control device cost (A) 17,248 Freight 5% of control device cost (A) 13,268 Purchased Equipment Total (B) 22% 322,412

Installation Foundations & supports 8% of purchased equip cost (B) 25,793 Handling & erection 14% of purchased equip cost (B) 45,138 Electrical 4% of purchased equip cost (B) 12,896 Piping 2% of purchased equip cost (B) 6,448 Insulation 1% of purchased equip cost (B) 3,224 Painting 1% of purchased equip cost (B) 3,224 Installation Subtotal Standard Expenses 30% 96,724

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 96,724 Total Direct Capital Cost, DC 419,135
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 32,241 Construction & field expenses 5% of purchased equip cost (B) 16,121 Contractor fees 10% of purchased equip cost (B) 32,241 Start-up 2% of purchased equip cost (B) 6,448 Performance test 1% of purchased equip cost (B) 3,224 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 9,672 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948
Total Capital Investment (TCI) = DC + IC 519,083
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization 2,839 Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681
Total Annual Direct Operating Costs 48,421
Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 10,382 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,191 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,191 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 48,998 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502

Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923

See Summary page for notes and assumptions

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors P rimary 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 3 9 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 B lower, Thermal 17,000 19 0.6 63.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 17,000 23 0.6 76.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 63.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 63.0 kW-hr 55,659 2,839 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization

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

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 T wi 380 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 429 Deg F - Temperature of waste gas out of heat recovery

T fo 401 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 11,811 scfm - Flow of waste gas

Q af 16 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 11,826 scfm Flue Gas Cost in 1989 $'s $222,560 Current Cost Using CHE Plant Cost Index $265,359 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

NOx Due to Duct Burner 939 scf/hr Flow of natural gas required 1.0 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners 0.345 tpy Additional NOx from duct burners

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Operating Unit: Utility Plant Heater Boiler #2

E mission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs 2000 2,173,722 Purchased Equipment (A) 2005 2,585,117 Purchased Equipment Total (B) SCR + Reheat 2,907,528

Total Capital Investment (TCI) = DC + IC SCR + Reheat 4,488,567

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 124,972 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 467,193 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 592,165



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.1 80% 2.83 11.3 52,345

Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43 4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35 5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24 6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31 7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53 8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48 9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 2,585,117 Instrumentation 0% of control device cost (A) NA ND Sales Taxes 0.0% of control device cost (A) NA Freight 0% of control device cost (A) NA Purchased Equipment Total (A) 0% 2,585,117

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 31% Replacement Power, two weeks 796,012
Total Indirect Installation Costs (B) 31% of purchased equip cost (A) 796,012

Project Contingeny (C) 15% of (A + B) 507,169

Total Plant Cost (D) A + B + C 3,888,299
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 77,766

Inventory Capital Reagent Vol * $/gal 3,420

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 3,969,484

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 59,542 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization 3,565 Cat. Replacement 346.28 Catalyst Replacement 2,705 Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739
Total Annual Direct Operating Costs 76,551
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 374,691 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 374,691

Total Annual Cost (Annualized Capital Cost + Operating Cost) 451,242

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Equipment Life 24,000 hours FCW 0.0975 Rep part cost per unit 141 $/ft 3 

### # of Layers 10 Re placement Factor 8 Layers replaced per year = 3.3 Amount Required 197 ft 3 

### Catalyst Cost 27,753 Y catalyst life factor 8 Years Annualized Cost 2,705

SCR Capital Cost per EPRI Method 2,173,722 Duty 104 MMBtu/hr Catalyst Area 

### 50 f t 2 

### 308 f (h SCR) Q flue gas 48,166 acfm Rx Area 58 1,273 f (h NH 3 

### ) NO x Cont Eff 80% (as faction) Rx Height 7.6 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 11 layers 362,172 f (vol catalyst) Temperature 380 Deg F h SCR 81 ft f (h SCR) Catalyst Volume 1,509 ft 3 New/Retrofit 

### R N or R

E lectrical Use Duty 104 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 79.1 NOx in 0.28 lb/MMBtu n catalyst layers 11 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 79.1

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

### Density

29 lb/hr Neat 13.5 gal/hr 29% solution Volume 14 day inventory 4,523 gal $3,420 Inventory Cost 101 lb/hr

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 59,542 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 79.1 kW-hr 69,892 3,565 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization Cat. Replacement 346 $/ft3 2,705 Catalyst Replacement Ammonia (29% aqua.) 0.12059928 $/lb 101 lb/hr 89,050 10,739 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Utility Plant Heater Boiler #2

E mission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 265,359 Purchased Equipment Total (B) 22% of control device cost (A) 322,412

Installation - Standard Costs 30% of purchased equip cost (B) 96,724 Installation - Site Specific Costs NA Installation Total 96,724 Total Direct Capital Cost, DC 419,135 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948 Total Capital Investment (TCI) = DC + IC 519,083
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 48,421 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502 Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923

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

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 265,359 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 26,536 ND Sales Taxes 6.5% of control device cost (A) 17,248 Freight 5% of control device cost (A) 13,268 Purchased Equipment Total (B) 22% 322,412

Installation Foundations & supports 8% of purchased equip cost (B) 25,793 Handling & erection 14% of purchased equip cost (B) 45,138 Electrical 4% of purchased equip cost (B) 12,896 Piping 2% of purchased equip cost (B) 6,448 Insulation 1% of purchased equip cost (B) 3,224 Painting 1% of purchased equip cost (B) 3,224 Installation Subtotal Standard Expenses 30% 96,724

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 96,724 Total Direct Capital Cost, DC 419,135
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 32,241 Construction & field expenses 5% of purchased equip cost (B) 16,121 Contractor fees 10% of purchased equip cost (B) 32,241 Start-up 2% of purchased equip cost (B) 6,448 Performance test 1% of purchased equip cost (B) 3,224 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 9,672 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948
Total Capital Investment (TCI) = DC + IC 519,083
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization 2,839 Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681
Total Annual Direct Operating Costs 48,421
Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 10,382 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,191 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,191 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 48,998 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502

Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923

See Summary page for notes and assumptions

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors P rimary 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 3 9 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 B lower, Thermal 17,000 19 0.6 63.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 17,000 23 0.6 76.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 63.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 63.0 kW-hr 55,659 2,839 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization

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

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 T wi 380 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 429 Deg F - Temperature of waste gas out of heat recovery

T fo 401 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 11,811 scfm - Flow of waste gas

Q af 16 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 11,826 scfm Flue Gas Cost in 1989 $'s $222,560 Current Cost Using CHE Plant Cost Index $265,359 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

NOx Due to Duct Burner 939 scf/hr Flow of natural gas required 1.0 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners 0.345 tpy Additional NOx from duct burners

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Operating Unit: Utility Plant Heater Boiler #4

E mission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs 2000 2,667,517 Purchased Equipment (A) 2005 3,172,367 Purchased Equipment Total (B) SCR + Reheat 3,529,175

Total Capital Investment (TCI) = DC + IC SCR + Reheat 5,234,392

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 148,575 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 539,809 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 688,384



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 15.4 80% 3.1 12.3 56,028

Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43 4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35 5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24 6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31 7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53 8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48 9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 3,172,367 Instrumentation 0% of control device cost (A) NA ND Sales Taxes 0.0% of control device cost (A) NA Freight 0% of control device cost (A) NA Purchased Equipment Total (A) 0% 3,172,367

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 25% Replacement Power, two weeks 796,012
Total Indirect Installation Costs (B) 25% of purchased equip cost (A) 796,012

Project Contingeny (C) 15% of (A + B) 595,257

Total Plant Cost (D) A + B + C 4,563,637
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 91,273

Inventory Capital Reagent Vol * $/gal 5,023

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 4,659,932

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 69,899 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization 5,244 Cat. Replacement 346.28 Catalyst Replacement 3,979 Ammonia (29% aqua.) 0.12 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization 15,773
Total Annual Direct Operating Costs 94,895
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 439,865 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 439,865

Total Annual Cost (Annualized Capital Cost + Operating Cost) 534,760

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Equipment Life 24,000 hours FCW 0.0975 Rep part cost per unit 141 $/ft 3 

### # of Layers 10 Re placement Factor 8 Layers replaced per year = 3.3 Amount Required 290 ft 3 

### Catalyst Cost 40,823 Y catalyst life factor 8 Years Annualized Cost 3,979

SCR Capital Cost per EPRI Method 2,667,517 Duty 153 MMBtu/hr Catalyst Area 

### 74 f t 2 

### 308 f (h SCR) Q flue gas 70,860 acfm Rx Area 85 850 f (h NH 3 

### ) NO x Cont Eff 80% (as faction) Rx Height 9.2 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 11 layers 532,728 f (vol catalyst) Temperature 380 Deg F h SCR 81 ft f (h SCR) Catalyst Volume 2,220 ft 3 New/Retrofit 

### R N or R

E lectrical Use Duty 153 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 116.4 NOx in 0.28 lb/MMBtu n catalyst layers 11 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 116.4

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

### Density

43 lb/hr Neat 19.8 gal/hr 29% solution Volume 14 day inventory 6,643 gal $5,023 Inventory Cost 148 lb/hr

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 69,899 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 116.4 kW-hr 102,817 5,244 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization Cat. Replacement 346 $/ft3 3,979 Catalyst Replacement Ammonia (29% aqua.) 0.12059928 $/lb 148 lb/hr 130,792 15,773 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Utility Plant Heater Boiler #4

E mission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 293,668 Purchased Equipment Total (B) 22% of control device cost (A) 356,807

Installation - Standard Costs 30% of purchased equip cost (B) 107,042 Installation - Site Specific Costs NA Installation Total 107,042 Total Direct Capital Cost, DC 463,849 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610 Total Capital Investment (TCI) = DC + IC 574,460
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 53,680 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944 Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625

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

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 293,668 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 29,367 ND Sales Taxes 6.5% of control device cost (A) 19,088 Freight 5% of control device cost (A) 14,683 Purchased Equipment Total (B) 22% 356,807

Installation Foundations & supports 8% of purchased equip cost (B) 28,545 Handling & erection 14% of purchased equip cost (B) 49,953 Electrical 4% of purchased equip cost (B) 14,272 Piping 2% of purchased equip cost (B) 7,136 Insulation 1% of purchased equip cost (B) 3,568 Painting 1% of purchased equip cost (B) 3,568 Installation Subtotal Standard Expenses 30% 107,042

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 107,042 Total Direct Capital Cost, DC 463,849
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 35,681 Construction & field expenses 5% of purchased equip cost (B) 17,840 Contractor fees 10% of purchased equip cost (B) 35,681 Start-up 2% of purchased equip cost (B) 7,136 Performance test 1% of purchased equip cost (B) 3,568 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 10,704 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610
Total Capital Investment (TCI) = DC + IC 574,460
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 574,460



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization 4,258 Natural Gas 9.26 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization 11,521
Total Annual Direct Operating Costs 53,680
Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 11,489 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,745 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,745 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 54,225 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944

Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625

See Summary page for notes and assumptions

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors P rimary 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 3 9 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 B lower, Thermal 25,500 19 0.6 94.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 25,500 23 0.6 114.4 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 94.5

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 94.5 kW-hr 83,488 4,258 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization

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

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 T wi 380 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 429 Deg F - Temperature of waste gas out of heat recovery

T fo 401 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 17,716 scfm - Flow of waste gas

Q af 23 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 17,739 scfm Flue Gas Cost in 1989 $'s $246,303 Current Cost Using CHE Plant Cost Index $293,668 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

NOx Due to Duct Burner 1,408 scf/hr Flow of natural gas required 1.5 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners 0.518 tpy Additional NOx from duct burners

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Operating Unit: Utility Plant Heater Boiler #5

E mission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs 2000 2,667,517 Purchased Equipment (A) 2005 3,172,367 Purchased Equipment Total (B) SCR + Reheat 3,529,175

Total Capital Investment (TCI) = DC + IC SCR + Reheat 5,234,392

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 148,575 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 539,809 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 688,384



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 14.3 80% 2.9 11.4 60,211

Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43 4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35 5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24 6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31 7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53 8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48 9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 3,172,367 Instrumentation 0% of control device cost (A) NA ND Sales Taxes 0.0% of control device cost (A) NA Freight 0% of control device cost (A) NA Purchased Equipment Total (A) 0% 3,172,367

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 25% Replacement Power, two weeks 796,012
Total Indirect Installation Costs (B) 25% of purchased equip cost (A) 796,012

Project Contingeny (C) 15% of (A + B) 595,257

Total Plant Cost (D) A + B + C 4,563,637
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 91,273

Inventory Capital Reagent Vol * $/gal 5,023

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 4,659,932

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 69,899 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization 5,244 Cat. Replacement 346.28 Catalyst Replacement 3,979 Ammonia (29% aqua.) 0.12 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization 15,773
Total Annual Direct Operating Costs 94,895
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 439,865 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 439,865

Total Annual Cost (Annualized Capital Cost + Operating Cost) 534,760

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Capital Recovery Factors P rimary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944
Replacement Catayst Equipment Life 24,000 hours FCW 0.0975 Rep part cost per unit 141 $/ft 3 

### # of Layers 10 Re placement Factor 8 Layers replaced per year = 3.3 Amount Required 290 ft 3 

### Catalyst Cost 40,823 Y catalyst life factor 8 Years Annualized Cost 3,979

SCR Capital Cost per EPRI Method 2,667,517 Duty 153 MMBtu/hr Catalyst Area 

### 74 f t 2 

### 308 f (h SCR) Q flue gas 70,860 acfm Rx Area 85 850 f (h NH 3 

### ) NO x Cont Eff 80% (as faction) Rx Height 9.2 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 11 layers 532,728 f (vol catalyst) Temperature 380 Deg F h SCR 81 ft f (h SCR) Catalyst Volume 2,220 ft 3 New/Retrofit 

### R N or R

E lectrical Use Duty 153 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 116.4 NOx in 0.28 lb/MMBtu n catalyst layers 11 layers Press drop catalyst 

### 1 i n H 2 

### O per layer Press drop duct 

### 3 in H 2 

### O Total 116.4

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

### Density

43 lb/hr Neat 19.8 gal/hr 29% solution Volume 14 day inventory 6,643 gal $5,023 Inventory Cost 148 lb/hr

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 69,899 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 116.4 kW-hr 102,817 5,244 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization Cat. Replacement 346 $/ft3 3,979 Catalyst Replacement Ammonia (29% aqua.) 0.12059928 $/lb 148 lb/hr 130,792 15,773 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Utility Plant Heater Boiler #5

E mission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 293,668 Purchased Equipment Total (B) 22% of control device cost (A) 356,807

Installation - Standard Costs 30% of purchased equip cost (B) 107,042 Installation - Site Specific Costs NA Installation Total 107,042 Total Direct Capital Cost, DC 463,849 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610 Total Capital Investment (TCI) = DC + IC 574,460
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 53,680 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944 Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625

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

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 293,668 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 29,367 ND Sales Taxes 6.5% of control device cost (A) 19,088 Freight 5% of control device cost (A) 14,683 Purchased Equipment Total (B) 22% 356,807

Installation Foundations & supports 8% of purchased equip cost (B) 28,545 Handling & erection 14% of purchased equip cost (B) 49,953 Electrical 4% of purchased equip cost (B) 14,272 Piping 2% of purchased equip cost (B) 7,136 Insulation 1% of purchased equip cost (B) 3,568 Painting 1% of purchased equip cost (B) 3,568 Installation Subtotal Standard Expenses 30% 107,042

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 107,042 Total Direct Capital Cost, DC 463,849
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 35,681 Construction & field expenses 5% of purchased equip cost (B) 17,840 Contractor fees 10% of purchased equip cost (B) 35,681 Start-up 2% of purchased equip cost (B) 7,136 Performance test 1% of purchased equip cost (B) 3,568 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 10,704 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610
Total Capital Investment (TCI) = DC + IC 574,460
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 574,460



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization 4,258 Natural Gas 9.26 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization 11,521
Total Annual Direct Operating Costs 53,680
Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 11,489 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,745 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,745 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 54,225 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944

Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625

See Summary page for notes and assumptions

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors P rimary 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 3 9 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 B lower, Thermal 25,500 19 0.6 94.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 25,500 23 0.6 114.4 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 94.5

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 94.5 kW-hr 83,488 4,258 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization

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

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## US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 T wi 380 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 F ER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 429 Deg F - Temperature of waste gas out of heat recovery

T fo 401 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 17,716 scfm - Flow of waste gas

Q af 23 scfm - Flow of auxiliary fuel

Y ear 2005 Inflation Rate 3.0% Cost Calculations 17,739 scfm Flue Gas Cost in 1989 $'s $246,303 Current Cost Using CHE Plant Cost Index $293,668 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

NOx Due to Duct Burner 1,408 scf/hr Flow of natural gas required 1.5 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners 0.518 tpy Additional NOx from duct burners

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 442,265 Purchased Equipment Total (B) 22% of control device cost (A) 537,352

Installation - Standard Costs 30% of purchased equip cost (B) 161,206 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 698,558 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579 Total Capital Investment (TCI) = DC + IC 1,384,220
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721 Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.3 75% 3.6 10.7 15,558

Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 442,265 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 44,227 MN Sales Taxes 6.5% of control device cost (A) 28,747 Freight 5% of control device cost (A) 22,113 Purchased Equipment Total (B) 22% 537,352

Installation Foundations & supports 8% of purchased equip cost (B) 42,988 Handling & erection 14% of purchased equip cost (B) 75,229 Electrical 4% of purchased equip cost (B) 21,494 Piping 2% of purchased equip cost (B) 10,747 Insulation 1% of purchased equip cost (B) 5,374 Painting 1% of purchased equip cost (B) 5,374 Installation Subtotal Standard Expenses 30% 161,206
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 698,558
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 53,735 Construction & field expenses 5% of purchased equip cost (B) 26,868 Contractor fees 10% of purchased equip cost (B) 53,735 Start-up 2% of purchased equip cost (B) 10,747 Performance test 1% of purchased equip cost (B) 5,374 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,121 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579
Total Capital Investment (TCI) = DC + IC 865,137 Retrofit Factor (3) 60% of TCI 519,082 TCI Retrofit Installed 1,384,220



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2 kW-hr, hr/yr, 0% utilization 81
Total Annual Direct Operating Costs 840
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,303 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,651 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,651 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,661 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721

Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Electrical Use Flow acfm **∆** P in H2O Efficiency Hp kW Fan motor 850 10 0.55 1.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 (assume 5% of flue gas is recirculated)

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1.8 kW-hr 1,598 81 $/kwh, 2 kW-hr, hr/yr, 0% utilization

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 442,265 Purchased Equipment Total (B) 22% of control device cost (A) 537,352

Installation - Standard Costs 30% of purchased equip cost (B) 161,206 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 698,558 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579 Total Capital Investment (TCI) = DC + IC 1,384,220
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721 Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 13.8 75% 3.4 10.3 16,098

Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 442,265 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 44,227 MN Sales Taxes 6.5% of control device cost (A) 28,747 Freight 5% of control device cost (A) 22,113 Purchased Equipment Total (B) 22% 537,352

Installation Foundations & supports 8% of purchased equip cost (B) 42,988 Handling & erection 14% of purchased equip cost (B) 75,229 Electrical 4% of purchased equip cost (B) 21,494 Piping 2% of purchased equip cost (B) 10,747 Insulation 1% of purchased equip cost (B) 5,374 Painting 1% of purchased equip cost (B) 5,374 Installation Subtotal Standard Expenses 30% 161,206
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 698,558
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 53,735 Construction & field expenses 5% of purchased equip cost (B) 26,868 Contractor fees 10% of purchased equip cost (B) 53,735 Start-up 2% of purchased equip cost (B) 10,747 Performance test 1% of purchased equip cost (B) 5,374 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,121 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579
Total Capital Investment (TCI) = DC + IC 865,137 Retrofit Factor (3) 60% of TCI 519,082 TCI Retrofit Installed 1,384,220



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2 kW-hr, hr/yr, 0% utilization 81
Total Annual Direct Operating Costs 840
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,303 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,651 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,651 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,661 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721

Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Electrical Use Flow acfm **∆** P in H2O Efficiency Hp kW Fan motor 850 10 0.55 1.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 (assume 5% of flue gas is recirculated)

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1.8 kW-hr 1,598 81 $/kwh, 2 kW-hr, hr/yr, 0% utilization

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 557,542 Purchased Equipment Total (B) 22% of control device cost (A) 677,414

Installation - Standard Costs 30% of purchased equip cost (B) 203,224 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 880,638 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998 Total Capital Investment (TCI) = DC + IC 1,745,018
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 880 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798 Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 14.8 75% 3.7 11.1 18,839

Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 557,542 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 55,754 MN Sales Taxes 6.5% of control device cost (A) 36,240 Freight 5% of control device cost (A) 27,877 Purchased Equipment Total (B) 22% 677,414

Installation Foundations & supports 8% of purchased equip cost (B) 54,193 Handling & erection 14% of purchased equip cost (B) 94,838 Electrical 4% of purchased equip cost (B) 27,097 Piping 2% of purchased equip cost (B) 13,548 Insulation 1% of purchased equip cost (B) 6,774 Painting 1% of purchased equip cost (B) 6,774 Installation Subtotal Standard Expenses 30% 203,224
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 880,638
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 67,741 Construction & field expenses 5% of purchased equip cost (B) 33,871 Contractor fees 10% of purchased equip cost (B) 67,741 Start-up 2% of purchased equip cost (B) 13,548 Performance test 1% of purchased equip cost (B) 6,774 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 20,322 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998
Total Capital Investment (TCI) = DC + IC 1,090,636 Retrofit Factor (3) 60% of TCI 654,382 TCI Retrofit Installed 1,745,018



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kW-hr, hr/yr, 0% utilization 122
Total Annual Direct Operating Costs 880
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 21,813 Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,906 Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,906 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 164,717 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798

Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Electrical Use Flow acfm **∆** P in H2O Efficiency Hp kW Fan motor 1,275 10 0.55 2.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 (assume 5% of flue gas is recirculated)

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2.7 kW-hr 2,397 122 $/kwh, 3 kW-hr, hr/yr, 0% utilization

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 557,542 Purchased Equipment Total (B) 22% of control device cost (A) 677,414

Installation - Standard Costs 30% of purchased equip cost (B) 203,224 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 880,638 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998 Total Capital Investment (TCI) = DC + IC 1,745,018
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 880 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798 Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 13.8 75% 3.4 10.3 20,299

Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 557,542 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 55,754 MN Sales Taxes 6.5% of control device cost (A) 36,240 Freight 5% of control device cost (A) 27,877 Purchased Equipment Total (B) 22% 677,414

Installation Foundations & supports 8% of purchased equip cost (B) 54,193 Handling & erection 14% of purchased equip cost (B) 94,838 Electrical 4% of purchased equip cost (B) 27,097 Piping 2% of purchased equip cost (B) 13,548 Insulation 1% of purchased equip cost (B) 6,774 Painting 1% of purchased equip cost (B) 6,774 Installation Subtotal Standard Expenses 30% 203,224
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 880,638
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 67,741 Construction & field expenses 5% of purchased equip cost (B) 33,871 Contractor fees 10% of purchased equip cost (B) 67,741 Start-up 2% of purchased equip cost (B) 13,548 Performance test 1% of purchased equip cost (B) 6,774 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 20,322 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998
Total Capital Investment (TCI) = DC + IC 1,090,636 Retrofit Factor (3) 60% of TCI 654,382 TCI Retrofit Installed 1,745,018



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kW-hr, hr/yr, 0% utilization 122
Total Annual Direct Operating Costs 880
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 21,813 Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,906 Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,906 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 164,717 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798

Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Electrical Use Flow acfm **∆** P in H2O Efficiency Hp kW Fan motor 1,275 10 0.55 2.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 (assume 5% of flue gas is recirculated)

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2.7 kW-hr 2,397 122 $/kwh, 3 kW-hr, hr/yr, 0% utilization

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

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.13.a: NO x 

# Control - Regenerative Selective Catalytic Reduction

Operating Unit: Utility Plant Heater Boiler #1

Em ission Unit Number EU 001 Stack/Vent Number SV 001 Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,201,308

Total Direct Capital Cost, DC 1,201,308

Total Capital Investment (TCI) = DC + IC 1,690,961
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 79,021 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615 Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.9 70% 4.5 10.4 22,879

Notes & Assumptions 1

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective. Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction

CAPITAL COSTS 2 

### Direct Capital Costs Purchased Equipment 1 

### (A) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,201,308 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,201,308

Indirect Installation General Facilities 5% of purchased equip cost (A) 60,065 Engineerin & Home Office 10% of purchased equip cost (A) 120,131 Process Contingency 5% of purchased equip cost (A) 60,065

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 240,262

Project Contingeny (C) 15% of (A + B) 216,235

Total Plant Cost (D) A + B + C 1,657,804
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 33,156
Inventory Capital Reagent Vol * $/gal 0
Intial Catalyst and Chemicals 0 for SCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,690,961



### OPERATING COSTS 2 

### Direct Annual Operating Costs, DC
Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 25,364 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization 2,321 Natural Gas 9.26 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization 13,933 Comp Air 0.32 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization 25 Ammonia (29% aqua.) 0.12 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization 4,173 SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204
Total Annual Direct Operating Costs 79,021
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 159,615 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615

Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636

See Summary page for notes and assumptions

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction

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

Replacement Catayst Equipment Life 3 Years CRF 0.3811 Catalyst Cost $87,139 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total cost 87,139

Annualized Cost 33,204

Electrical Use Power consumed 51 kWhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 51.5

Reagent Use & Other Operating Costs
Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 39.2 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5 Compressed air use 5 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Heat required 1,703 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators Auxiliary Fuel Use Equation 3.19

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 25,364 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh 51.5 kW-hr 45,502 2,321 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 1703.1 scfh 1,505,032 13,933 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization Comp Air 0.32 $/kscf 4.8 scfm 80 25 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization Ammonia (29% aqua.) 0.12 $/lb 39 lb/hr 34,605 4,173 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization SCR Catalyst 0.00 $/ft 3 

### 0 ft 3 

### 0 33,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization

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

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction

Duct Burner Fuel Usage Estimate

A uxiliary Fuel Use Equation 3.19 Input Numbers T wi 

### 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers 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 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 

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

T fo 

### 417 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 

### 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist 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 

### 11,811 scfm - Flow of waste gas

Q af 

### 28 scfm - Flow of auxiliary fuel

NOx Due to Duct Burner

1,703 scf/hr Flow of natural gas required 1.8 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners 0.6 tpy Additional NOx from duct burners

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

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.13.b: NO x 

# Control - Regenerative Selective Catalytic Reduction

Operating Unit: Utility Plant Heater Boiler #2

Em ission Unit Number EU 002 Stack/Vent Number SV 002 Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,201,308

Total Direct Capital Cost, DC 1,201,308

Total Capital Investment (TCI) = DC + IC 1,690,961
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 79,021 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615 Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.4 70% 4.3 10.1 23,638

Notes & Assumptions 1

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective. Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction

CAPITAL COSTS 2 

### Direct Capital Costs Purchased Equipment 1 

### (A) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,201,308 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,201,308

Indirect Installation General Facilities 5% of purchased equip cost (A) 60,065 Engineerin & Home Office 10% of purchased equip cost (A) 120,131 Process Contingency 5% of purchased equip cost (A) 60,065

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 240,262

Project Contingeny (C) 15% of (A + B) 216,235

Total Plant Cost (D) A + B + C 1,657,804
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 33,156
Inventory Capital Reagent Vol * $/gal 0
Intial Catalyst and Chemicals 0 for SCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,690,961



### OPERATING COSTS 2 

### Direct Annual Operating Costs, DC
Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 25,364 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization 2,321 Natural Gas 9.26 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization 13,933 Comp Air 0.32 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization 25 Ammonia (29% aqua.) 0.12 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization 4,173 SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204
Total Annual Direct Operating Costs 79,021
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 159,615 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615

Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636

See Summary page for notes and assumptions

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction

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

Replacement Catayst Equipment Life 3 Years CRF 0.3811 Catalyst Cost $87,139 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total cost 87,139

Annualized Cost 33,204

Electrical Use Power consumed 51 kWhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 51.5

Reagent Use & Other Operating Costs
Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 39.2 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5 Compressed air use 5 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Heat required 1,703 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators Auxiliary Fuel Use Equation 3.19

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 25,364 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh 51.5 kW-hr 45,502 2,321 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 1703.1 scfh 1,505,032 13,933 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization Comp Air 0.32 $/kscf 4.8 scfm 80 25 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization Ammonia (29% aqua.) 0.12 $/lb 39 lb/hr 34,605 4,173 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization SCR Catalyst 0.00 $/ft 3 

### 0 ft 3 

### 0 33,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization

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

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction

Duct Burner Fuel Usage Estimate

A uxiliary Fuel Use Equation 3.19 Input Numbers T wi 

### 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers 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 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 

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

T fo 

### 417 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 

### 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist 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 

### 11,811 scfm - Flow of waste gas

Q af 

### 28 scfm - Flow of auxiliary fuel

NOx Due to Duct Burner

1,703 scf/hr Flow of natural gas required 1.8 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners 0.6 tpy Additional NOx from duct burners

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

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.13.c: NO x 

# Control - Regenerative Selective Catalytic Reduction

Operating Unit: Utility Plant Heater Boiler #4

Em ission Unit Number EU 004 Stack/Vent Number SV 004 Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,532,177

Total Direct Capital Cost, DC 1,532,177

Total Capital Investment (TCI) = DC + IC 2,156,692
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 112,705 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577 Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 15.8 70% 4.7 11.0 28,633

Notes & Assumptions 1

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective. Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction

CAPITAL COSTS 2 

### Direct Capital Costs Purchased Equipment 1 

### (A) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,532,177 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,532,177

Indirect Installation General Facilities 5% of purchased equip cost (A) 76,609 Engineerin & Home Office 10% of purchased equip cost (A) 153,218 Process Contingency 5% of purchased equip cost (A) 76,609

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 306,435

Project Contingeny (C) 15% of (A + B) 275,792

Total Plant Cost (D) A + B + C 2,114,404
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 42,288
Inventory Capital Reagent Vol * $/gal 0
Intial Catalyst and Chemicals 0 for SCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 2,156,692



### OPERATING COSTS 2 

### Direct Annual Operating Costs, DC
Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 32,350 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization 3,481 Natural Gas 9.26 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization 20,899 Comp Air 0.32 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization 38 Ammonia (29% aqua.) 0.12 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization 6,130 SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 49,807
Total Annual Direct Operating Costs 112,705
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 203,577 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577

Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281

See Summary page for notes and assumptions

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction

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

Replacement Catayst Equipment Life 3 Years CRF 0.3811 Catalyst Cost $130,708 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total cost 130,708

Annualized Cost 49,807

Electrical Use Power consumed 77 kWhr 77 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 77.2

Reagent Use & Other Operating Costs
Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 57.5 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5 Compressed air use 7 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Heat required 2,555 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators Auxiliary Fuel Use Equation 3.19

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 32,350 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh 77.2 kW-hr 68,253 3,481 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 2554.7 scfh 2,257,548 20,899 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization Comp Air 0.32 $/kscf 7.1 scfm 120 38 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization Ammonia (29% aqua.) 0.12 $/lb 58 lb/hr 50,826 6,130 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization SCR Catalyst 0.00 $/ft 3 

### 0 ft 3 

### 0 49,807 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization

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

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction

Duct Burner Fuel Usage Estimate

A uxiliary Fuel Use Equation 3.19 Input Numbers T wi 

### 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers 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 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 

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

T fo 

### 417 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 

### 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist 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 

### 17,716 scfm - Flow of waste gas

Q af 

### 43 scfm - Flow of auxiliary fuel

NOx Due to Duct Burner

2,555 scf/hr Flow of natural gas required 2.7 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.2 lb/hr Additional NOx from duct burners 0.9 tpy Additional NOx from duct burners

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

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.13.d: NO x 

# Control - Regenerative Selective Catalytic Reduction

Operating Unit: Utility Plant Heater Boiler #5

Em ission Unit Number EU 005 Stack/Vent Number SV 005 Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,532,177

Total Direct Capital Cost, DC 1,532,177

Total Capital Investment (TCI) = DC + IC 2,156,692
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 112,705 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577 Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 14.7 70% 4.4 10.3 30,710

Notes & Assumptions 1

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective. Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction

CAPITAL COSTS 2 

### Direct Capital Costs Purchased Equipment 1 

### (A) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,532,177 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,532,177

Indirect Installation General Facilities 5% of purchased equip cost (A) 76,609 Engineerin & Home Office 10% of purchased equip cost (A) 153,218 Process Contingency 5% of purchased equip cost (A) 76,609

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 306,435

Project Contingeny (C) 15% of (A + B) 275,792

Total Plant Cost (D) A + B + C 2,114,404
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 42,288
Inventory Capital Reagent Vol * $/gal 0
Intial Catalyst and Chemicals 0 for SCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 2,156,692



### OPERATING COSTS 2 

### Direct Annual Operating Costs, DC
Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 32,350 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization 3,481 Natural Gas 9.26 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization 20,899 Comp Air 0.32 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization 38 Ammonia (29% aqua.) 0.12 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization 6,130 SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 49,807
Total Annual Direct Operating Costs 112,705
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 203,577 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577

Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281

See Summary page for notes and assumptions

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction

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

Replacement Catayst Equipment Life 3 Years CRF 0.3811 Catalyst Cost $130,708 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total cost 130,708

Annualized Cost 49,807

Electrical Use Power consumed 77 kWhr 77 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 77.2

Reagent Use & Other Operating Costs
Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 57.5 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5 Compressed air use 7 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Heat required 2,555 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators Auxiliary Fuel Use Equation 3.19

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 32,350 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh 77.2 kW-hr 68,253 3,481 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 2554.7 scfh 2,257,548 20,899 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization Comp Air 0.32 $/kscf 7.1 scfm 120 38 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization Ammonia (29% aqua.) 0.12 $/lb 58 lb/hr 50,826 6,130 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization SCR Catalyst 0.00 $/ft 3 

### 0 ft 3 

### 0 49,807 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization

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

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction

Duct Burner Fuel Usage Estimate

A uxiliary Fuel Use Equation 3.19 Input Numbers T wi 

### 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers 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 90% Factional Heat Recovery % Heat recovery section efficiency

T wo 

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

T fo 

### 417 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 

### 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist 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 

### 17,716 scfm - Flow of waste gas

Q af 

### 43 scfm - Flow of auxiliary fuel

NOx Due to Duct Burner

2,555 scf/hr Flow of natural gas required 2.7 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.2 lb/hr Additional NOx from duct burners 0.9 tpy Additional NOx from duct burners

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.a: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 361,408 Purchased Equipment Total (B) 22% of control device cost (A) 439,111

Installation - Standard Costs 30% of purchased equip cost (B) 131,733 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 570,844 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124 Total Capital Investment (TCI) = DC + IC 1,131,149
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,084 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506 Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.3 67% 4.7 9.6 14,282

Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application 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 3 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 361,408 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 36,141 MN Sales Taxes 6.5% of control device cost (A) 23,492 Freight 5% of control device cost (A) 18,070 Purchased Equipment Total (B) 22% 439,111

Installation Foundations & supports 8% of purchased equip cost (B) 35,129 Handling & erection 14% of purchased equip cost (B) 61,476 Electrical 4% of purchased equip cost (B) 17,564 Piping 2% of purchased equip cost (B) 8,782 Insulation 1% of purchased equip cost (B) 4,391 Painting 1% of purchased equip cost (B) 4,391 Installation Subtotal Standard Expenses 30% 131,733
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 570,844
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 43,911 Construction & field expenses 5% of purchased equip cost (B) 21,956 Contractor fees 10% of purchased equip cost (B) 43,911 Start-up 2% of purchased equip cost (B) 8,782 Performance test 1% of purchased equip cost (B) 4,391 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 13,173 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124
Total Capital Investment (TCI) = DC + IC 706,968 Retrofit Factor (3) 60% of TCI 424,181 TCI Retrofit Installed 1,131,149



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 7.2 kW-hr, 3156 hr/yr 326
Total Annual Direct Operating Costs 1,084
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 14,139 Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,070 Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,070 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 106,773 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506

Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Electrical Use Flow acfm **∆** P in H2O Efficiency Hp kW Fan motor 3,400 10 0.55 7.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 (assume 20% of flue gas used for OFA)

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 7.2 kW-hr 6,391 326 $/kwh, 7.2 kW-hr, 3156 hr/yr

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.b: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 361,408 Purchased Equipment Total (B) 22% of control device cost (A) 439,111

Installation - Standard Costs 30% of purchased equip cost (B) 131,733 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 570,844 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124 Total Capital Investment (TCI) = DC + IC 1,131,149
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,084 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506 Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 13.8 67% 4.6 9.2 14,778

Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application 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 3 CUECost Workbook Version 1.0, USEPA Document Page 2

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB OFA 1/8/2008 Page 74 of 106

## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 361,408 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 36,141 MN Sales Taxes 6.5% of control device cost (A) 23,492 Freight 5% of control device cost (A) 18,070 Purchased Equipment Total (B) 22% 439,111

Installation Foundations & supports 8% of purchased equip cost (B) 35,129 Handling & erection 14% of purchased equip cost (B) 61,476 Electrical 4% of purchased equip cost (B) 17,564 Piping 2% of purchased equip cost (B) 8,782 Insulation 1% of purchased equip cost (B) 4,391 Painting 1% of purchased equip cost (B) 4,391 Installation Subtotal Standard Expenses 30% 131,733
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 570,844
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 43,911 Construction & field expenses 5% of purchased equip cost (B) 21,956 Contractor fees 10% of purchased equip cost (B) 43,911 Start-up 2% of purchased equip cost (B) 8,782 Performance test 1% of purchased equip cost (B) 4,391 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 13,173 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124
Total Capital Investment (TCI) = DC + IC 706,968 Retrofit Factor (3) 60% of TCI 424,181 TCI Retrofit Installed 1,131,149



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 7.2 kW-hr, 3156 hr/yr 326
Total Annual Direct Operating Costs 1,084
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 14,139 Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,070 Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,070 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 106,773 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506

Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Electrical Use Flow acfm **∆** P in H2O Efficiency Hp kW Fan motor 3,400 10 0.55 7.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 (assume 20% of flue gas used for OFA)

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 7.2 kW-hr 6,391 326 $/kwh, 7.2 kW-hr, 3156 hr/yr

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.c: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 455,609 Purchased Equipment Total (B) 22% of control device cost (A) 553,565

Installation - Standard Costs 30% of purchased equip cost (B) 166,070 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 719,635 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605 Total Capital Investment (TCI) = DC + IC 1,425,985
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707 Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 14.8 67% 4.9 9.9 17,294

Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application 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 3 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 455,609 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 45,561 MN Sales Taxes 6.5% of control device cost (A) 29,615 Freight 5% of control device cost (A) 22,780 Purchased Equipment Total (B) 22% 553,565

Installation Foundations & supports 8% of purchased equip cost (B) 44,285 Handling & erection 14% of purchased equip cost (B) 77,499 Electrical 4% of purchased equip cost (B) 22,143 Piping 2% of purchased equip cost (B) 11,071 Insulation 1% of purchased equip cost (B) 5,536 Painting 1% of purchased equip cost (B) 5,536 Installation Subtotal Standard Expenses 30% 166,070
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 719,635
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 55,357 Construction & field expenses 5% of purchased equip cost (B) 27,678 Contractor fees 10% of purchased equip cost (B) 55,357 Start-up 2% of purchased equip cost (B) 11,071 Performance test 1% of purchased equip cost (B) 5,536 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,607 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605
Total Capital Investment (TCI) = DC + IC 891,240 Retrofit Factor (3) 60% of TCI 534,744 TCI Retrofit Installed 1,425,985



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 10.8 kW-hr, 3156 hr/yr 489
Total Annual Direct Operating Costs 1,247
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,825 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,912 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,912 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 134,603 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707

Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Electrical Use Flow acfm **∆** P in H2O Efficiency Hp kW Fan motor 5,100 10 0.55 10.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 (assume 20% of flue gas used for OFA)

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 10.8 kW-hr 9,587 489 $/kwh, 10.8 kW-hr, 3156 hr/yr

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.d: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 455,609 Purchased Equipment Total (B) 22% of control device cost (A) 553,565

Installation - Standard Costs 30% of purchased equip cost (B) 166,070 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 719,635 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605 Total Capital Investment (TCI) = DC + IC 1,425,985
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707 Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 13.8 67% 4.5 9.2 18,634

Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application. 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 3 CUECost Workbook Version 1.0, USEPA Document Page 2

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 455,609 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 45,561 MN Sales Taxes 6.5% of control device cost (A) 29,615 Freight 5% of control device cost (A) 22,780 Purchased Equipment Total (B) 22% 553,565

Installation Foundations & supports 8% of purchased equip cost (B) 44,285 Handling & erection 14% of purchased equip cost (B) 77,499 Electrical 4% of purchased equip cost (B) 22,143 Piping 2% of purchased equip cost (B) 11,071 Insulation 1% of purchased equip cost (B) 5,536 Painting 1% of purchased equip cost (B) 5,536 Installation Subtotal Standard Expenses 30% 166,070
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 719,635
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 55,357 Construction & field expenses 5% of purchased equip cost (B) 27,678 Contractor fees 10% of purchased equip cost (B) 55,357 Start-up 2% of purchased equip cost (B) 11,071 Performance test 1% of purchased equip cost (B) 5,536 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,607 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605
Total Capital Investment (TCI) = DC + IC 891,240 Retrofit Factor (3) 60% of TCI 534,744 TCI Retrofit Installed 1,425,985



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 10.8 kW-hr, 3156 hr/yr 489
Total Annual Direct Operating Costs 1,247
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,825 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,912 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,912 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 134,603 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707

Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Electrical Use Flow acfm **∆** P in H2O Efficiency Hp kW Fan motor 5,100 10 0.55 10.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 (assume 20% of flue gas used for OFA)

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 10.8 kW-hr 9,587 489 $/kwh, 10.8 kW-hr, 3156 hr/yr

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.a: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 175,993 Purchased Equipment Total (B) 22% of control device cost (A) 213,832

Installation - Standard Costs 30% of purchased equip cost (B) 64,150 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 277,981 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288 Total Capital Investment (TCI) = DC + IC 344,269
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722 Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.3 50% 7.1 7.1 6,653

Notes & Assumptions

1 Equipment cost based on estimate from John Zink 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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 175,993 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 17,599 MN Sales Taxes 6.5% of control device cost (A) 11,440 Freight 5% of control device cost (A) 8,800 Purchased Equipment Total (B) 22% 213,832

Installation Foundations & supports 8% of purchased equip cost (B) 17,107 Handling & erection 14% of purchased equip cost (B) 29,936 Electrical 4% of purchased equip cost (B) 8,553 Piping 2% of purchased equip cost (B) 4,277 Insulation 1% of purchased equip cost (B) 2,138 Painting 1% of purchased equip cost (B) 2,138 Installation Subtotal Standard Expenses 30% 64,150
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 277,981
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 21,383 Construction & field expenses 5% of purchased equip cost (B) 10,692 Contractor fees 10% of purchased equip cost (B) 21,383 Start-up 2% of purchased equip cost (B) 4,277 Performance test 1% of purchased equip cost (B) 2,138 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 6,415 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288
Total Capital Investment (TCI) = DC + IC 344,269



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management

Total Annual Direct Operating Costs 758
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 6,885 Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,443 Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,443 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 32,497 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722

Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.b: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 175,993 Purchased Equipment Total (B) 22% of control device cost (A) 213,832

Installation - Standard Costs 30% of purchased equip cost (B) 64,150 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 277,981 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288 Total Capital Investment (TCI) = DC + IC 344,269
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722 Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 13.8 50% 6.9 6.9 6,883

Notes & Assumptions

1 Equipment cost based on estimate from John Zink 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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 175,993 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 17,599 MN Sales Taxes 6.5% of control device cost (A) 11,440 Freight 5% of control device cost (A) 8,800 Purchased Equipment Total (B) 22% 213,832

Installation Foundations & supports 8% of purchased equip cost (B) 17,107 Handling & erection 14% of purchased equip cost (B) 29,936 Electrical 4% of purchased equip cost (B) 8,553 Piping 2% of purchased equip cost (B) 4,277 Insulation 1% of purchased equip cost (B) 2,138 Painting 1% of purchased equip cost (B) 2,138 Installation Subtotal Standard Expenses 30% 64,150
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 277,981
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 21,383 Construction & field expenses 5% of purchased equip cost (B) 10,692 Contractor fees 10% of purchased equip cost (B) 21,383 Start-up 2% of purchased equip cost (B) 4,277 Performance test 1% of purchased equip cost (B) 2,138 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 6,415 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288
Total Capital Investment (TCI) = DC + IC 344,269



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management

Total Annual Direct Operating Costs 758
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 6,885 Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,443 Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,443 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 32,497 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722

Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.c: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 221,866 Purchased Equipment Total (B) 22% of control device cost (A) 269,567

Installation - Standard Costs 30% of purchased equip cost (B) 80,870 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 350,437 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566 Total Capital Investment (TCI) = DC + IC 434,003
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782 Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 14.8 50% 7.4 7.4 8,024

Notes & Assumptions

1 Equipment cost based on estimate from John Zink 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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 221,866 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 22,187 MN Sales Taxes 6.5% of control device cost (A) 14,421 Freight 5% of control device cost (A) 11,093 Purchased Equipment Total (B) 22% 269,567

Installation Foundations & supports 8% of purchased equip cost (B) 21,565 Handling & erection 14% of purchased equip cost (B) 37,739 Electrical 4% of purchased equip cost (B) 10,783 Piping 2% of purchased equip cost (B) 5,391 Insulation 1% of purchased equip cost (B) 2,696 Painting 1% of purchased equip cost (B) 2,696 Installation Subtotal Standard Expenses 30% 80,870
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 350,437
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 26,957 Construction & field expenses 5% of purchased equip cost (B) 13,478 Contractor fees 10% of purchased equip cost (B) 26,957 Start-up 2% of purchased equip cost (B) 5,391 Performance test 1% of purchased equip cost (B) 2,696 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 8,087 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566
Total Capital Investment (TCI) = DC + IC 434,003



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management

Total Annual Direct Operating Costs 758
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 8,680 Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,340 Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,340 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 40,967 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782

Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management

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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.d: NO X 

## Control - Low NO X 

## Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 221,866 Purchased Equipment Total (B) 22% of control device cost (A) 269,567

Installation - Standard Costs 30% of purchased equip cost (B) 80,870 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 350,437 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566 Total Capital Investment (TCI) = DC + IC 434,003
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782 Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540



### Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 13.8 50% 6.9 6.9 8,646

Notes & Assumptions

1 Equipment cost based on estimate from John Zink 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

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) 221,866 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 22,187 MN Sales Taxes 6.5% of control device cost (A) 14,421 Freight 5% of control device cost (A) 11,093 Purchased Equipment Total (B) 22% 269,567

Installation Foundations & supports 8% of purchased equip cost (B) 21,565 Handling & erection 14% of purchased equip cost (B) 37,739 Electrical 4% of purchased equip cost (B) 10,783 Piping 2% of purchased equip cost (B) 5,391 Insulation 1% of purchased equip cost (B) 2,696 Painting 1% of purchased equip cost (B) 2,696 Installation Subtotal Standard Expenses 30% 80,870
Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 350,437
Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 26,957 Construction & field expenses 5% of purchased equip cost (B) 13,478 Contractor fees 10% of purchased equip cost (B) 26,957 Start-up 2% of purchased equip cost (B) 5,391 Performance test 1% of purchased equip cost (B) 2,696 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 8,087 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566
Total Capital Investment (TCI) = DC + IC 434,003



### OPERATING COSTS Direct Annual Operating Costs, DC
Operating Labor Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management

Total Annual Direct Operating Costs 758
Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 8,680 Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,340 Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,340 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 40,967 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782

Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540

See Summary page for notes and assumptions

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## US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

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

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management

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

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Operating Unit: Utility Plant Heater Boiler #1

Em ission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.18 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 769,260 Purchased Equipment Total (B) 0% of control device cost (A) 769,260

Installation - Standard Costs 15% of purchased equip cost (B) 138,467

Total Capital Investment (TCI) = DC + IC 1,084,406
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 166,949 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068 Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 14.3 50% 7.1 7.1 42,037

Notes & Assumptions 1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI 2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25 4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21

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# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260 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) 769,260

Indirect Installation [1] General Facilities 5% of purchased equip cost (A) 38,463 Engineerin & Home Office 10% of purchased equip cost (A) 76,926 Process Contingency 5% of purchased equip cost (A) 38,463

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 153,852

Project Contingeny ( C) 15% of (A + B) 138,467

Total Plant Cost D A + B + C 1,061,579
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)) 21,232
Inventory Capital Reagent Vol * $/gal 1,596
Intial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,084,406 Retrofit Installation Factor 30% 325,322
Total Capital Investment, Retrofit Installed 1,409,728



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 15.00 % of Total Capital Investment 162,661 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization 89 Water 0.08 $/mgal, 11 gph, 3156 hr/yr, 28% utilization 1 Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 4,198
Total Annual Direct Operating Costs 166,949
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 133,068 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068

Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018

See Summary page for notes and assumptions

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# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)

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

Electrical Use NOx in 0.28 lb/MMBtu kW NSR 1.37 equation 1.14 Power 2.0

Total 2.0

Reagent Use & Other Operating Costs Urea Use 11.73 lb/hr Neat equation 1.15 50% solution 71.0 lb/ft 3 

### Density 50% Solution 23.46 lb/hr 2.5 gal/hr 831 gal $1,596 Inventory Cost Water Use 11 gal/hr Inject at 10% solution Fuel Use 0.19 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2.0 kW-hr 1,753 89 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization Water 0.08 $/mgal 11.2 gph 10 1 $/mgal, 11 gph, 3156 hr/yr, 28% utilization Urea 405 $/ton 0.0117 ton/hr 10 4,198 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 SNCR #1 SNCR 97 of 106

# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Operating Unit: Utility Plant Heater Boiler #2

Em ission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.18 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 769,260 Purchased Equipment Total (B) 0% of control device cost (A) 769,260

Installation - Standard Costs 15% of purchased equip cost (B) 138,467

Total Capital Investment (TCI) = DC + IC 1,084,406
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 166,949 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068 Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 29.2 13.8 50% 6.9 6.9 43,495

Notes & Assumptions 1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI 2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25 4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SNCR #2 SNCR 98 of 106

# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260 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) 769,260

Indirect Installation [1] General Facilities 5% of purchased equip cost (A) 38,463 Engineerin & Home Office 10% of purchased equip cost (A) 76,926 Process Contingency 5% of purchased equip cost (A) 38,463

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 153,852

Project Contingeny ( C) 15% of (A + B) 138,467

Total Plant Cost D A + B + C 1,061,579
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)) 21,232
Inventory Capital Reagent Vol * $/gal 1,596
Intial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,084,406 Retrofit Installation Factor 30% 325,322
Total Capital Investment, Retrofit Installed 1,409,728



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 15.00 % of Total Capital Investment 162,661 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization 89 Water 0.08 $/mgal, 11 gph, 3156 hr/yr, 28% utilization 1 Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 4,198
Total Annual Direct Operating Costs 166,949
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 133,068 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068

Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018

See Summary page for notes and assumptions

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SNCR #2 SNCR 99 of 106

# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)

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

Electrical Use NOx in 0.28 lb/MMBtu kW NSR 1.37 equation 1.14 Power 2.0

Total 2.0

Reagent Use & Other Operating Costs Urea Use 11.73 lb/hr Neat equation 1.15 50% solution 71.0 lb/ft 3 

### Density 50% Solution 23.46 lb/hr 2.5 gal/hr 831 gal $1,596 Inventory Cost Water Use 11 gal/hr Inject at 10% solution Fuel Use 0.19 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2.0 kW-hr 1,753 89 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization Water 0.08 $/mgal 11.2 gph 10 1 $/mgal, 11 gph, 3156 hr/yr, 28% utilization Urea 405 $/ton 0.0117 ton/hr 10 4,198 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SNCR #2 SNCR 100 of 106

# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Operating Unit: Utility Plant Heater Boiler #4

Em ission Unit Number EU 004 Stack/Vent Number 0 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.18 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 905,717 Purchased Equipment Total (B) 0% of control device cost (A) 905,717

Installation - Standard Costs 15% of purchased equip cost (B) 163,029

Total Capital Investment (TCI) = DC + IC 1,277,232
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 197,883 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730 Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 14.8 50% 7.4 7.4 47,792

Notes & Assumptions 1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI 2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25 4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SNCR #4 SNCR 101 of 106

# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 905,717 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) 905,717

Indirect Installation [1] General Facilities 5% of purchased equip cost (A) 45,286 Engineerin & Home Office 10% of purchased equip cost (A) 90,572 Process Contingency 5% of purchased equip cost (A) 45,286

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 181,143

Project Contingeny ( C) 15% of (A + B) 163,029

Total Plant Cost D A + B + C 1,249,889
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)) 24,998
Inventory Capital Reagent Vol * $/gal 2,345
Intial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,277,232 Retrofit Installation Factor 30% 383,169
Total Capital Investment, Retrofit Installed 1,660,401



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 15.00 % of Total Capital Investment 191,585 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization 131 Water 0.08 $/mgal, 17 gph, 3156 hr/yr, 28% utilization 1 Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 6,166
Total Annual Direct Operating Costs 197,883
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 156,730 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730

Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613

See Summary page for notes and assumptions

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SNCR #4 SNCR 102 of 106

# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)

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

Electrical Use NOx in 0.28 lb/MMBtu kW NSR 1.37 equation 1.14 Power 2.9

Total 2.9

Reagent Use & Other Operating Costs Urea Use 17.23 lb/hr Neat equation 1.15 50% solution 71.0 lb/ft 3 

### Density 50% Solution 34.46 lb/hr 3.6 gal/hr 1,220 gal $2,345 Inventory Cost Water Use 17 gal/hr Inject at 10% solution Fuel Use 0.28 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 191,585 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2.9 kW-hr 2,572 131 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization Water 0.08 $/mgal 16.5 gph 15 1 $/mgal, 17 gph, 3156 hr/yr, 28% utilization Urea 405 $/ton 0.0172 ton/hr 15 6,166 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SNCR #4 SNCR 103 of 106

# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Operating Unit: Utility Plant Heater Boiler #5

Em ission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394 Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.18 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 905,717 Purchased Equipment Total (B) 0% of control device cost (A) 905,717

Installation - Standard Costs 15% of purchased equip cost (B) 163,029

Total Capital Investment (TCI) = DC + IC 1,277,232
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 197,883 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730 Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613



### Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 42.9 13.8 50% 6.9 6.9 51,494

Notes & Assumptions 1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI 2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22 3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25 4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23 5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SNCR #5 SNCR 104 of 106

# US Steel - Minntac Draft BART Emission Control Cost Analysis Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)

CAPITAL COSTS D irect Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 905,717 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) 905,717

Indirect Installation [1] General Facilities 5% of purchased equip cost (A) 45,286 Engineerin & Home Office 10% of purchased equip cost (A) 90,572 Process Contingency 5% of purchased equip cost (A) 45,286

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 181,143

Project Contingeny ( C) 15% of (A + B) 163,029

Total Plant Cost D A + B + C 1,249,889
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)) 24,998
Inventory Capital Reagent Vol * $/gal 2,345
Intial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,277,232 Retrofit Installation Factor 30% 383,169
Total Capital Investment, Retrofit Installed 1,660,401



### OPERATING COSTS Direct Annual Operating Costs, DC

O perating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 15.00 % of Total Capital Investment 191,585 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization 131 Water 0.08 $/mgal, 17 gph, 3156 hr/yr, 28% utilization 1 Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 6,166
Total Annual Direct Operating Costs 197,883
Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 156,730 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730

Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613

See Summary page for notes and assumptions

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SNCR #5 SNCR 105 of 106

# US Steel - Minntac

Draft BART Emission Control Cost Analysis Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)

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

Electrical Use NOx in 0.28 lb/MMBtu kW NSR 1.37 equation 1.14 Power 2.9

Total 2.9

Reagent Use & Other Operating Costs Urea Use 17.23 lb/hr Neat equation 1.15 50% solution 71.0 lb/ft 3 

### Density 50% Solution 34.46 lb/hr 3.6 gal/hr 1,220 gal $2,345 Inventory Cost Water Use 17 gal/hr Inject at 10% solution Fuel Use 0.28 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 191,585 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2.9 kW-hr 2,572 131 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization Water 0.08 $/mgal 16.5 gph 15 1 $/mgal, 17 gph, 3156 hr/yr, 28% utilization Urea 405 $/ton 0.0172 ton/hr 15 6,166 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SNCR #5 SNCR 106 of 106

# 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.

A ttached 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 stations414898, 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
f rom 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.

T he 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. B est 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,

p recipitation 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 MinnTac 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

t he 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
C ALPUFF 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
i mprovement 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
C ALMET, CALPUFF, and CALPOST modeling templates provided by the Minnesota Pollution Control Agency (MPCA). The Minnesota BART modeling protocol 3 

# describes the CALPUFF model inputs
i ncluding 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

a ny 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

c ontribute 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, B est Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota. 4 

# 40 CFR 51, Appendix Y. 5 

# MPCA, March 2006, B est Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota.

# De minimis Modeling As a part of the streamlined BART approach, a method for removing insignificant sources from f urther BART evaluation was developed, with guidance from MPCA. Sources meeting a de minimis threshold would not require further BART analysis. A de minimis threshold of 0.05 dV was used in this analysis.
For this facility, twelve sources were modeled, SV003, 010, 019, 020, 086, 088, 182, and 187 as well as the PM and SO2 emissions from SV001, 002, 004, and 005 were modeled. The maximum 98 th 

# percentile modeled impact for these sources was 0.04 dV, meeting the required de

m inimis threshold of 0.05 dV. This exempts these sources from further BART analysis. A summary of the de minimis modeling is in the table below.

Mo deled 98th Percentile Impact 2002 2003 2004 2002-2004 Maximum BWCA 0.040 0.034 0.029 0.031 0.040 Voyageurs 0.019 0.020 0.016 0.018 0.020



# Predicting 24-Hour Maximum Emission Rates

Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for preB ART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should reflect a maximum 24-hour average basis.

Table 4-1 & Table 6-2 within this report describe the pre and post-BART model input parameters, respectively.



# Modeled Results

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for

t he predicted post-BART emission scenario(s). Results for the 98th percentile and number of days above 0.5 dV at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are
included in Table 6-3.

# Appendix C

1. CALPUFF Modeling System

The CALPUFF Modeling System is the required model for determining visual impacts at long distances
f rom 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.

T he 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. B est 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,

p recipitation 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 MinnTac 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

t he 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
C ALPUFF 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
i mprovement 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
C ALMET, CALPUFF, and CALPOST modeling templates provided by the Minnesota Pollution Control Agency (MPCA). The Minnesota BART modeling protocol 3 

# describes the CALPUFF model inputs
i ncluding 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

a ny 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

c ontribute 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, B est Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota. 4 

# 40 CFR 51, Appendix Y. 5 

# MPCA, March 2006, B est Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota.

# De minimis Modeling As a part of the streamlined BART approach, a method for removing insignificant sources from f urther BART evaluation was developed, with guidance from MPCA. Sources meeting a de minimis threshold would not require further BART analysis. A de minimis threshold of 0.05 dV was used in this analysis.
For this facility, twelve sources were modeled, SV003, 010, 019, 020, 086, 088, 182, and 187 as well as the PM and SO2 emissions from SV001, 002, 004, and 005 were modeled. The maximum 98 th 

# percentile modeled impact for these sources was 0.04 dV, meeting the required de

m inimis threshold of 0.05 dV. This exempts these sources from further BART analysis. A summary of the de minimis modeling is in the table below.

Mo deled 98th Percentile Impact 2002 2003 2004 2002-2004 Maximum BWCA 0.040 0.034 0.029 0.031 0.040 Voyageurs 0.019 0.020 0.016 0.018 0.020



# Predicting 24-Hour Maximum Emission Rates

Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for preB ART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should reflect a maximum 24-hour average basis.

Table 4-1 & Table 6-2 within this report describe the pre and post-BART model input parameters, respectively.



# Modeled Results

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for

t he predicted post-BART emission scenario(s). Results for the 98th percentile and number of days above 0.5 dV at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are
included in Table 6-3.N

Barr Footer: Date: 7/5/2006 1:27:58 PM File: I:\projects\23\00\Minntac.mxd User: ams100 0 100 200MetersMinntac Aerial Photo100 0 100 200MetersTaconite BART AnalysisNOx ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

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

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

Reference No. 1NOxPollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle30SNOXN------------xEarly commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converterpasses through a novel glass-tube condenser in which the SO3ishydrated to H2SO4vapor and then condensed to a concentrated liquidsulfuric acid (H2SO4).31 SOx-NOx-Rox-BoxN------------xTechnology has not beendemonstratedDry sorbent injection upstream of the baghouse for removal of SOx andammonia injection upstream of a zeolitic selective catalytic reduction(SCR) catalyst incorporated in the baghouse to reduce NOx emissions.32 Electron (E-Beam) Process N------------xNo operating commercial applicationson coalElectron beam irradiation in the presence of ammonia to initiate chemicalconversion of sulfur and nitrogen oxides into components which can beeasily collected by conventional methods such as an ESP or baghouse.33 Electrocatalytic Oxidation N------------xSimilar to cold plasma. Will keepwatch for availability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using nonthermal plasma.On recent project, the vender was doing final trials on full-scaleapplications.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------------xAbsorption and SCR. Experiencelimited to pilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheresof alumina, to form copper sulfate. Ammonia is injected into the flue gasbefore the absorption reactor and a selective catalytic reduction-typereaction occurs that reduces the nitric oxides in the flue gas. In theregeneration step, the copper sulfate is reduced in a regenerator with areducing agent, such as natural gas, producing a concentrated stream ofSO2.36 Cold PlasmaN------------xResearch Level37 BiofiltersYN---------xNot applicable to furnaces.Gas stream is passed through a filter medium of soil and microbes.Pollutants are adsorbed and degraded by microbial metabolism formingthe products carbon dioxide and water.38 Pahlman ProcessN------------xResearch LevelGas stream is passed through a filter baghouse in which speciallydeveloped, small-particle, high-surface area metal oxide sorbent havebeen deployed. Pollutants are removed from the gases by adsorption.1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART ReportsTaconite BART AnalysisSO2 ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

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

Reference No. 1SO2Pollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle15 Electrocatalytic OxidationN------------xSimilar to cold plasma. Will keep watch foravailability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-thermalplasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSON------------Commercial version of adsorption. Limitedexperience (proof-of-concept tests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gasfrom coal-fired utility and industrial boilers. In the process, the SO2is converted toa saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) and theNOx is converted to nitrogen and oxygen.17 Copper-OxideN------------xAbsorption and SCR. Experience limited topilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheres ofalumina, to form copper sulfate. Ammonia is injected into the flue gas before theabsorption reactor and a selective catalytic reduction-type reaction occurs thatreduces the nitric oxides in the flue gas. In the regeneration step, the copper sulfateis reduced in a regenerator with a reducing agent, such as natural gas, producing aconcentrated stream of SO2.18SNOXN------------xEarly commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converter passesthrough a novel glass-tube condenser in which the SO3is hydrated to H2SO4vaporand then condensed to a concentrated liquid sulfuric acid (H2SO4).19 Cold PlasmaN------------xResearch level1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART ReportsSummary of Relevant Economic Feasibility ($/ton) Control CostsAvg. Expected Values($/ton)Limiting/Marginal values($/ton)ReferenceRegulatory Body/RuleSO2NOxSO2NOxCommentsBART100 - 1000 100 - 100070 FR 39135BART281 - 129670 FR 39135 Table 3BART91970 FR 39133FR Notice 6JULY05 Final RuleBARTGuidelines disparagingly reference "thousands of dollars per ton"in commenting on the need to exceed MACT and its generalunreasonableness.70 FR 25210 CAIRCAIR1300Estimated Marginal cost 2009BART(proposed rule) 200-1000BART proposed lists this as values for 90-95% SO2 control,which is still assumed, or .1 to .15 lb/MMBtu. Dropped fromfinal to give states flexibility to require more. Says for scrubbers,bypasses aren't BART, only 100% scrubbing is BART.FR Notice 5MAY04 Proposed RuleBART(proposed rule)0.2 lb/MMBtu for NOx is assumed reasonable. Recognizes thatsome sources may need SCR to get this level. For those, statediscretion of the cost vs. visibility value is necessary.CAIR(using IPM)1000 1500CAIR ( 2009 in 1999$)9002400CAIR ( 2015 in 1999$)18003000Midwest RPO Report ReferencingCAIRCAIR (depending onNat'l emissions)1200 - 3000 1400- 2100This was modeled with TRUM (Technology RetrofittingUpdating Model) to develop the marginal values.Kammer EPA DecisionKammer Decision> 1000 > 1000LADCO Midwest RPO BoilerAnalysisLADCO/Midwest RPO 1240 - 3822 607 - 4493MANE-VU BART ControlAssessmentMANE-VU200 - 500 200 - 1500Bowers vs. SWAPCABowers vs. SWAPCA 300 300 1000 1000954-1134 was ruled too much, in favor of 256-310 for SO2. Thisdid consider incremental value. Sections XVII to XIXWRAP3000WRAP Trading ProgramMethodologyEPA - Referenced byWrapReferences EPA-600S\7-90-018. Low is <$500/ton, Moderate is$500-3000/ton, High is over $3000/tonThe dollars per ton estimates cited above were obtained from BART guidance, documentation of similar regulatory programs such as CAIR,and relevant court decisions. These materials indicate that most EPA sanctioned documents, including the final BART ruling, concretelysupport an average expected reasonable cost range of $1,300 to $1,800 per ton of NOx removed and a range of $1,000 to $1,300 per ton ofSO2removed. The BART presumptive limits were set based on cost effective controls that were on average less than these ranges. As anexample, the presumptive SO2limit was established based on an average cost effectiveness of less than $1,000/ton. As the cost analysisextends into RPO, WRAP and other regional planning documentation, the cost ranges become more variable and difficult to predict. Forease of comparison, the federally established ranges for NOx and SO2were used as a BART cost threshold basis.

# Taconite BART Analysis NO X 

# Control Process Boilers Available and Applicable Review

Step 1 Step 2Reference No.1



### NO x 

### Pollution Control T echnologyIs this a generallyavailable controltechnology?Is the control technologyavailable to processboilers?Is the control technologyapplicable to this specificsource?Is it technically feasiblefor this source?



### Approximate Control Efficiency 

## Combustion Controls

1 E xternal Flue Gas Recirculation (EFGR) Y Y N N

---

2 Low-NOx Burners (LNB) Y Y Y Y 50%

3 LNB with Overfire Air (OFA) Y Y Y Y 68%

4 Induced Flue Gas Recirculation Burners Y Y Y Y 75%
10 Energy Efficiency Projects Y Y Y Y Site-specific

15 Alternate Fuels Y Y Y Y (not required by BART) Site-specific

Post Combustion Controls

21 Non-Selective Catalytic

Reduction (NSCR) Y N

--- --- ---

22 Low Temperature Oxidation

(LTO) - Tri-NOx® Y N

--- --- ---

23 Low Temperature Oxidation

(LTO) - LoTOx Y Y Y Y 90%

24 Selective Catalytic

Reduction (SCR) Y Y Y Y 80%

25 Regenerative SCR Y Y Y Y 70%

26 Selective Non-Catalytic

Reduction (SNCR) Y Y Y Y 50%

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.htm 2) c) New and Emerging Environmental Technologies, http://neet.rti.org/ 2) d) ND BART Reports