## Keetac BART Report September 8, 2006

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# i 

# Keetac BART Report September 8, 2006

Table of Contents

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

2. Introduction...........................................................................................................................................1 2.A BART Eligibility.........................................................................................................................3 2.B BART Determinations ................................................................................................................3

3. Streamlined BART Analysis ................................................................................................................9 3.A Indurating Furnaces ....................................................................................................................9 3.B PM-Only Taconite MACT Emission Units ................................................................................9 3.C Sources of fugitive PM that are subject to MACT standards....................................................10 3.D Non-MACT Units and Fugitive Sources (PM only).................................................................10 3.E Other Combustion Units ...........................................................................................................11 3.F Visibility Impact Modeling for Negligible Impacts..................................................................11

4. Baseline Conditions and Visibility Impacts for BART Eligible Units ...............................................13 4.A MPCA Subject-to-BART Modeling .........................................................................................13 4.B Facility Baseline Emission Rates..............................................................................................14 4.C Facility Baseline Modeling Results ..........................................................................................16
5. BART Analysis for BART Eligible Emission Units ..........................................................................18 5.A Indurating Furnace....................................................................................................................18 5.A.i Sulfur Dioxide Controls............................................................................................... 19 5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 19 5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 19 5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies................................................................................................ 26 5.A.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 26 5.A.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 30 5.A.ii Nitrogen Oxide Controls.............................................................................................. 34 5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 34 5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 34 5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies................................................................................................ 47 5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results............................... 47 5.A.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 50
6. Visibility Impacts................................................................................................................................55 6.A Post-BART Modeling Scenarios...............................................................................................55

## Keetac BART Report September 8, 2006

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# ii 6.B Post-BART Modeling Results ..................................................................................................55

7. Select BART.......................................................................................................................................61

List of Tables

Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis ....12 Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data..15 Table 4-2 Baseline Visibility Modeling Results..........................................................................17 Table 5-1 Indurating Furnace SO 2 

# Control Technology – Availability, Applicability, and

Technical Feasibility ..................................................................................................25 Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness.........................................26 Table 5-3 SO 2 

# Control Cost Summary ........................................................................................28 Table 5-4 SO 2 

# Control Technology Impacts Assessment.............................................................29 Table 5-5 Post- BART SO 2 

# Control - Predicted 24-hour Maximum Emission Rates....................32 Table 5-6 Post-BART SO 2 

# Modeling Scenarios - Visibility Modeling Results ............................33 Table 5-7 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and

Technical Feasibility ..................................................................................................46 Table 5-8 Indurating Furnace NO x 

# Control Technology Effectiveness ........................................47 Table 5-9 NO x 

# Control Cost Summary........................................................................................48 Table 5-10 NO x 

# Control Technology Impacts Assessment ............................................................50 Table 5-11 Post- BART NO X 

# Control - Predicted 24-hour Maximum Emission Rates...................52 Table 5-12 Post-BART NO X 

# Modeling Scenarios - Visibility Modeling Results ...........................53 Table 6-1 Post-BART Modeling Scenarios – Predicted 24-hour Maximum Emission Rates ........56 Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results ...................................60

List of Figures

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

List of Appendices

Appendix A Control Cost Analysis Spreadsheets Appendix B Visibility Impacts Modeling Report Appendix C Changes to MPCA BART Modeling Protocol Appendix D Indurating Furnace – Applicable and Available Retrofit Technologies Appendix E NO X 

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

at USS/Minntac Appendix F Summary of Relevant Economic Feasibility ($/ton) Control Costs

## Keetac BART Report September 8, 2006

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# iii 

# 1. Executive Summary

U.S. Steel Corporation’s Keewatin Taconite Operations (Keetac) is located in northern Minnesota, with mining and processing facilities in Keewatin, Minnesota. This report describes the background and methods for the selection of the Best Available Retrofit Technology (BART) as proposed by Keetac 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, Keetac’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 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 Keetac “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 facilities to focus their resources on the main contributors to visibility impairment. As described in section 3 of this document, the emissions from several of the sources at this facility meet the criteria for a streamlined analysis.

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

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

# and NO x 

# emissions from the indurating furnace. At the time of the BART baseline period, the indurating furnace operated with two centrifugal collectors for the control of particulate matter (PM) with collateral control of sulfur dioxide (SO 2 

# ) and the furnace was only permitted to burn natural gas.

1 

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

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# iv However, based on permit 13700063-003, two new SO 2 

# scrubbers were installed that operate in parallel and the furnace was permitted to burn coal. The new scrubber started operation in October 2005 and coal burning commenced in December 2005.

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 consideration of all of the above criteria, Keetac proposes the following as BART for SO 2 

# and NO X 

# for the Indurating Furnace:

• BART for SO 2 

# :

o SO 2 

# emissions will be controlled by the new wet scrubbers, which will be operated as required in accordance with provisions of the Taconite MACT and permit 13700063-003.

o SO 2 

# removal efficiency of the wet scrubbers will be maintained at a minimum of 34%; this is based on compliance tests from October 2005 and May 2006 while operating at a pH of 6.5 which is anticipated to be the minimum operating pH, except during periods of startup, shutdown, malfunction, and acid wash.

o Compliance will be initially demonstrated by existing performance test data, as performed in October 2005 and May 2006.

o Continuous compliance will be demonstrated by continuous monitoring of the scrubber water pH, the scrubber water flow rate, and the scrubber pressure drop. These are the same parameters that are required to be monitored by the Taconite MACT and/or permit 13700063-003. The operating limits will be determined

based on the initial SO 2 

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

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# v • BART for NO x 

# :

o NO x 

# emissions will be controlled by existing combustion controls and fuel blending.

o NO x 

# CEMS will be installed for the purpose of NO X 

# monitoring.

o NO x 

# emission limits will be proposed by the facility 12-months after the

installation of the NO x 

# CEMS to allow the facility sufficient time for monitoring to determine the actual emission rates under a variety of operating 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.

The schedule implementing the SO 2 

# scrubber monitoring program, installing the NO x 

# CEMS, and determining the appropriate NO x 

# emissions limit will be within the 5-year time-frame required for BART implementation. In addition, Keetac 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 NO x 

# emission rates as determined during recent stack testing, the proposed BART controls will result in visibility improvement on the 98 th 

# percentile day of approximately 0.032 deciviews (dV) when burning gas and 0.675 dV when burning coal. These reductions represent visibility improvements of approximately 3% and 54%, respectively, compared to the baseline (pre-BART) operating conditions.

## Keetac BART Report September 8, 2006

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# 1 

# 2. Introduction

To meet the Clean Air Act’s requirements, the U.S. Environmental Protection Agency (U.S. EPA) published regulations in July 1999 to address visibility impairment in our nation’s largest national parks and wilderness (“Class I”) areas. This rule is commonly known as the “Regional Haze Rule” [64 Fed. Reg. 35714 (July, 1999) and 70 Fed. Reg. 39104 (July 6, 2005), and] and is found in 40 CFR part 51, in §51.300 through §51.309.

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

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

## Keetac BART Report September 8, 2006

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

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

(Source MPCA BART-Strategy October 4, 2005)



# By 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.

## Keetac BART Report September 8, 2006

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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 must meet the following three conditions:

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

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

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

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

# , PM 2.5 

# , SO 2 

# , NO x 

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

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



# 2.B BART Determinations Each source that is subject to BART must determine BART on a case-by-case basis. Even if a source was previously part of a group BART determination, individual BART determinations must be made 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,

## Keetac BART Report September 8, 2006

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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



# The five steps of a BART analysis are:

Step 1 - Identify all Control Technologies

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

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

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



# Step 2 - Eliminate Technically Infeasible Options

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

a. 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



# b. 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



# c. 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



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



# Step 3 - Evaluate Control Effectiveness

In step three, the remaining controls are ranked based on the control efficiency at the expected emission rate (post-BART) as compared to the emission rate before addition of controls (pre-BART) for the pollutant of concern.

Step 4 - Evaluate Impacts and Document Results

In the fourth step, an engineering analysis documents the impacts of each remaining control technology option. The economic analysis compares dollar per ton of pollutant removed for each technology. In addition it includes incremental dollar per ton cost analysis to illustrate the economic effectiveness of one technology in relation to the others. Finally, step four includes an assessment of energy impacts and other non-air quality environmental impacts.

Economic impacts were analyzed using the procedures found in the U.S. EPA Air Pollution Control Cost Manual – Sixth Edition (EPA 452/B-02-001). Equipment cost

estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA’s Air Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model version 7.5 were used. Vendor cost estimates for this project were used when applicable. The source of the control equipment cost data are noted in each of the control cost analysis worksheets as found in Appendix A.

Step 5 - Evaluate Visibility Impacts

The fifth step requires a modeling analysis conducted with U.S. EPA -approved models such as CALPUFF. The modeling protocol 8 

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

.

## Keetac BART Report September 8, 2006

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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



# To complete the BART process, the analysis must “establish enforceable emission limits that reflect the BART requirements and requires compliance within a reasonable period of time.” 10 

# Those limits must be developed for inclusion in the state implementation plan (SIP) that is due to U.S. EPA in December of 2007. In addition, the analysis must include requirements that the source “employ techniques that ensure compliance on a continuous basis” 11 

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

9 

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

# MPCA. March 2006. Guidance 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



# Compliance 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 facilities 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.

Relative to NO x 

# and SO 2 

# , PM is not a major visibility impairing pollutant. Further, the indurating furnace 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, the technology analysis is up-to-date. As a result, BART will be presumed to be equivalent to MACT for PM and no further analysis will be required to establish BART for PM for these sources.

A full BART analysis will be conducted for NO x 

# and SO 2 

# for the indurating furnace at Keetac. 

# 3.B PM-Only Taconite MACT Emission Units In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions from Ore Crushing and Handling operations, Pellet Coolers, and Finished Pellet Handling operations. These sources operate near ambient temperature, only emit PM, and do not emit NO x 

# or SO 2 

# . The Ore Crushing and Handling sources and the Finished Pellet Handling sources operate with control equipment to meet the applicable MACT limits (0.008 gr/dscf for existing sources and 0.005 gr/dscf for new sources). The Pellet Cooler sources are excluded from additional control under the MACT

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

emissions. 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. Guidance for Facilities Conducting a BART Analysis . Page 2. 15 

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

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

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

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

# 3.C Sources of fugitive PM that are subject to MACT standardsThe taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from nonMACT sources are addressed in section 3.D). No equipment that emits fugitive PM has been identified at Keetac as potentially BART-eligible equipment, so these sources are not required to be addressed. Therefore, no analysis is required to establish BART for fugitive PM sources. 

# 3.D Non-MACT Units and Fugitive Sources (PM only) A few sources of PM emissions and sources of fugitive PM are not subject to a MACT standard. This includes additive blending, storage and handling. There are no fugitive sources at the facility which have been identified as subject-to-BART.

Considering all PM emissions which are subject to the BART standard, the PM emissions from the above units represent less than 0.5% 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.

The point source emission units are controlled by high efficiency wet scrubbers and baghouses. These are technologies which 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. Existing controls will be considered BART consistent with direction from MPCA in the May 18, 2006 meeting.

## Keetac BART Report September 8, 2006

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# 11 

# 3.E Other Combustion Units There were no other combustion units identified as subject-to-BART at the Keetac facility. Therefore, no analysis is required for “other combustion units.”


# 3.F Visibility Impact Modeling for Negligible Impacts There were no sources requiring visibility impacts modeling for negligible impacts at the Keetac facility. Therefore, no visibility impacts analysis was required for modeling for negligible impacts.

## Keetac BART Report September 8, 2006

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

## Keetac BART Report September 8, 2006

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# 13 

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

As indicated in U.S. EPA’s final BART guidance 16 

# , one of the factors to consider when determining BART for an individual source is the degree of visibility improvement resulting from the retrofit technology. The visibility impacts for this facility were determined using CALPUFF, 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

PM 10 

# can play a large part in predicting impairment. It is therefore important to take a multi-pollutant approach when assessing visibility impacts.

In order to 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 17



# . 

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

16 

# Federal Register 70, no. 128 (July 6, 2005): 39106. 17 

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

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# 14 

# 4.B Facility Baseline Emission Rates Prior to re-creating the MPCA visibility impairment model, the modeling protocol was re-revaluated. On 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 C. The MPCA has given verbal approval to the proposed changes to the modeling protocol.

In addition, the maximum 24-hour emission rates were re-evaluated and adjusted, as appropriate, to confirm that the emission rates represent the maximum steady-state operating conditions during periods of high capacity utilization. The maximum 24-hour emission rates were adjusted to reflect the highest actual emission rate as opposed to the maximum annual emission rate. The baseline emission rates from the following sources were adjusted using these criteria:

• Indurating Furnace: The 24-hour maximum SO 2 

# emissions as submitted in BART questionnaire were based on the MPCA permit limit of 951 tons/year (5,211 lb/day) based on the annual emission limit in the Title V permit. The SO 2 

# emissions were changed to 7,152 lb/day based on the results of a stack test conducted in October 2005 on the scrubber inlet, which represents the worst case emissions for Keetac’s indurating furnace during the baseline period.

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

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

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# 16 

# 4.C Facility Baseline Modeling Results The Minnesota BART modeling protocol also describes the post processing elements of the analysis. 18 

# The CALBART output files provide the following two methods to assess the expected post-BART visibility improvement:

• 98 th 

# Percentile: As defined by federal guidance and as stated in the MPCA’s document which identifies the Minnesota facilities that are subject to BART 19 

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

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

# highest day) meets or exceeds the threshold of five-tenths (0.5) of a deciview (dV) at a Federally protected Class I area receptor.

• Number of Days Exceeding 0.5 dV: The severity of the visibility impairment contribution, or reasonably attributed visibility impairment, can be gauged by assessing the number of days on which a source exceeds a visibility impairment threshold of 0.5 dV.

A summary of the baseline visibility modeling is presented in Table 4-2. As illustrated in the table, 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 exceeds the threshold of 0.5 dV. The results of this modeling are also utilized in the post-BART modeling analysis in section 6 of this document.

The full modeling analysis is presented in Appendix B.

18 

# MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota. Page 8. 19 

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

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# 17 Table 4-2 Baseline Visibility Modeling Results

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# 18 

# 5. BART Analysis for BART Eligible Emission Units

BART eligible sources at this facility can be divided into groups based upon the type of process. However, the Keetac facility has only one source required to undergo a full BART analysis for NO x 

# and SO 2 

# :

• Grate Kiln – Indurator Waste Gas, Phase II (EU 030, SV 051)


# 5.A Indurating Furnace “Soft” or “green” pellets are oxidized and heat-hardened in the induration furnace. The induration process involves pellet pre-heating, drying, hardening, oxidation and cooling.

Keetac has one grate/kiln induration furnace, 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.

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 grate/kiln induration furnace at this facility utilizes the following fuels:

• Natural gas, coal, fuel oil, and petroleum coke.

Emissions from the induration furnaces are controlled as follows:

• PM / PM 10 

# : PM emissions are controlled using two new wet scrubbers which operate in parallel using hydrated lime to control the pH of the water-based scrubbing solution.

• SO 2 

# : SO 2 

# emissions are controlled using two new wet scrubbers which operate in parallel using hydrated lime to control the pH of the water-based scrubbing solution. Based on recent

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# 19 stack test data, the SO 2 

# scrubbing efficiency is approximately 34% at the typical minimum operating pH of 6.5. The minimum operating pH is anticipated to be 6.5 at all times, except during periods of startup, shutdown, malfunction, and acid wash.

• NO X 

# : NO X 

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

# emissions when burning solid fuels).



# 5.A.i Sulfur Dioxide Controls

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

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

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

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

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

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

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# 20 The following section describes retrofit SO 2 

# control technologies that were identified as available and applicable in the May 9 submittal and discusses aspects of those technologies that determine whether or not the technology is technically feasible for the indurating furnace.

Wet Walled Electrostatic Precipitator (WWESP) An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the flue gas stream. The suspended particles are given an electrical charge by passing through a high voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal.

A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry ESP and uses a water spray to remove particulate matter from the collection plates. For SO 2 

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

# absorber.

The SO 2 

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

as SO 2 

# flue gas concentration, fuel used, and ore composition. Since the induration furnaces at this facility 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 polishing SO 2 

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

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

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

# reduction for this BART analysis.

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

# , is generally termed flue-gas desulfurization (FGD). FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting liquid, to remove SO 2 

# in the waste gas. Crushed limestone, lime, or caustic are typically used as scrubbing 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.

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# 21 For a wet scrubber to be considered a high efficiency SO 2 

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

# . Typical high efficiency SO 2 

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

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

# could be a venturi rod scrubber design using water as a scrubbing solvent. Venturi rod scrubbers, which are frequently used for PM control at taconite facilities, will also remove some of the SO 2 

# from the flue gas as collateral

emission reduction.

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

CaCO 3 

# + SO 2 

# → CaSO 3 

# • 1/2 H2O + CO 2 

# CaSO 3 

# •1/2 H 2 

# O + 3H 2 

# O + O 2 

# → 2 CaSO 4 

# •2 H 2 

# O

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a more reactive reagent than limestone. The reactions for lime scrubbing are as follows:

Ca(OH) 2 

# +SO 2 

# → CaSO 3 

# • 1/2 H 2 

# O + 1/2 H 2 

# O Ca(OH) 2 

# + SO 2 

# + 1/2 O 2 

# + H 2 

# O → CaSO 4 

# •2 H 2 

# O

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

# removal reactions are as

follows:

Na+ + OH- + SO 2 

# + → Na 2 

# SO 3 

# 2Na+ + 2OH- + SO 2 

# + → Na 2 

# SO 3 

# + H 2 

# O

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

# removal, additional equipment 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 excess air is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency scrubbers. The highest control efficiencies can be achieved when SO 2 

# concentrations are the highest. Unlike

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

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

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

# control efficiency of the

wet scrubber.

As previously stated, two new wet scrubbers are currently in place and operate in parallel on the

furnaces exhausts. The scrubbers remove 34% of the SO 2 

# at the anticipated minimum operating pH of 6.5 and greater than 50% at the typical operating pH of 7.5. Taking into consideration the removal

of SO 2 

# from the existing scrubber as well as a high efficiency SO 2 

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

The new SO 2 

# scrubbers which commenced operation in October 2005 have been evaluated, tested, and optimized for SO 2 

# per the design of the scrubbers. Since the operation of the scrubber has recently been optimized, further improvement of SO 2 

# removal efficiency of the existing scrubber is not feasible and is not considered further in this report.

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

# reduction for this BART analysis.

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

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

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

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

# control efficiency range for dry SO 2 

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

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

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

# is absorbed by the slurry, forming CaSO 3 

# /CaSO 4 

# . The liquid-to-gas ratio is such that the water evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the gas and collected with a fabric filter. When used to specifically control SO 2 

# , the term flue-gas desulfurization (FGD) may also be used.

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

Energy Efficiency Projects Energy efficiency projects provide opportunities for a 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 Keetac 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 through 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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# 24 significantly less NO x 

# when burning solid fuels. Therefore, if this option is pursued, the impact on emissions 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. 20



# Therefore, 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, Keetac 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 and 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. 21 

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

20 

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

21 

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

# process under development by KFx, Inc.

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# 25To 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 to 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 available and applicable to the indurating furnace process are identified in Table 5-1. The technical feasibility as determined in Step 2 is also included in Table 5-1.

Table 5-1 Indurating Furnace SO 2 

# Control Technology – Availability, Applicability, and Technical Feasibility

Step 1 Step 2

SO 2 

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



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

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

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# 26 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%



# 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



# Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. EPA models and factors. Operating costs were based on 93% utilization and 8400 operating hours per year which is based on historic operating records. Operating costs of consumable materials, such as electricity, water, and chemicals were established based on the U.S. EPA control cost manual 22

22 

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

.

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# 27 and engineering experience, and 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. 23 

# After discussions with facility staff and management, 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, such as an SO2 scrubber or WWESP, on the roof. Therefore, the cost estimates provide for additional site-work and construction costs to accommodate the new equipment within the facility. A site-specific estimate for site work, foundations, and structural steel was added to arrive at the total retrofit installed cost of the control technology. The site specific estimate was based on recent actual retrofit costs for installation of a secondary wet scrubber at 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 E. This cost-effective threshold is also an indirectmeasure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,3000 cost effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for proposing BART in lieu of developing industry and site specific data.

23 

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

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# 28 Table 5-3 SO 2 

# Control Cost Summary

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# 29 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 24



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

The cost of SO 2 

# control with a WWESP is greater than the screening level of $12,000 per ton 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, this alternative is removed from further consideration in this analysis.

The costs of SO 2 

# control with a second wet scrubber are below the MPCA recommended screening threshold of $12,000 per ton, and therefore is carried forward in the BART analysis.

Energy and Environmental Issues The energy and non-air quality impacts for wet scrubbers are presented in Table 5-4.

Table 5-4 SO 2 

# Control Technology Impacts Assessment

Control Technology Energy Impacts Other Impacts

Secondary Wet Scrubber • Significant pressure drop results in higher electrical requirements • Additional water consumption and wastewater generation

• Increased facility waterbalance and water quality issues

• Additional solid waste/sludge generation

• Process downtime/lost production during installation?

24 

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

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# 30 5.A.i.e STEP 5 – Evaluate Visibility Impacts As previously stated in section 4 of this document, states are required to consider the degree of visibility improvement resulting from the retrofit technology, in combination with other factors such as economic, energy and other non-air quality impacts, when determining BART for an individual source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document. This section of the report evaluates the visibility impacts of BART SO 2 

# control and the resulting degree of visibility improvement.

However, as previously stated, two new scrubbers were installed on the indurating furnace after the BART baseline period and started operation in October 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, the emissions in the post-BART modeling analysis must be adjusted to account for the improved removal efficiency. Therefore, the visibility impacts modeling presented in this section also present 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 indurating furnace were adjusted to account for the new wet scrubber and for the ability for the furnace to burn coal. However, it is important to note that the worst-case SO 2 

# emissions scenario is based on coal burning and the worst-case NO x 

# emissions scenario is based on natural gas burning. Therefore, post-baseline (i.e. post-BART) modeling was conducted for two separate operating scenarios: (1) burning natural gas and (2) burning solid fuel. Table 5-5 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 operations. The stack parameters (location, height, velocity, and temperature) were assumed to remain unchanged from the baseline modeling.

Post-BART Visibility Impacts Modeling Results Results of the post-BART visibility impacts modeling for SO 2 

# are presented in Table 5-6. 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:

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# 31 • Current Operation:

o Natural Gas Operation: The operation of the new SO 2 

# scrubbers when burning natural gas results in a visibility improvement of 0.032 dV which represents a 3% improvement compared to the baseline. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 118 days.

o Coal Operation: The operation of the new SO 2 

# scrubbers when burning coal results in a visibility improvement of 0.675 dV which represents a 53% improvement compared to the baseline. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 32 days.

 Secondary SO 2 

# Scrubber:

o Natural Gas Operation: The operation of a second SO 2 

# scrubber, in combination with the existing SO 2 

# scrubber, when burning natural gas results in a visibility improvement of 0.056 dV which represents a 5% improvement compared to the baseline. This is a 0.024 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 112 days.

o Coal Operation: The operation of a second SO 2 

# scrubber, in combination with the existing SO 2 

# scrubber, when burning coal results in a visibility improvement of 0.778 dV which represents a 62% improvement compared to the baseline. This is a 0.102 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 19 days.

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

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# 32 Table 5-5 Post- BART SO 2 

# Control - Predicted 24-hour Maximum Emission Rates

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# 33 Table 5-6 Post-BART SO 2 

# Modeling Scenarios - Visibility Modeling Results

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# 34 

# 5.A.ii Nitrogen Oxide Controls

To be able to control NO x 

# it is important to understand how NO x 

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

# production occurs:

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

# .

• Thermal NO x 

# production arises from the thermal dissociation of nitrogen and oxygen molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen.

Thermal NO x 

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

• Prompt NO x 

# is a form of thermal NO x 

# which is generated at the flame boundary. It is the result of reactions between nitrogen and carbon radicals generated during combustion. Only

minor amounts of NO x 

# are emitted as prompt NO x 

# .

The majority of NO x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the heater, the balance

of NO 2 

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

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 D.

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

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

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

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

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

The following section describes retrofit NO x 

# control technologies that were identified as available and applicable in the May 9 submittal and discusses aspects of those technologies that determine whether or not the technology is technically feasible for the indurating furnace.

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

# formation. In an external flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x 

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

The typical NO x 

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

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

1. The process exhaust gas in an induration furnace has approximately 15% - 18% oxygen versus a boiler which has 2% - 3% oxygen. In a boiler, the flue gas is relatively inert so it can be used as a diluent for 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 product specifications. Existing burners are designed to meet these process conditions.

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# 36 Application of EFGR would reduce flame temperatures. Lower flame temperatures would reduce furnace temperatures to the point that product quality could be jeopardized.

3. Application of EFGR technology increases flame length. Dilution of the combustion reactants increases the reaction time needed for fuel oxidation to occur; so, flame length increases. Therefore, application of EFGR could result in flame impingement on furnace components. That would subject those components to excessive temperatures and cause equipment failures.

Although this may be an available and applicable control option, it is not technically feasible due to the high oxygen content of the flue gas and will not be further evaluated in this report.

Low-NO x 

# Burners

Low-NO x 

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

# formation through the restriction of oxygen, flame temperature, and/or residence time. LNB is typically a staged combustion process that is designed to split fuel combustion into two zones, primary combustion and secondary combustion. This analysis utilizes the staged fuel design in the cost analysis because lower emission rates can be achieved with staged fuel burner than with a staged air burner.

In the primary combustion zone of a staged fuel burner, NO x 

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

# formation. In the secondary combustion zone, incomplete combustion products formed in the primary zone act as reducing agents. In a reducing atmosphere, nitrogen compounds are preferentially converted to molecular nitrogen (N 2 

# ) over nitric oxide (NO).

If LNB were to be applied in the indurating section of the furnace, the reduced flame temperatures associated with LNB would adversely affect taconite pellet product quality. 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 credited for that section of the furnace. However, the indurating furnace at this facility does not have a preheat section. Therefore, low-NO x 

# burners are not a feasible control technology for the indurating furnace.

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

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

# burner control technologies. The burner is designed to draw flue gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel combustion to further reduce flame temperature. The estimated NO x 

# control efficiency for IFGR burners in high temperature applications is 25-50%.

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

Although this may be an available and applicable control option, it is not technically feasible due to the high oxygen content of the flue gas and will not be further evaluated in this report.

Energy Efficiency Projects Energy efficiency projects provide opportunities for a 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 Keetac 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

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# 38 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.

Keetac’s sister facility, Minntac, installed air injection ports on the kilns on lines 6 and 7. In March 2002, Minntac submitted a report to MPCA presenting an analysis of the NO X 

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

# emissions from the kiln decreased by approximately 5% when 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 at Keetac, it is important 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.

Based on the experience gained at Minntac, ported kilns are considered available and technically feasible control technologies.

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 through 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 significantly less NO x 

# when burning solid fuels. Therefore, if this option is pursued, the impact on emissions 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. 25

25 

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

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# 39 Therefore, 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, Keetac will continue to evaluate and implement alternate fuel usage as the feasibility arises.

Process Optimization with NO x 

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

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

# emissions 26 

# . Based on conversations with MPCA staff, this work practice would include process adjustments, or optimization, to minimize NO x 

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

# CEMS. If NO x 

# CEMS are not installed, it may also be possible to measure the impact of the process changes using parametric monitoring.

As part of the negotiation of the draft PSD permit, Keetac’s sister facility, Minntac, has installed NO x 

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

# CEMS has resulted in lower emissions being reported in the annual 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 worst-case operating conditions. In addition, the NO x 

# CEMS has allowed Minntac to quantify the emissions rates for all fuel combinations.

Although the NO x 

# CEMS has allowed the facility to use better data for reporting, Minntac has not yet 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. Therefore, process optimization as a control option will not be evaluated further in this report.

Post Combustion Controls

NO x 

# can be controlled using add-on systems located downstream of the furnace area of the combustion process. The two main techniques in commercial service include the selective non catalytic reduction (SNCR) process and the selective catalytic reduction (SCR) process. There are a number of different process systems in each of these categories of control techniques.

26 

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

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# 40 In addition to these treatment systems, there are a large number of other processes being developed and tested on the market. These approaches involve innovative techniques of chemically reducing, absorbing, or adsorbing NO x 

# downstream of the combustion chamber. Examples of these alternatives are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these

alternatives is described below.

Non-Selective Catalytic Reduction (NSCR) A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied primarily in natural gas combustion applications.

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

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

# emission reductions of 90 percent. In order to operate properly, the combustion process must be near stoichiometric conditions. Under this condition, in the presence of a catalyst, NO x 

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

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO x 

# removal

are:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (2)

NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to the indurating furnace. In addition, we are not aware of any NSCR installations on taconite induration furnaces or similar combustion equipment. Therefore, this technology will not be further evaluated in this report.

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction SCR is a post-combustion NO x 

# control technology in which ammonia (NH 3 

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

# is removed through the following chemical reaction:

4 NO + 4 NH 3 

# + O 2 

# → 4 N 2 

# + 6 H 2 

# O (1)

2 NO 2 

# + 4 NH 3 

# + O 2 

# → 3 N 2 

# + 6 H 2 

# O (2)

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

# decomposition. SCR requires a temperature range of about 570°F – 850°F for a normal catalyst. At temperature exceeding approximately 670oF, the oxidation of ammonia begins to become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and corrosion problems. A high temperature zeolite catalyst is also available; it can operate in the 600 °F 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 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.

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# 42 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.

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. 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;

• 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.

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, and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas (4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium

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# 43 hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The nitrates are removed from the scrubbing system and discharged to an appropriate water treatment system. Commercially available LTO systems include Tri-NO x 

# ® and LoTOx®.

NO + O 3 

# → NO 2 

# + O 2 

# (1)

NO 2 

# + O 3 

# → NO 3 

# + O 2 

# (2)

NO 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O → 2HNO 3 

# (4)

HNO 3 

# + NaOH → NaNO 3 

# + H 2 

# O (5)

Low Temperature Oxidation (Tri-NO x ® 

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

# in a primary scrubbing stage. Then NO 2 

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

reactions are as follows:

O 3 

# + NO → O 2 

# + NO 2 

# (1)

2NaOH + 2NO 2 

# + 1⁄2 O 2 

# → 2NaNO 3 

# + H2O (2)

Tri-NO x ® 

# is a multi-staged wet scrubbing process in industrial use. Several process columns, each assigned a separate processing stage, are involved. In the first stage, the incoming material is quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO 2 

# . Subsequent stages reduce NO 2 

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

# process is that concurrent scrubbing of sulfuric acid mist can be achieved.

Tri-NO x ® 

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

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

# ). NO x 

# concentrations in taconite exhaust are typically no higher than 300 ppm. Therefore, Tri-NO x ® 

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

Low Temperature Oxidation (LoTOx ® 

# )

BOC Gases’ Lo-TOx ® 

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

# technology uses ozone

to oxidize NO to NO 2 

# and NO 2 

# to N 2 

# O 5 

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

# O 5 

# is converted to HNO 3 

# in a

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# 44 scrubber, and is removed with lime or caustic. Ozone for LoTOx ® 

# is generated on site with an electrically powered ozone generator. The ozone generation rate is controlled to match the amount

needed for NO x 

# control. Ozone is generated from pure oxygen. In order for LoTOx ® 

# to be economically feasible, a source of low cost oxygen must be available from a pipeline or on site generation.

The first component of the technical feasibility review includes determining if the technology would apply to the process being reviewed. This would include a review and comparison of the chemical and physical properties required. Although it appears that the chemistry involved in the LTO technology 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 technology is commercially available. Evaluations of LTO found that it has only been applied to small to medium sized coal or gas fired boiler applications, and has never been demonstrated on a large-scale facility. For example, the current installations of LoTOx ® 

# are on sources with flue gas flow rates from 150 – 35,000 acfm, which is quite small, compared to the indurating furnace flue gas flow rates of up to 205,000 acfm. This large scale-up is contrary to good engineering practices and could be problematic in maintaining the current removal efficiencies.

In addition, only two of BOC’s LoTOx ® 

# installations are fully installed and operational applications. Therefore, although this is an emerging technology, the limited application means that it has not been demonstrated to be an effective technology in widespread application.

There are several other concerns about the technical feasibility and applicability of LTO on an indurating furnace:

• The composition of the indurating furnace flue gas is significantly different than the composition of the flue gas from the boilers and process heaters that utilize LTO;

• The taconite dust in the flue gas is primarily magnetite (Fe 3 

# O 4 

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

# O 3 

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

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

# , converting the material to SO3 which could result in the generation of sulfuric acid mist from the scrubber;

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

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

Application of this technology has not been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high moisture content. Using LTO at a taconite plant would require research, test runs, and extended trials to identify potential issues related to design for high airflows and impacts on plant systems, including the furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of a demonstration project. The timeline required to perform such a demonstration project would likely be two years to develop and agree on the test plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and report on the results. The results would not be available within the time window for establishing emission limits to be incorporated in the state implementation plan (SIP) by December 2007.

Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to learn how to apply a control technology to a completely new and significantly different source type. Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for this application and will not be evaluated further.

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

# control technologies that are available and applicable to the indurating furnace process are identified in Table 5-4. The technical feasibility as determined in Step 2 is also included in Table 5-6.

## Keetac BART Report September 8, 2006

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# 46 Table 5-7 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and Technical Feasibility

Step 1 Step 2

SO 2 

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



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

Low-N 

# O x 

# Burners Y Y N (only applicable to preheat sections) ---

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 --- ---

## Keetac BART Report September 8, 2006

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# 47 5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control

Technologies Table 5-8 describes the expected control efficiency from each of the remaining technically feasible control options as identified in Step 2.

Table 5-8 Indurating Furnace NO x 

# Control Technology Effectiveness



# NO x 

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

Ported Kilns 5%



# 5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results Table 5-9 details the expected costs associated with installation of SCR with conventional reheat and ported kilns.

For SCR, equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S. EPA cost models. SCR capital costs were based on methods in the U.S. EPA Control Cost Manual. For ported kilns, the capital costs were based on Minntac’s budgetary estimate of ported kiln installation on Line 4/5 and scaled to Keetac’s flow rate using the 6/10 power law as shown in the following equation.

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



# Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. EPA models and factors. Operating costs were based on 93% utilization and 8400 operating hours per year. Operating costs of consumable materials, such as electricity, water, and chemicals were

established based on the U.S. EPA control cost manual 27 

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

27 

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

.

## Keetac BART Report September 8, 2006

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# 48 Table 5-9 NO x 

# Control Cost Summary

## Keetac BART Report September 8, 2006

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# 49 Due to space considerations, 60% 28 

# of the total capital investment was included in the costs to account for a retrofit installation. After a tour of the facility and discussions with facility staff, it was determined the space surrounding the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to transport materials to and from the building. Additionally, the structural design of the existing building would not support additional equipment on the roof. Therefore, the cost estimates provide for additional site-work and construction costs to accommodate the new equipment within the facility. A site-specific estimate for site work, foundations, and structural steel was added to arrive at the total retrofit installed cost of the control technology. The site specific estimate was based on Barr’s experience with similar projects. See Appendix B 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 E. This cost-effective threshold is also an indirectmeasure of affordability for the electric utility industry used by U.S. EPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,3000 cost effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for proposing BART in lieu of developing industry and site specific data.

The annualized pollution control cost value was used to determine whether or not additional impacts analyses would be conducted for the technology. If the control cost was less than a screening threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are evaluated. MPCA set the screening level to eliminate technologies from requiring the additional impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant 29



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

28 

# U.S. EPA, CUE Cost Workbook Version 1.0 . Page 2. 29 

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

## Keetac BART Report September 8, 2006

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# 50 The cost of NO X 

# control with either SCR with conventional reheat or ported kilns is below the screening level of $12,000 per ton of pollutant removed. Therefore, these control technologies are carried forward in the BART analysis.

Energy and Environmental Issues The energy and non-air quality impacts for SCR with conventional reheat and Low-NO x 

# burners are presented in Table 5-10.

Table 5-10 NO x 

# Control Technology Impacts Assessment

Control Technology Energy Impacts Other Impacts

SCR with Conventional Reheat • Increased fan sizes due to increased pressure drop

• Natural gas burning to reheat flue gas to reaction temperature • Catalyst disposal

Ported Kilns • None • 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. This section of the report evaluates the visibility impacts of BART NO x 

# control and the resulting degree of visibility improvement.

However, as previously stated, two new scrubbers were installed on the indurating furnace after the BART baseline period and started operation in October 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, the emissions in the post-BART modeling analysis must be adjusted to account for the improved removal efficiency. Therefore, the visibility impacts modeling presented in this section also present the post-baseline (i.e. post-BART) current operations of the facility.

## Keetac BART Report September 8, 2006

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# 51 Predicted 24-Hour Maximum Emission Rates Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should also reflect a maximum 24-hour average project emission rate. In the visibility impacts modeling analysis, the emissions from the indurating furnace was adjusted to account for the new wet scrubber and for the ability of the furnace to burn coal. However, it is important to note that the worst-case SO 2 

# emissions scenario is based on coal burning and the worst-case NO x 

# emissions scenario is based on natural gas burning. Therefore, post-baseline (i.e. post-BART) modeling was conducted for two separate operating scenarios: (1) burning natural gas and (2) burning solid fuel. Emission reductions due to the SCR with standard reheat and ported kilns were based on the current operations.

Table 5-11 provides a summary of the modeled NO X 

# 24-hour maximum emission rates for the postbaseline (i.e. post-BART) operations. The stack parameters (location, height, velocity, and temperature) were assumed to remain unchanged from the baseline modeling.

Post-BART Visibility Impacts Modeling Results Results of the post-BART visibility impacts modeling for current operations are presented in Table 5-12. 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 table 5-12, post-BART modeled visibility improvements are as follows:

• Current Operation:

o Natural Gas Operation: The operation of the new SO 2 

# scrubbers when burning natural gas results in a visibility improvement of 0.032 dV which represents a 3% improvement compared to the baseline. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 118 days.

o Coal Operation: The operation of the new SO 2 

# scrubbers when burning coal results in a visibility improvement of 0.675 dV which represents a 53% improvement compared to the baseline. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 32 days.

## Keetac BART Report September 8, 2006

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# 52 Table 5-11 Post- BART NO X 

# Control - Predicted 24-hour Maximum Emission Rates

## Keetac BART Report September 8, 2006

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# 53 Table 5-12 Post-BART NO X 

# Modeling Scenarios - Visibility Modeling Results

## Keetac BART Report September 8, 2006

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# 54 • Ported Kilns:

o Natural Gas Operation: The operation of a ported kiln when burning natural gas results in a visibility improvement of 0.096 dV which represents an 8% improvement compared to the baseline. This is a 0.064 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 109 days.

o Coal Operation: The operation of a ported kiln when burning coal shows no improvement in NO x 

# emissions compared to the same operating scenario without air injection ports. Therefore, the visibility impact is the same as the current operation when burning coal.

• SCR with Conventional Reheat:

o Natural Gas Operation: The operation of an SCR system with conventional reheat when burning natural gas results in a visibility improvement of 0.911 dV which represents a 73% improvement compared to the baseline. This is a 0.879 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 3 days.

o Coal Operation: The operation of an SCR system with conventional reheat when burning coal results in a visibility improvement of 0.973 dV which represents a 78% improvement compared to the baseline. This is a 0.298 dV improvement compared to current operations when burning coal. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 2 days.

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

## Keetac BART Report September 8, 2006

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# 55 

# 6. Visibility Impacts

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

SO 2 

# and NO x 

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

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

# and NO x 

# controls. In addition, all of the modeling scenarios are also presented in this section. 

# 6.A Post-BART Modeling Scenarios Table 6-1 provides a summary of the modeled SO 2 

# , NO X 

# and PM 10 

# 24-hour maximum emission rates for the post-baseline (i.e. post-BART) operations. All of the modeling scenario results, as presented in sections 5.A.i.e and 5.A.ii.e, of this report, are presented in Table 6-1. In addition, the various

combinations of SO 2 

# controls with NO x 

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

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

• Natural Gas Operation: The operation of the new SO 2 

# scrubbers when burning natural gas results in a visibility improvement of 0.032 dV which represents a 3% improvement compared to the baseline. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 118 days.

## Keetac BART Report September 8, 2006

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# 56 Table 6-1 Post-BART Modeling Scenarios – Predicted 24-hour Maximum Emission Rates

## Keetac BART Report September 8, 2006

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# 57 o Coal Operation: The operation of the new SO 2 

# scrubbers when burning coal results in a visibility improvement of 0.675 dV which represents a 53% improvement compared to the baseline. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 32 days.

• Secondary SO 2 

# Scrubber:

o Natural Gas Operation: The operation of a second SO 2 

# scrubber, in combination with the existing SO 2 

# scrubber, when burning natural gas results in a visibility improvement of 0.056 dV which represents a 5% improvement compared to the baseline. This is a 0.024 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 112 days.

o Coal Operation: The operation of a second SO 2 

# scrubber, in combination with the existing SO 2 

# scrubber, when burning coal results in a visibility improvement of 0.778 dV which represents a 62% improvement compared to the baseline. This is a 0.102 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 19 days.

• Ported Kilns:

o Natural Gas Operation: The operation of a ported kiln when burning natural gas results in a visibility improvement of 0.096 dV which represents an 8% improvement compared to the baseline. This is a 0.064 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 109 days.

o Coal Operation: The operation of a ported kiln when burning coal shows no improvement in NO x 

# emissions compared to the same operating scenario without air injection ports. Therefore, the visibility impact is the same as the current operation when burning coal.

## Keetac BART Report September 8, 2006

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# 58 • SCR with Conventional Reheat:

o Natural Gas Operation: The operation of an SCR system with conventional reheat when burning natural gas results in a visibility improvement of 0.911 dV which represents a 73% improvement compared to the baseline. This is a 0.879 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 3 days.

o Coal Operation: The operation of an SCR system with conventional reheat when burning coal results in a visibility improvement of 0.973 dV which represents a 78% improvement compared to the baseline. However, this is only a 0.298 dV improvement compared to current operations when burning coal. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 2 days.

• Secondary SO 2 

# Scrubber with Ported Kiln

o Natural Gas Operation: The operation of a secondary wet scrubber with a ported kiln when burning natural gas results in a visibility improvement of 0.120 dV which represents a 10% improvement compared to the baseline. This is a 0.088 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 105 days.

o Coal Operation: The operation of a secondary wet scrubber with a ported kiln when burning coal results in a visibility improvement of 0.780 dV which represents an 18% improvement compared to the baseline. However, this is only 0.105 dV improvement compared to current operations when burning coal. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 18 days.

• Secondary SO 2 

# Scrubber with SCR with Conventional Reheat

o Natural Gas Operation: The operation of a secondary wet scrubber with SCR with conventional reheat when burning natural gas results in a visibility improvement of

## Keetac BART Report September 8, 2006

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# 59 0.952 dV which represents a 76% improvement compared to the baseline. This is a 0.920 dV improvement compared to current operations when burning natural gas. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 2 days.

o Coal Operation: The operation of a secondary wet scrubber with SCR with conventional reheat when burning coal results in a visibility improvement of 1.069 dV which represents a 85% improvement compared to the baseline. However, this is only a 0.394 dV improvement compared to current operations when burning coal. In addition, the number of days in which the visibility impacts from the facility exceeded 0.5 dV decreased from 120 days to 0 days.

## Keetac BART Report September 8, 2006

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# 60 Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results

## Keetac BART Report September 8, 2006

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# 61 

# 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.

Keetac operates one indurating furnace which is subject-to-BART:

• Grate Kiln – Indurator Waste Gas, Phase II (EU 030, SV 051)

As presented in section 3 of the report, the PM emissions from the indurating furnace was 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 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 presented in MPCA and U.S. EPA guidance for determining BART, as presented in this report.

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

# , add-on secondary wet scrubber to control

additional SO 2 

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

# CEMS. The secondary wet scrubber, ported kiln, and SCR alternatives were not proposed as BART for the following reasons:

Secondary Wet Scrubber

This technology, in addition to the new wet scrubber, does not provide significant visibility improvement to the Class I areas and is not cost effective at $8870/ton of SO 2 

# removed. In addition it requires additional energy to operate fans and results in additional wastewater that would require treatment and residuals disposal. There are also additional process water volume and quality considerations that would need to be addressed.

Ported Kiln

Converting the kiln to a ported kiln will result in only an estimated 5% decrease in NO x 

# emissions when burning gas. It would not result in emissions reductions when burning solid

## Keetac BART Report September 8, 2006

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# 62 fuel, the primary fuel used by Keetac. Therefore, the technology will not result in any measurable visibility improvement at the Class I areas compared to the current operation. Further, it is not cost effective at an estimated amount of $6,032/ton NO x 

# removed.

SCR Application of SCR is not cost effective at $9514/ton NO x 

# removed. It would not result in significant visibility improvements when burning solid fuel, the primary fuel used by Keetac. It would involve substantial electric use to operate new fans and substantial gas use to reheat the exhaust to temperatures required for the technology to effectively remove NO x 

# . The spent catalyst would create a new solid waste. In addition, ammonia, a visibility impairing pollutant, would be emitted due to ammonia slip from the process and would detrimentally impact the visibility benefit and would potentially cause additional deposition of nitrogen to nearby surface waters.

Based on the consideration of all of the criteria presented in the BART analysis, Keetac proposes the following as BART for SO 2 

# and NO X 

# for the Indurating Furnace:

• BART for SO 2 

# :

o SO 2 

# emissions will be controlled by the new wet scrubbers, which will be operated as required in accordance with provisions of the Taconite MACT and permit 13700063-003.

o SO 2 

# removal efficiency of the wet scrubbers will be maintained at a minimum of 34%; this is based on compliance tests from October 2005 and May 2006 while operating at a pH of 6.5 which is anticipated to be the minimum operating pH, except during periods of startup, shutdown, malfunction, and acid wash.

o Compliance will be initially demonstrated by existing performance test data, as performed in October 2005 and May 2006.

o Continuous compliance will be demonstrated by continuous monitoring of the scrubber water pH, the scrubber water flow rate, and the scrubber pressure drop. These are the same parameters that are required to be monitored by the Taconite MACT and/or permit 13700063-003. The operating limits will be determined

## Keetac BART Report September 8, 2006

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# 63 based on the initial SO 2 

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

• BART for NO x 

# :

o NO x 

# emissions will be controlled by existing combustion controls and fuel blending.

o NO x 

# CEMS will be installed for the purpose of NO x 

# monitoring.

o NO x 

# emission limits will be proposed by the facility 12-months after the

installation of the NO x 

# CEMS to allow the facility sufficient time for monitoring to determine the actual emission rates under a variety of operating 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.

The schedule implementing the SO 2 

# scrubber monitoring program, installing the NO x 

# CEMS, and determining the appropriate NO x 

# emissions limit will be within the 5-year time-frame required for BART implementation. In addition, Keetac 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 NO x 

# emission rates as determined during recent stack testing, the proposed BART controls will result in visibility improvement on the 98 th 

# percentile day of approximately 0.032 deciviews (dV) when burning gas and 0.675 dV when burning coal. These reductions represent visibility improvements of approximately 3% and 54%, respectively, compared to the baseline (pre-BART) operating conditions.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-hrActualEmissions(lb/day)PM10 Max. 24-hr ActualEmissions(lb/day)MACTPM EmissionLimit*(g/dscf)StackNumber Actions Required3.A. Indurating FurnacesEU 030 Grate Kiln - Indurator Waste Gas, Phase II 33,295.2 5,213.4 2,452.1 0.010 SV051M BART Analysis for SO2 + NOx3.B. PM-Only Taconite MACT Emission UnitsEU 001Gyrator Crusher - Primary Crusher No. 1------6.60.008 SV001MNoneEU 002Gyrator Crusher - Primary Crusher No. 2------4.90.008 SV002MNoneEU 003 Conveyor Transfer - Drive house No. 1 Primary Conveyor------46.4 0.008 SV003MNoneEU 004 Conveyor Transfer - Drive house No. 2 Primary Conveyor------7.20.008 SV004MNoneEU 005Conveyor Transfer - Crude Ore Feed------88.4 0.008 SV005MNoneEU 006Conveyor Transfer - Crude Ore Feed------88.4 0.008 SV006MNoneEU 007Conveyor Transfer - Crude Ore Feed------88.4 0.008 SV007MNoneEU 008Conveyor Transfer - Crude Ore Feed------88.4 0.008 SV008MNoneEU 009Conveyor Transfer - Crude Ore Feed------88.4 0.008 SV009MNoneEU 010Conveyor Transfer - Crude Ore Feed------88.4 0.008 SV010MNoneEU 011Conveyor Transfer - Crude Ore Feed------2.90.008 SV011MNoneEU 012Conveyor Transfer - Crude Ore Feed------2.90.008 SV012MNoneEU 013Conveyor Transfer - Crude Ore Feed------2.90.008 SV013MNoneEU 014Conveyor Transfer - Crude Ore Feed------2.90.008 SV014MNoneEU 022Grate Kiln - Grate Discharge, Phase II------23.9 0.008 SV022MNoneEU 024Cooler Dump Zone, Phase II------22.1 0.008 SV024MNoneEU 026Pellet Cooler, Phase II------386.6 0.008 SV026MNoneEU 032Pellet Cooler Product Belts, Phase II------12.2 0.008 SV032MNoneEU 034Pellet Loadout Drive House------66.3 0.008 SV034MNoneEU 037 Pellet Screening - Phase II, Pellet Screening System------9.80.008 SV037MNoneEU 038 Pellet Screening - Phase II, Conveyor Drop------9.80.008 SV038MNone3.C. Sources of fugitive PM that are subject to MACT standardsNONE---------------------3.D. Non-MACT Units and Fugitive Sources (PM only)EU 015Additive Blending, Phase I------0.6--- SV015MNoneEU 016Additive Blending, Phase II------4.4--- SV016MNoneEU 017Addititive Silo, Phase I------4.8--- SV017MNoneEU 018Addititive Silo, Phase II------2.3--- SV018MNoneEU 018Additive Blending------2.3--- SV049MNone3.E. Other Combustion UnitsNONE---------------------* The taconite MACT emission limits are based on EPA Method 5 and include the applicable averaging and grouping provisions, as presented in the regulation.Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions DataEU # EU DescriptionSO2Maximum24-hr EmissionRate (lbs/day)NOxMaximum24-hr EmissionRate (lbs/day)PM2.5Maximum 24-hr EmissionRate (lbs/day)PM10Maximum24-hr EmissionRate (lbs/day) SV #StackEasting(utm)StackNorthing(utm)Height ofOpeningfromGround (ft)BaseElevationofGround(ft)Stacklength,width, orDiameter(ft)FlowRate atexit(acfm)ExitTemp(°F)Basis for SO224-hour ActualEmissionsBasis for NOx24-hour ActualEmissionsBasis forPM2.524-hourActualEmissionsBasis forPM1024-hourActualEmissionsEU 030Grate Kiln -Indurator WasteGas, Phase II7,152 33,288n/a2,452 SV051M 495489 5251028 156 1480 13 848,000 132Stack TestOctober 2005Stack TestJuly 2000n/aStack TestJuly 2000EU 001Gyrator Crusher -Primary CrusherNo. 1n/an/an/a 6.627945205 SV001M 495040.2 5251860.4 63 1390 2.7 19,500 77 n/an/an/aEmissionfactors fromstack testsEU 002Gyrator Crusher -Primary CrusherNo. 2n/an/an/a 4.897315068 SV002M 495002 5251960.9 64.7 1390 2.9 23,700 77 n/an/an/aEmissionfactors fromstack testsEU 003Conveyor Transfer -Drive house No. 1Primary Conveyorn/an/an/a 46.39561644 SV003M 495103.7 5251488.6 115 1500 1.9 10,900 77 n/an/an/aEmissionfactors fromstack testsEU 004Conveyor Transfer -Drive house No. 2Primary Conveyorn/an/an/a 7.21709589 SV004M 495096.1 5251488.6 118 1500 2.3 16,600 77 n/an/an/aEmissionfactors fromstack testsEU 005Conveyor Transfer -Crude Ore Feedn/an/an/a 88.37260274 SV005M 495196.2 5251103.9 62 1480 2.5 11,500 77 n/an/an/aEmissionfactors fromstack testsEU 006Conveyor Transfer -Crude Ore Feedn/an/an/a 88.37260274 SV006M 495195.8 5252644.5 62 1480 2.5 11,500 77 n/an/an/aEmissionfactors fromstack testsEU 007Conveyor Transfer -Crude Ore Feedn/an/an/a 88.37260274 SV007M 495209.2 5252659.1 62 1480 2.5 11,500 77 n/an/an/aEmissionfactors fromstack testsEU 008Conveyor Transfer -Crude Ore Feedn/an/an/a 88.37260274 SV008M 495212.9 5252688.3 62 1480 2.5 11,500 77 n/an/an/aEmissionfactors fromstack testsEU 009Conveyor Transfer -Crude Ore Feedn/an/an/a 88.37260274 SV009M 495183.7 5252705.4 62 1480 2.5 11,500 77 n/an/an/aEmissionfactors fromstack testsEU 010Conveyor Transfer -Crude Ore Feedn/an/an/a 88.37260274 SV010M 495184.1 5251180.7 62 1480 2.5 11,500 77 n/an/an/aEmissionfactors fromstack testsEU 011Conveyor Transfer -Crude Ore Feedn/an/an/a 2.872109589 SV011M 495230 5252739.5 127 1480 1.9 13,400 77 n/an/an/aEmissionfactors fromstack testsEU 012Conveyor Transfer -Crude Ore Feedn/an/an/a 2.872109589 SV012M 495227.6 5252754.1 127 1480 1.9 13,400 77 n/an/an/aEmissionfactors fromstack testsEU 013Conveyor Transfer -Crude Ore Feedn/an/an/a 2.872109589 SV013M 495225.2 5252772.4 127 1480 1.9 13,400 77 n/an/an/aEmissionfactors fromstack testsEU 014Conveyor Transfer -Crude Ore Feedn/an/an/a 2.872109589 SV014M 495222.9 5252869.3 127 1480 1.9 13,400 77 n/an/an/aEmissionfactors fromstack testsEU 022Grate Kiln - GrateDischarge, Phase IIn/an/an/a 23.93424658 SV022M 495403.2 5250986.7 155.5 1480 4.2 27,400 85 n/an/an/aEmissionfactors fromstack testsEU 024Cooler Dump Zone,Phase IIn/an/an/a 22.09315068 SV024M 495410.5 5250930.6 155.5 1480 5.2 59,000 125 n/an/an/aEmissionfactors fromstack testsEU 026Pellet Cooler, PhaseIIn/an/an/a 386.630137 SV026M 495405.6 5250942.8 151 1480 13.5 388,804 975 n/an/an/aEmissionfactors fromstack testsEU 032Pellet CoolerProduct Belts,Phase IIn/an/an/a 12.15123288 SV032M 495410.5 5250942.8 156 1480 5.1 29,350 77 n/an/an/aEmissionfactors fromstack testsEU 034Pellet LoadoutDrive Housen/an/an/a 66.27945205 SV034M 495466.3 5250790.3 44 1480 2.2 11,500 77 n/an/an/aEmissionfactors fromstack testsEU 037Pellet Screening -Phase II, PelletScreening Systemn/an/an/a 9.757808219 SV037M 495437.2 5250887.9 70 1480 5 65,000 120 n/an/an/aEmissionfactors fromstack testsEU 038Pellet Screening -Phase II, ConveyorDropn/an/an/a 9.757808219 SV038M 495457.9 5250883.6 44 1480 1.6 18,780 120 n/an/an/aEmissionfactors fromstack testsEU 015Additive Blending,Phase In/an/an/a 0.621523973 SV015M 495280.2 5251016.1 131 1480 2.2 3,800 77 n/an/an/aEmissionfactors fromstack testsEU 016Additive Blending,Phase IIn/an/an/a 4.350667808 SV016M 495438.6 5251046.3 150 1480 3.1 14,800 77 n/an/an/aEmissionfactors fromstack testsEU 017Addititive Silo,Phase In/an/an/a 4.823145205 SV017M 495354.5 5251016 87 1480 1 3,100 77 n/an/an/aEmissionfactors fromstack testsEU 018Addititive Silo,Phase IIn/an/an/a 2.257643836 SV018M 495464 5251028 89 1480 1 2,300 77 n/an/an/aEmissionfactors fromstack testsEU 018 Additive Blending n/an/an/a 2.257643836 SV049M 495464 5251028 89 1480 1 2,300 77 n/an/an/aEmissionfactors fromstack testsTable 4-2 Baseline Visibility Modeling Results2002200320042002 – 2004 CombinedScenario # SO2NOxClass IArea withGreatestImpactModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasVNP 1.372491.197421.008311.253120Scenario Control Technology

## Table 5-3 SO 2 

## Control Cost Summary



# Control Technology Installed Capital Cost (MM$) Operating Cost

(MM$/yr) Annualized

Pollution Control Cost ($/ton) Incremental

Control Cost ($/ton)

Wet Walled Electrostatic Precipitator (WWESP) (after existing scrubber) $45,081,576 $11,531,318 $15,165 n/a



# Secondary Wet Scrubber (after existing scrubber) $30,203,843 $5,058,352 $8,870 n/aTable 5-5 Post- BART SO2Control - Predicted 24-hour Maximum Emission RatesScenario Control TechnologySO2NOxControlScenario SV #EmissionUnitSO2NOx% ReductionMax 24-hourlbs/day % ReductionMax 24-hourlbs/day1 SV051M EU030Current OperationsBurning Nat Gas(with new Scrubber)Current OperationsBurning Nat Gas(with new Scrubber)Max is stack testinlet with pH 7on scrubber(34% removal)196.7Max NOx onNatural Gasdoesn't change1387.02 SV051M EU030Current OperationsBurning Coal(with new Scrubber)Current OperationsBurning Coal(with new Scrubber)Max is Coalstack test pH 7(34%) with %Sadjustment400.0Max NOx onCoal based onMay 2005 StackTest466.03 SV051MEU030Secondary Wet Scrubber(after existing scrubber)Burning Natural GasCurrent OperationsBurning Nat Gas(with new Scrubber)60%78.7---1387.04 SV051MEU030Secondary Wet Scrubber(after existing scrubber)Burning CoalCurrent OperationsBurning Coal(with new Scrubber)60%160.0Max NOx onCoal based onMay 2005 StackTest466.0Table 5-6 Post-BART SO2Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004 CombinedScenario # SO2NOxClass IArea withGreatestImpactModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasVNP1.372 49 1.197 42 1.008 31 1.253 1201Current OperationsBurning Nat Gas(with new Scrubber)Current OperationsBurning Nat Gas(with new Scrubber)VNP1.337 48 1.18 42 0.986 30 1.221 1182Current OperationsBurning Coal(with new Scrubber)Current OperationsBurning Coal(with new Scrubber)VNP0.642 17 0.534 9 0.447 6 0.578 323Secondary WetScrubber(after existingscrubber)Burning NaturalGasCurrent OperationsBurning Nat Gas(with new Scrubber)VNP1.297 47 1.156 39 0.96 30 1.197 1124Secondary WetScrubber(after existingscrubber)Burning CoalCurrent OperationsBurning Coal(with new Scrubber)VNP0.537 12 0.46 5 0.392 4 0.475 19Scenario Control TechnologyTable 5-11 Post- BART NOXControl - Predicted 24-hour Maximum Emission RatesScenario Control TechnologySO2NOxControlScenario SV #EmissionUnitSO2NOx% ReductionMax 24-hourlbs/day % ReductionMax 24-hourlbs/day1 SV051M EU030Current OperationsBurning Nat Gas(with new Scrubber)Current OperationsBurning Nat Gas(with new Scrubber)Max is stack testinlet with pH 7on scrubber(34% removal)196.7Max NOx onNatural Gasdoesn't change1387.02 SV051M EU030Current OperationsBurning Coal(with new Scrubber)Current OperationsBurning Coal(with new Scrubber)Max is Coalstack test pH 7(34%) with %Sadjustment400.0Max NOx onCoal based onMay 2005 StackTest466.05 SV051M EU030Current OperationsBurning Nat Gas(with new Scrubber)Ported KilnBurning Nat GasMax is stack testinlet with pH 7on scrubber(34% removal)196.75%1317.76 SV051M EU030Current OperationsBurning Coal(with new Scrubber)Ported KilnBurning Coal(No NOx Improvement)Max is Coalstack test pH 7(34%) with %Sadjustment400.0Max NOx onCoal based onMay 2005 StackTest466.09 SV051MEU030Current OperationsBurning Nat Gas(with new Scrubber)SCRWith Conventional ReheatMax is stack testinlet with pH 7 onscrubber(34% removal)196.780%277.410 SV051MEU030Current OperationsBurning Coal(with new Scrubber)SCRWith Conventional ReheatMax is Coalstack test pH 7(34%) with %Sadjustment400.080%93.2

## Table 5-9 NO x 

## Control Cost Summary



# Control Technology Installed Capital Cost (MM$) Operating Cost

(MM$/yr) Annualized

Pollution Control Cost ($/ton) Incremental

Control Cost ($/ton)

Selective Catalytic Reduction with Reheat (SCR) $63,936,099 $31,615,514 $9,514 $9,952



# Ported Kiln $34,450,205 $17,748,523 $6,032 n/aTable 5-12 Post-BART NOx Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004 CombinedScenario # SO2NOxClass IArea withGreatestImpactModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasVNP 1.372 49 1.197 42 1.008 31 1.253 1201Current OperationsBurning Nat Gas(with new Scrubber)Current OperationsBurning Nat Gas(with new Scrubber)VNP 1.337 48 1.18 42 0.986 30 1.221 1182Current OperationsBurning Coal(with new Scrubber)Current OperationsBurning Coal(with new Scrubber)VNP 0.642 17 0.534 9 0.447 6 0.578 325Current OperationsBurning Nat Gas(with new Scrubber)Ported KilnBurning Nat GasVNP 1.281 47 1.118 36 0.941 28 1.157 1096Current OperationsBurning Coal(with new Scrubber)Ported KilnBurning Coal(No NOxImprovement)VNP 0.64 17 0.531 9 0.446 6 0.573 319Current OperationsBurning Nat Gas(with new Scrubber)SCRWith ConventionalReheatVNP 0.385 1 0.321 2 0.275 1 0.342 310Current OperationsBurning Coal(with new Scrubber)SCRWith ConventionalReheatVNP 0.333 1 0.275 1 0.222 0 0.28 2Scenario Control TechnologyTable 6-1 Post-BART Modeling Scenarios – Predicted 24-hour Maximum Emission RatesScenario Control TechnologySO2NOxControlScenario SV #EmissionUnitSO2NOx% ReductionMax 24-hourlbs/day % ReductionMax 24-hourlbs/day0 SV051M EU 030BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural Gasn/a7152.0n/a33288.01 SV051M EU 030Current OperationsBurning Nat Gas(with new Scrubber)Current OperationsBurning Nat Gas(with new Scrubber)Max is stack testinlet with pH 7on scrubber(34% removal)196.7Max NOx onNatural Gasdoesn't change1387.02 SV051M EU 030Current OperationsBurning Coal(with new Scrubber)Current OperationsBurning Coal(with new Scrubber)Max is Coalstack test pH 7(34%) with %Sadjustment400.0Max NOx onCoal based onMay 2005 StackTest466.03 SV051MEU 030Secondary Wet Scrubber(after existing scrubber)Burning Natural GasCurrent OperationsBurning Nat Gas(with new Scrubber)60%78.7---1387.04 SV051MEU 030Secondary Wet Scrubber(after existing scrubber)Burning CoalCurrent OperationsBurning Coal(with new Scrubber)60%160.0Max NOx onCoal based onMay 2005 StackTest466.05 SV051M EU 030Current OperationsBurning Nat Gas(with new Scrubber)Ported KilnBurning Nat GasMax is stack testinlet with pH 7on scrubber(34% removal)196.7 0.11317.76 SV051M EU 030Current OperationsBurning Coal(with new Scrubber)Ported KilnBurning Coal(No NOx Improvement)Max is Coalstack test pH 7(34%) with %Sadjustment400.0Max NOx onCoal based onMay 2005 StackTest466.0Table 6-1 Post-BART Modeling Scenarios – Predicted 24-hour Maximum Emission RatesScenario Control TechnologySO2NOxControlScenario SV #EmissionUnitSO2NOx% ReductionMax 24-hourlbs/day % ReductionMax 24-hourlbs/day7 SV051MEU 030Secondary Wet Scrubber(after existing scrubber)Burning Natural GasPorted KilnBurning Nat Gas60%78.70.11317.78 SV051MEU 030Secondary Wet Scrubber(after existing scrubber)Burning CoalPorted KilnBurning Coal(No NOx Improvement)60%160.0Max NOx onCoal based onMay 2005 StackTest466.09 SV051M EU 030Current OperationsBurning Nat Gas(with new Scrubber)SCRWith Conventional ReheatMax is stack testinlet with pH 7on scrubber(34% removal)196.7 0.8277.410 SV051M EU 030Current OperationsBurning Coal(with new Scrubber)SCRWith Conventional ReheatMax is Coalstack test pH 7(34%) with %Sadjustment400.00.893.211 SV051MEU 030Secondary Wet Scrubber(after existing scrubber)Burning Natural GasSCRWith Conventional ReheatMax is stack testinlet with pH 7 onscrubber(34% removal)196.70.8277.412 SV051MEU 030Secondary Wet Scrubber(after existing scrubber)Burning CoalSCRWith Conventional ReheatMax is Coalstack test pH 7(34%) with %Sadjustment400.00.893.2Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004 CombinedScenario # SO2NOxClass IArea withGreatestImpactModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciview0BaselineIndurating Furnacesburning Natural GasBaselineIndurating Furnacesburning Natural GasVNP 1.372 49 1.197 42 1.008 31 1.253 1201Current OperationsBurning Nat Gas(with new Scrubber)Current OperationsBurning Nat Gas(with new Scrubber)VNP 1.337 48 1.18 42 0.986 30 1.221 1182Current OperationsBurning Coal(with new Scrubber)Current OperationsBurning Coal(with new Scrubber)VNP 0.642 17 0.534 9 0.447 6 0.578 323Secondary WetScrubber(after existingscrubber)Burning Natural GasCurrent OperationsBurning Nat Gas(with new Scrubber)VNP 1.297 47 1.156 39 0.96 30 1.197 1124Secondary WetScrubber(after existingscrubber)Burning CoalCurrent OperationsBurning Coal(with new Scrubber)VNP 0.537 12 0.46 5 0.392 4 0.475 195Current OperationsBurning Nat Gas(with new Scrubber)Ported KilnBurning Nat GasVNP 1.281 47 1.118 36 0.941 28 1.157 1096Current OperationsBurning Coal(with new Scrubber)Ported KilnBurning Coal(No NOxImprovement)VNP 0.64 17 0.531 9 0.446 6 0.573 31Scenario Control TechnologyTable 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004 CombinedScenario # SO2NOxClass IArea withGreatestImpactModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentile Value(deciview)No. of daysexceeding 0.5deciviewScenario Control Technology7Secondary WetScrubber(after existingscrubber)Burning Natural GasPorted KilnBurning Nat GasVNP 1.241 45 1.093 36 0.915 28 1.133 1058Secondary WetScrubber(after existingscrubber)Burning CoalPorted KilnBurning Coal(No NOxImprovement)VNP 0.535 12 0.453 5 0.391 4 0.473 189Current OperationsBurning Nat Gas(with new Scrubber)SCRWith ConventionalReheatVNP 0.385 1 0.321 2 0.275 1 0.342 310Current OperationsBurning Coal(with new Scrubber)SCRWith ConventionalReheatVNP 0.333 1 0.275 1 0.222 0 0.28 211Secondary WetScrubber(after existingscrubber)Burning Natural GasSCRWith ConventionalReheatVNP 0.334 1 0.29 1 0.25 1 0.301 212Secondary WetScrubber(after existingscrubber)Burning CoalSCRWith ConventionalReheatVNP 0.207 0 0.18 0 0.156 0 0.184 0United States Steel: Keewatin Taconite Company9/6/2006BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Cost SummaryNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonSelective CatalyticReduction with Reheat(SCR)80% 830.83323.2 $63,936,099 $31,615,514$9,514$9,952Ported Kilns5% 3946.3207.7 $6,465,590 $610,306$2,938n/aSO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $AnnualizedOperating Cost $/yrPollution ControlCost $/tonIncrementalControl Cost$/tonWet Walled ElectrostaticPrecipitator (WWESP)(after existing scrubber)80% 190.1760.4 $45,081,576 $11,531,318$15,165n/aSecondary Wet Scrubber(after existing scrubber)60% 380.2570.3 $30,203,843 $5,058,352$8,870n/aY:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control CostsCost Summary9/7/2006 Page 1 of 17United States Steel: Keewatin Taconite CompanyBART Report - Attachment A: Emission Control Cost AnalysisTable A.2: Summary of Utility, Chemical and Supply CostsOperating Unit:Indurating FurnaceStudy Year2006Emission Unit NumberEU 030Stack/Vent NumberSV051MItemUnit Cost UnitsCost Year Data SourceNotesOperating Labor61 $/hrPer Kevin Pylka e-mail 07-31-06Maintenance Labor61 $/hrPer Kevin Pylka e-mail 07-31-06Electricity0.051 $/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.htmWater0.28 $/mgal 0.20 1995EPA Air Pollution Control Cost Manual, 6thEd 2002, Section 5 Ch 1, page 1-40Annual Costs for Packed Tower Absorber Example Problem. '95 costadjusted for 3% inflation.Cooling Water0.28 $/mgal 0.23 1999EPA Air Pollution Control Cost Manual, 6thed. Section 3.1 Ch 1Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and3% inflationCompressed Air0.32 $/mscf 0.25 1998EPA Air Pollution Control Cost Manual 6th Ed2002, Section 6 Chapter 1Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%inflationWastewater Disposal Neutralization1.69 $/mgal 1.50 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 2 Chapter 2.5.5.5Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch3 lists $1.30 - $2.15/1,000 galSCR Catalyst141.00$/ft3Cormetech, Inc.Chemicals & SuppliesLime91.62 $/ton91.62 2006Estimate from Cutler-Magney Company.Oxygen40.00 $/ton2006BOC estimate.Ammonia (29% aqua.)0.12 $/lb0.101 2000EPA Air Pollution Control Cost Manual 6th Ed2002, Section 5 Chapter 2, page 2-50Annual costs for a retrofit SCR system example problem. '00 costsadjusted for 3% inflation.Caustic305.96 $/ton280 2003 Hawkins Chemical50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflationOtherSales Tax6.5% %Interest Rate7.00% %EPA Air Pollution Control Cost ManualIntroduction, Chapter 2, section 2.4.2.Social (discount) rate used as a default.Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control CostsUtility Chem$ Data9/7/2006 Page 2 of 17Operating InformationAnnual Op. Hrs8400 HoursUtilization Rate93%Equipment Life20 yrsEngineering EstimateStandardized Flow RateSV051M704,757 scfm @ 32o FCalculated.TemperatureSV051M132 Deg FBART spreadsheet.Moisture ContentSV051M16.5%Per Kevin Pylka e-mail 07-31-06Actual Flow RateSV051M848,000 acfmBART spreadsheet.Standardized Flow RateSV051M756,324 scfm @ 68o FCalculated.Dry Std Flow RateSV051M631,531 dscfm @ 68o FCalculated.Max Emis1Projected Futurelb/hr ton/yearPollutantLb/Hr Actuals4(tpy)ppmv ppmvNitrous Oxides (NOx)SV051M1397.04,154.0 309 209.4with 100% coal2466.0with 100% natural gas31270.0Enter percent coal burned40%Enter percent natural gas burned60%1) Based on Oct '05 stack test with 10% factor added.2) Based on Jun 2006 stack test3) Based on Oct 2005 stack test4) Based on percent of each type of fuel burned, and max lb/hr emissions in cells C122 and C123.Max Emis1Projected FutureSulfur Dioxides (SO2)Lb/Hr Actuals2(tpy)SV051M400.0 950.5 63 34.41) Max emissions based on recent stack test data, but assumed to use a coal with 1% Sulfur instead of 0.47%2) Projected future actuals are based on the permit limit of 217 lb/hr.Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control CostsUtility Chem$ Data9/7/2006 Page 3 of 17

## United States Steel: Keewatin Taconite Company

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

## Control - Selective Catalytic Reduction with Reheat

Operating Unit: Indurating Furnace

Emission Unit Number EU 030 Stack/Vent Number SV051M Design Capacity 350 mmbtu/hr Standardized Flow Rate 704,757 scfm @ 32o F Expected Utilization Rate 93% Temperature 132 Deg F Expected Annual Hours of Operation 8,400 Hours Moisture Content 16.5% Annual Interest Rate 7.0% Actual Flow Rate 848,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 756,324 scfm @ 68o F Dry Std Flow Rate 631,531 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 25,614,464 Purchased Equipment Total SCR Only 27,279,404 SCR + Reheat 28,192,467

Total Capital Investment (TCI) = DC + IC SCR + Reheat 63,936,099

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 23,952,985 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,687,489 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 31,615,514



### 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) 1,397.0 4,154.0 80% 830.8 3,323.2 9,514

Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 For Calculation purposes, duty reflects increased flow rate, not actual duty. 3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43 5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35 6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24 7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31 8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53 9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48 10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46 11 CUECost Workbook Version 1.0, USEPA Document Page 2

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## United States Steel: Keewatin Taconite Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS Direct Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 25,614,464 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,664,940 Freight 5% of control device cost (A) NA Purchased Equipment Total 27,279,404

Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 10% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 10% of purchased equip cost (A) 2,643,899

Project Contingeny (C) 15% of (A + B) 4,488,495

Total Plant Cost (D) A + B + C 34,411,798

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)) 688,236

Inventory Capital Reagent Vol * $/gal 66,258

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 35,166,291

Retrofit factor (11) 60% of TCI 21,099,775 Site preparation 1,400,000 Structural Steel 4,800,000

Total Capital Investment Retrofit Installed 62,466,066



### OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 8400 hr/yr 128,100 Supervisor 15% 15% of Operator Costs 19,215 Maintenance Maintenance Total 1.50 % of Total Capital Investment 527,494 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,640 kW-hr, 8400 hr/yr, 93% utilization 653,432 SCR Catalyst 64.71 Catalyst Replacement 507,499 Ammonia 0.12 $/lb, 1,952 lb/hr, 8400 hr/yr, 93% utilization 1,839,424 Total Annual Direct Operating Costs 3,675,165

Indirect Operating Costs Overhead 60% of total labor and material costs 101,433 Administration (2% total capital costs) 2% of total capital costs (TCI) 703,326 Property tax (1% total capital costs) 1% of total capital costs (TCI) 351,663 Insurance (1% total capital costs) 1% of total capital costs (TCI) 351,663 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,896,355 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 7,404,440

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,079,604

See Summary page for notes and assumptions

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## United States Steel: Keewatin Taconite Company

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

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

Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. #1 2708 ft 3 Cormetech, Inc. FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 756,324 scfm Vol #2 11571.3 ft 3 Amount Required 11,571 f t 3 Catalyst Cost 1,631,558 Y catalyst life factor 3 Years Annualized Cost 507,499

Equivalent Duty 4,119 Plant Cap kW A 422,471 Est power platn eff 35% Unc Nox lb/mmBtu B 0.35 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 422,471 Capital Cost $/kW D $60.63 $25,614,463.64 Total SCR Equipment Uncontrolled Nox t/y 1,397.0 Fixed O&M E $169,055.46 Annual Operating Hrs 8000 Variable O&M F $719,855.06 Uncontrolled Nox lb/mmBtu 0.354 Ann Cap Factor G 0.82 Heat Input mmBtu/hr H 6,000 SCR Capital Cost

Electrical Use Duty 4,119 MMBtu/hr kW NOx Cont Eff 80% Power 1,640.1 NOx in 0.35 lb/MMBtu n catalyst layers 4 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O T otal 1640.1

Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 566 lb/hr Neat 260.8 gal/hr 29% solution Volume 14 day inventory 87,637 gal $66,258 Inventory Cost 1952 lb/hr

Design Basis Max Emis Control Eff (%) lb/MMBtu 80% Nitrous Oxides (NOx) 0.354

Actual 108,262 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu Adjusted Duty 4,119 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,400 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 2,100 128,100 $/Hr, 2.0 hr/8 hr shift, 8400 hr/yr Supervisor 15% of Op. NA 19,215 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 527,494 % 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 1640.1 kW-hr 12,812,399 653,432 $/kwh, 1,640 kW-hr, 8400 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 507,499 Catalyst Replacement Ammonia 0.12 $/lb 1952 lb/hr 15,252,365 1,839,424 $/lb, 1,952 lb/hr, 8400 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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## United States Steel: Keewatin Taconite Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3: NO x 

## Control - Cost to Reheat Flue Gas (Thermal Oxidizer)

Operating Unit: Indurating Furnace

Emission Unit Number EU 030 Stack/Vent Number SV051M Chemical Engineering Standardized Flow Rate 704,757 scfm @ 32o F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 132 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,400 Hours Moisture Content 16.5% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 848,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 756,324 scfm @ 68o F Dry Std Flow Rate 631,531 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 751,493 Purchased Equipment Total (B) 22% of control device cost (A) 913,064

Installation - Standard Costs 30% of purchased equip cost (B) 273,919 Installation - Site Specific Costs NA Installation Total 273,919 Total Direct Capital Cost, DC 1,186,983 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 283,050 Total Capital Investment (TCI) = DC + IC 1,470,033

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 20,277,820 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 258,089 Total Annual Cost (Annualized Capital Cost + Operating Cost) 20,535,909

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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## United States Steel: Keewatin Taconite Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3: NOx Control - Cost to Reheat Flue Gas (Thermal Oxidizer)

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 751,493 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 75,149 MN Sales Taxes 6.5% of control device cost (A) 48,847 Freight 5% of control device cost (A) 37,575 Purchased Equipment Total (B) 22% 913,064

Installation Foundations & supports 8% of purchased equip cost (B) 73,045 Handling & erection 14% of purchased equip cost (B) 127,829 Electrical 4% of purchased equip cost (B) 36,523 Piping 2% of purchased equip cost (B) 18,261 Insulation 1% of purchased equip cost (B) 9,131 Painting 1% of purchased equip cost (B) 9,131 Installation Subtotal Standard Expenses 30% 273,919

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 273,919 Total Direct Capital Cost, DC 1,186,983

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 91,306 Construction & field expenses 5% of purchased equip cost (B) 45,653 Contractor fees 10% of purchased equip cost (B) 91,306 Start-up 2% of purchased equip cost (B) 18,261 Performance test 1% of purchased equip cost (B) 9,131 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 27,392 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 283,050

Total Capital Investment (TCI) = DC + IC 1,470,033

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,470,033



### OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 8400 hr/yr 32,025 Supervisor 15% 15% of Operator Costs 4,804 Maintenance Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 8400 hr/yr 32,025 Maintenance Materials 100% of maintenance labor costs 32,025 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3,142 kW-hr, 8400 hr/yr, 93% utilization 1,251,747 Natural Gas 9.26 $/mscf, 4,361 scfm, 8400 hr/yr, 93% utilization 18,925,194

Total Annual Direct Operating Costs 20,277,820

Indirect Operating Costs Overhead 60% of total labor and material costs 60,527 Administration (2% total capital costs) 2% of total capital costs (TCI) 29,401 Property tax (1% total capital costs) 1% of total capital costs (TCI) 14,700 Insurance (1% total capital costs) 1% of total capital costs (TCI) 14,700 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 138,761 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 258,089

Total Annual Cost (Annualized Capital Cost + Operating Cost) 20,535,909

See Summary page for notes and assumptions

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## United States Steel: Keewatin Taconite Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3: NOx Control - Cost to Reheat Flue Gas (Thermal Oxidizer)

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

Replacement Catalyst: Catalyst Equipment Life 3 years CRF 0.3811 Rep part cost per unit 0 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Electrical Use
Flow acfm **∆** P in H2O Efficiency Hp kW Blower, Thermal 848,000 19 0.6 3,141.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 848,000 23 0.6 3,803.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 3141.8

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,400 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 525 32,025 $/Hr, 0.5 hr/8 hr shift, 8400 hr/yr Supervisor 15% of Op. NA 4,804 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 525 32,025 $/Hr, 0.5 hr/8 hr shift, 8400 hr/yr Maint Mtls 100 % of Maintenance Labor NA 32,025 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 3141.8 kW-hr 24,544,054 1,251,747 $/kwh, 3,142 kW-hr, 8400 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 4,361 scfm 2,044,309 18,925,194 $/mscf, 4,361 scfm, 8400 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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## United States Steel: Keewatin Taconite Company BART Report - Attachment A: Emission Control Cost Analysis Table A.3: NOx Control - Cost to Reheat Flue Gas (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 T wi 132 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 565 Deg F - Temperature of waste gas out of heat recovery

T fo 317 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 756,324 scfm - Flow of waste gas

Q af 4,361 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 760,686 scfm Flue Gas Cost in 1989 $'s $630,284 Current Cost Using CHE Plant Cost Index $751,493 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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## United States Steel: Keewatin Taconite Company

BART Report - Attachment A: Emission Control Cost Analysis Table A.4: NO x 

## Control - Ported Kilns

Operating Unit: Indurating Furnace

Emission Unit Number EU 030 Stack/Vent Number SV051M Design Capacity 350 mmbtu/hr Standardized Flow Rate 704,757 scfm @ 32o F Expected Utilization Rate 93% Temperature 132 Deg F Expected Annual Hours of Operation 8,400 Hours Moisture Content 16.5% Annual Interest Rate 7.0% Actual Flow Rate 848,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 756,324 scfm @ 68o F Dry Std Flow Rate 631,531 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs (1) 

### Minntac Line 4/5 Budget Estimate = 5,000,000 $ Total Capital Investment (TCI) = DC + IC 6,465,590 Minntac Line 4/5 volumetric flow = 650,000 acfm Operating Costs (2) 

### Keetac volumetric flow = 848,000 acfm Total Annual Cost (Annualized Capital Cost) 610,306 Use "6/10 Rule" to calculate Keetac Cost = 6,465,590 $

Capital Recovery Factor

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944 Capital Recovery Cost 610,306



### Emission Control Cost Calculation Max Emis Annual Cont Eff (3) 

### Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,397.0 4,154.0 5% 3946.3 207.7 2,938

Notes & Assumptions 1 Capital costs based on Minntac Line 4/5 Budget Estimate and scaled using 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."

### United States Steel: Keewatin Taconite Company

BART Report - Attachment A: Emission Control Cost Analysis Table A.5: SO 2 

### Control - Wet Walled Electrostatic Precipitator

Operating Unit: Indurating Furnace

Emission Unit Number EU 030 Stack/Vent Number SV051M Standardized Flow Rate 704,757 scfm @ 32o F Expected Utilization Rate 93% Temperature 132 Deg F Expected Annual Hours of Operation 8,400 Hours Moisture Content 16.5% Annual Interest Rate 7.0% Actual Flow Rate 848,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 756,324 scfm @ 68o F Dry Std Flow Rate 631,531 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 8,928,933 Purchased Equipment Total (B) 22% of control device cost (A) 10,848,654

Installation - Standard Costs 67% of purchased equip cost (B) 7,268,598 Installation - Site Specific Costs 6,200,000 Installation Total 7,268,598 Total Direct Capital Cost, DC 18,117,252 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 6,183,733 Total Capital Investment (TCI) = DC + IC 45,081,576

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 6,152,007 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,379,312 Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,531,318

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) 1,397.0 4,154.0 0% 4154.0

- NA Sulfur Dioxide (SO 2 ) 400.0 950.5 80% 190.1 760.4 15,165

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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### United States Steel: Keewatin Taconite Company

BART Report - Attachment A: Emission Control Cost Analysis Table A.5: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 8,928,933 Instrumentation 10% of control device cost (A) 892,893 MN Sales Taxes 6.5% of control device cost (A) 580,381 Freight 5% of control device cost (A) 446,447 Purchased Equipment Total (B) 22% 10,848,654

Installation Foundations & supports 4% of purchased equip cost (B) 433,946 Handling & erection 50% of purchased equip cost (B) 5,424,327 Electrical 8% of purchased equip cost (B) 867,892 Piping 1% of purchased equip cost (B) 108,487 Insulation 2% of purchased equip cost (B) 216,973 Painting 2% of purchased equip cost (B) 216,973 Installation Subtotal Standard Expenses 67% 7,268,598

Total Direct Capital Cost, DC 18,117,252

Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 2,169,731 Construction & field expenses 20% of purchased equip cost (B) 2,169,731 Contractor fees 10% of purchased equip cost (B) 1,084,865 Start-up 1% of purchased equip cost (B) 108,487 Performance test 1% of purchased equip cost (B) 108,487 Model Studies 2% of purchased equip cost (B) 216,973 Contingencies 3% of purchased equip cost (B) 325,460 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 6,183,733

Total Capital Investment (TCI) = DC + IC 24,300,985

Retrofit multiplier 3 60% of TCI 14,580,591 Site preparation 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 45,081,576

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 8400 hr/yr 128,100 Supervisor 15% 15% of Operator Costs 19,215 Maintenance Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 8400 hr/yr 16,546 Maintenance Materials 1.00 % of Maintenance Labor 89,289 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,004 kW-hr, 8400 hr/yr, 93% utilization 798,356 Water 0.28 $/mgal, 4,240 gpm, 8400 hr/yr, 93% utilization 550,198 WW Treat Neutralization 1.69 $/mgal, 4,240 gpm, 8400 hr/yr, 93% utilization 3,355,208 Reagent 305.96 $/ton, 1,000 lb/hr, 8400 hr/yr, 93% utilization 1,195,094 Total Annual Direct Operating Costs 6,152,007

Indirect Operating Costs Overhead 60% of total labor and material costs 151,890 Administration (2% total capital costs) 2% of total capital costs (TCI) 486,020 Property tax (1% total capital costs) 1% of total capital costs (TCI) 243,010 Insurance (1% total capital costs) 1% of total capital costs (TCI) 243,010 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 4,255,382 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,379,312

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,531,318

See summary page for notes and assumptions

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### United States Steel: Keewatin Taconite Company

BART Report - Attachment A: Emission Control Cost Analysis Table A.5: 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 848,000 10 1,534.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 79.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 200,562 389.1 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 2,003.8

Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm 4240.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr Reagent Use 2.50 lb NaOH/lb SO2 1000.00 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,400 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 2,100 128,100 $/Hr, 2.0 hr/8 hr shift, 8400 hr/yr Supervisor 15% of Op. NA 19,215 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 15.0 hr/wk 660 16,546 $/Hr, 15.0 hr/wk, 8400 hr/yr Maint Mtls 1 % of Purchase Cost NA 89,289 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1 Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 2003.8 kW-hr 15,654,040 798,356 $/kwh, 2,004 kW-hr, 8400 hr/yr, 93% utilization Water 0.28 $/mgal 4,240.0 gpm 1,987,373 550,198 $/mgal, 4,240 gpm, 8400 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 4,240.0 gpm 1,987,373 3,355,208 $/mgal, 4,240 gpm, 8400 hr/yr, 93% utilization Reagent 305.96 $/ton 1,000.0 lb/hr 3,906 1,195,094 $/ton, 1,000 lb/hr, 8400 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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### United States Steel: Keewatin Taconite Company BART Report - Attachment A: Emission Control Cost Analysis Table A.6: SO 2 

### Control - Wet Scrubber

Operating Unit: Indurating Furnace

Emission Unit Number EU 030 Stack/Vent Number SV051M Standardized Flow Rate 704,757 scfm @ 32o F Expected Utilization Rate 93% Temperature 132 Deg F Expected Annual Hours of Operation 8,400 Hours Moisture Content 16.5% Annual Interest Rate 7.0% Actual Flow Rate 848,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 756,324 scfm @ 68o F Dry Std Flow Rate 631,531 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 6,173,828 Purchased Equipment Total (B) 22% of control device cost (A) 7,501,201

Installation - Standard Costs 85% of purchased equip cost (B) 6,376,021 Installation - Site Specific Costs 6,200,000 Installation Total 6,376,021 Total Direct Capital Cost, DC 13,877,222 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1,125,180 Total Capital Investment (TCI) = DC + IC 30,203,843

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,546,699 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,511,652 Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,058,352

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) 1,397.0 4,154.0 0% 4154.0

- NA Sulfur Dioxide (SO 2 ) 400.0 950.5 60% 380.2 570.3 8,870

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

EU030 Wet Scrubber

### United States Steel: Keewatin Taconite Company BART Report - Attachment A: Emission Control Cost Analysis Table A.6: SO2 Control - Wet Scrubber

CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 6,173,828 Instrumentation 10% of control device cost (A) 617,383 MN Sales Taxes 7% of control device cost (A) 401,299 Freight 5% of control device cost (A) 308,691 Purchased Equipment Total (B) 22% 7,501,201

Installation Foundations & supports 12% of purchased equip cost (B) 900,144 Handling & erection 40% of purchased equip cost (B) 3,000,480 Electrical 1% of purchased equip cost (B) 75,012 Piping 30% of purchased equip cost (B) 2,250,360 Insulation 1% of purchased equip cost (B) 75,012 Painting 1% of purchased equip cost (B) 75,012 Installation Subtotal Standard Expenses 85% 6,376,021

Total Direct Capital Cost, DC 13,877,222

Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 375,060 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 375,060 Start-up 1% of purchased equip cost (B) 75,012 Performance test 1% of purchased equip cost (B) 75,012 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 225,036 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1,125,180

Total Capital Investment (TCI) = DC + IC 15,002,402 9,001,441 Retrofit multiplier 5 60% of TCI Site preparation 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 30,203,843

OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 8400 hr/yr 32,025 Supervisor 15% 15% of Operator Costs 4,804 Maintenance Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 8400 hr/yr 32,025 Maintenance Materials 100% of maintenance labor costs 32,025 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,744 kW-hr, 8400 hr/yr, 93% utilization 694,798 Water 0.28 $/kgal, 796 gpm, 8400 hr/yr, 93% utilization 103,252 WW Treat Neutralization 1.69 $/kgal, 644 gpm, 8400 hr/yr, 93% utilization 509,992 Lime 91.62 $/ton, 385 lb/hr, 8400 hr/yr, 93% utilization 137,779 Total Annual Direct Operating Costs 1,546,699

Indirect Operating Costs Overhead 60% of total labor and material costs 60,527 Administration (2% total capital costs) 2% of total capital costs (TCI) 300,048 Property tax (1% total capital costs) 1% of total capital costs (TCI) 150,024 Insurance (1% total capital costs) 1% of total capital costs (TCI) 150,024 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,851,029 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,511,652

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,058,352

See Summary page for notes and assumptions

EU030 Wet Scrubber

### United States Steel: Keewatin Taconite Company BART Report - Attachment A: Emission Control Cost Analysis Table A.6: 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 848,000 8.55 0.7

- 1,211.9 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 32,224 gpm 1 60 0.7

- 519.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 796 gpm 1 60 0.7

- 12.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total 1743.9

Reagent Use & Other Operating Costs Caustic Use 400.00 lb/hr SO2 2.50 lb NaOH/lb SO2 1000.00 lb/hr Caustic Lime Use 400.00 lb/hr SO2 0.96 lb Lime/lb SO2 385.00 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 32,224 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 796 gpm Evaporation Loss 4 = 151.21 gpm

Operating Cost Calculations Annual hours of operation: 8,400 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 525 32,025 $/Hr, 0.5 hr/8 hr shift, 8400 hr/yr Supervisor 15% of Op. NA 4,804 15% of Operator Costs Maintenance Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 525 32,025 $/Hr, 0.5 hr/8 hr shift, 8400 hr/yr Maint Mtls 100 % of Maintenance Labor NA 32,025 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.051 $/kwh 1743.9 kW-hr 13,623,492 694,798 $/kwh, 1,744 kW-hr, 8400 hr/yr, 93% utilization Water 0.28 $/kgal 795.7 gpm 372,956 103,252 $/kgal, 796 gpm, 8400 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/kgal 644.5 gpm 302,081 509,992 $/kgal, 644 gpm, 8400 hr/yr, 93% utilization Lime 91.6 $/ton 385.0 lb/hr 1,504 137,779 $/ton, 385 lb/hr, 8400 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

EU030 Wet Scrubber

# Memorandum

To: 

# Margaret McCourtney
From: 

# Andrew Skoglund Subject: 

# Revisions per your comments

Date: 

# May 16, 2006 Project: 

# Taconite Industry BART Clients

c: 

# Mary Jean Fenske, Barr Taconite BART Project Team, Taconite BART Industry Reps.

Attached is a revised version of our proposed changes to the BART-analysis modeling protocol. They are set up in the format described in Appendix G to the modeling protocol. The proposed OZONE.DAT files and a figure depicting the proposed modeling domain are also included, as requested.

The PSD modeling protocols referenced for the CALMET parameters are based on PSD modeling protocols submitted for Mesabi Nugget LLC, Northshore Mining Line 5 Restart, and Minnesota Steel Industries LLC. Each of these facilities has submitted a modeling protocol using MM4/MM5 data with observations for review. The values noted are representative of those that were used after receiving comment from the FLMs. The Minnesota Steel Industries modeling protocol was submitted in May 2005, with FLM response on June 14, 2005. FLMs approved of the submitted values.

The comments section regarding receptors has been revised to indicate that we will be using a subset of the original MPCA receptor group, using only BWCA and Voyageurs receptors.

Thank you,

Andrew J. Skoglund Barr Engineering Co. (952) 832 - 2685 askoglund@barr.com

Barr Engineering Company Appendix B 4700 West 77th Street • Minneapolis, MN 55435-4803 Phone: 952-832-2600 • Fax: 952-832-2601 • www.barr.com An EEO Employer



## Minneapolis, MN • Hibbing, MN • Duluth, MN • Ann Arbor, MI • Jefferson City, MO

# ! ; NBarr Footer: Date: 6/3/2004 4:10:56 PM File: C:\Temp\Test.mxd User: bal


## 0 100 Kilometers



# MODELING DOMAIN Taconite BART Modeling Taconite Industry Group Minnesota 0 100 Miles 

# Legend

Modeling Domain 

# Class I Area

BWCA VoyageursTERRELVariableDescriptionValueDefaultCommentsGTOPO30 GTOPO 30-sec data- n/a 1 degree DEM files will be usedXREFKM Reference point coordinates for grid168 n/aYREFKM Reference point coordinates for grid720 n/aNX Number of X grid cells40 n/aNYNumber of Y grid cells30n/aCTGPROCVariableDescriptionValueDefaultCommentsXREFKM Reference point coordinates for grid168 n/aYREFKM Reference point coordinates for grid720 n/aNX Number of X grid cells40 n/aNYNumber of Y grid cells30n/aCALMETVariableDescriptionValueDefaultCommentsNUSTA Number of upper air stations4 14898, 14918, 94983, 4837NX Number of X grid cells40 n/aNY Number of Y grid cells30 n/aXORIGKM Reference point coordinates for grid168 n/aYORIGKM Reference point coordinates for grid720 n/aNOOBS No Observation Mode0 Y Include Surface, Upper Air and Precipitation ObservationsNSSTA Number of Surface Stations74 n/a 74 surface weather stationsNPSTA Number of Precipitation Stations68 n/a 68 precipitation stationsRMAX2 Maximum radius of influence over land aloft50 n/a Similar to PSD with ObservationsRMAX3 Maximum radius of influence over water500 n/a Similar to PSD with ObservationsR1 Relative weighting of the first guess field and observations in the surface layer (km) 10 n/a Similar to PSD with ObservationsR2 Relative weighting of the first guess field and observations in the layers aloft (km)20 n/a Similar to PSD with ObservationsISURFT Surface met. Stations to use for the surface temperature- n/a Hibbing Met stationIUPT Upper air station to use for the domain scale lapse rate- n/a International Falls Upper Air stationITPROG 3D temperature from observations or from prognostic data?0 Y Inclusion of Surface and Upper AirTRADKM Radius of influence for temperature interpolation500 Y Similar to PSD with ObservationsJWAT1 Beginning land use category for temperature interpolation over water99 n/a CALMET may fail when using 55 with no overwater dataJWAT2 Ending land use category for temperature interpolation over water99 n/a CALMET may fail when using 55 with no overwater dataSIGMAPRadius of influence (km)100YPrecipitation Observations are includedInput Group 0bInput Group 2Input Group 2Input Group 2Input Group 4Input Group 5Input Group 6CALPUFFVariableDescriptionValueDefaultCommentsNX Number of X grid cells in met grid40 n/aNY Number of Y grid cells in met grid30 n/aXORIGKM Reference point coordinates for met grid168 n/aYORIGKM Reference point coordinates for met grid720 n/aIBCOMP X index of LL corner1 n/aJBCOMP Y index of LL corner1 n/aIECOMP X index of UR corner40 n/aJECOMP Y index of UR corner30 n/aMOZ Ozone data input option1 N OZONE.DAT from MN, WI, and MI observation stationsNRECNumber of non-gridded receptors1222n/aUsing only BWCA and Voyageurs from MPCA protocolInput Group 11Input Group 17Input Group 4N

Barr Footer: Date: 7/5/2006 1:45:22 PM File: I:\projects\23\00\Minntac.mxd User: ams1000100MetersKeetac Aerial Photo

# Appendix C

1. CALPUFF Modeling System

The CALPUFF Modeling System is the required model for determining visual impacts at long distances from sources. This model was used in accordance with the guidelines found in the Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota, Final 1 

# , with the modifications found in Appendix B.

The CALPUFF system consists of three main components (CALMET, CALPUFF and CALPOST) and a number of pre-processing programs. These pre-processing programs are designed to prepare available meteorological and geophysical data for input into CALMET. Each of these modeling components are

described below:

• CALMET is a meteorological model that develops hourly wind and temperature fields on a threedimensional gridded modeling domain. Associated two-dimensional fields such as mixing heights, terrain elevations, land use categories and dispersion properties are also included in the file produced by CALMET.

• CALPUFF is a transport and dispersion model that follows the “puffs” of material emitted from one or more sources as they travel downwind. CALPUFF simulates dispersion and chemical transformations as each puff moves away from the source, using the multi-dimensional grids generated by CALMET.

• CALPUFF produces an output file containing hourly concentrations of pollutants which are processed by CALPOST to yield estimates of ambient air extinction coefficients and related measures of visibility impairment at selected averaging times and locations.

Lambert conformal coordinates (LCC) were used in the modeling. To accommodate this coordinate system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets and overcome other size limitations, CALPUFF was recompiled with several size parameters increased.

1 

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

# CALMET

Three years (2002-2004) of MM5 prognostic mesoscale meteorological data, surface weather data, precipitation data, and upper air data were used to generate the CALMET data set for use in the CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells (north-south) with a grid spacing of 12 km. This grid encompasses the facility sources, the BWCAW and Voyageurs National Park. USGS digital elevation maps (DEMs) and land use land cover (LULC) files required by CALMET were obtained from the MPCA.



# CALPUFF

CALPUFF model input files were set up for each year of CALMET data. Model parameters were set to the values specified in the revised modeling protocol (Appendix B).

The CALPUFF modeling considered the emission of SO2, NOx, PM10 (coarse particulate matter, 2.5μ to 10μ), and PM2.5 (fine particulate matter, under 2.5μ).

The CALPUFF modeling also tracked SO4, NO3, and HNO3, which are generated by the chemical transformation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates of transformation. The MESOPUFF-generated transformation rates are a function of the background ozone and ammonia concentrations, the former set by observations, the latter using monthly average values provided by MPCA.

The CALPUFF modeling used the receptors for the Boundary Water Canoe Area Wilderness and Voyageurs National Park provided by the MPCA in the original subject-to-BART modeling files.



# CALPOST

CALPOST converted the hourly concentration and monthly average relative humidity files generated by CALPUFF into 24-hour time-averaged extinction coefficients. These emissions-based extinction coefficients were compared to the 20% best days background extinction coefficients designated in the modeling protocol.

# 2. Visibility Impacts Analysis

As indicated in EPA’s final BART guidance 2 

# , states are required to consider the degree of visibility improvement resulting from the retrofit technology in combination with other factors, such as economics and technical feasibility, when determining BART for an individual source.

The CALPUFF program models how a pollutant contributes to visibility impairment with consideration for the background atmospheric ammonia, ozone and meteorological data. Additionally, the interactions between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part in predicting impairment. It is therefore important to take a multi-pollutant approach when assessing visibility impacts.



# Assessing Visibility Impairment

The visibility impairment contribution for different emission rate scenarios can be determined using the CALMET, CALPUFF, and CALPOST modeling templates provided by the Minnesota Pollution Control Agency (MPCA). The Minnesota BART modeling protocol 3 

# describes the CALPUFF model inputs including the meteorological data set and background atmospheric ammonia and ozone concentrations along with the functions of the CALPOST post processing. There are two criteria with which to assess the expected post-BART visibility improvement: the 98th percentile delta deciview and the number of days on which a source exceeds an impairment threshold.

As defined by federal guidance 4 

# a source "contributes to visibility impairment” if the 98th percentile of any year’s modeling results meets or exceeds the threshold of five-tenths of a deciview (dV) at a federally protected Class I area receptor. The pre-BART evaluation of this criterion conducted by the Minnesota Pollution Control Agency identified this facility as having BART eligible source(s) 5 

# that could cause or contribute to visibility impairment at Minnesota Class I areas. In addition to establishing whether or not a source contributes to impairment on the 98th percentile, the severity of the visibility impairment contribution or reasonably attributed visibility impairment can be gauged by assessing the number of days
on which a source exceeds 0.5 dV.

2 

# 40 CFR 51, Appendix Y. 3 

# MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota. 4 

# 40 CFR 51, Appendix Y. 5 

# MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota.

# Predicting 24-Hour Maximum Emission Rates

Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for preBART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should reflect a maximum 24-hour average basis.

Table 4-1 & Table 6-2 within this report describe the pre and post-BART model input parameters, respectively.



# Modeled Results

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for the predicted post-BART emission scenario(s). Results for the 98th percentile and number of days above 0.5 dV at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are
included in Table 6-3.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 PrincipleCombustion Controls1 Overfire Air (OFA) Y N --- ------xNOx formation front is not stationary inan indurating furnaceCombustion air is separated into primary and secondary flow sections toachieve complete burnout and to encourage the formation of N2ratherthan NOx2External Flue GasRecirculation (EFGR)Y Y N ------xxMixes flue gas with combustion air which reduces oxygen content andtherefore reduces flame temperature3 Low-NOx BurnersYYY(preheatburners)Y(preheatburners)10-20%x x xHigher control efficiency at the burner,but the listed control efficiency is forthe entire furnace.Burners are designed to reduce NOx formation through restriction ofoxygen, flame temperature, and/or residence time4Induced Flue GasRecirculation BurnersYYN------x x xNeed to be upfired. Need convectiveloop to get gas recirculatedDraws flue gas to dilute the fuel in order to reduce the flame temperature5 Low Excess AirYN---------xNeed high O2for process requirementsand product qualityReduces oxygen content in flue gas and reduces flame temperature6Burners out of Service(BOOS)YN---------xNeed capacity of all burners for worstcase scenarioShut off the fuel flow from one burner or more to create fuel rich and fuellean zones7 Fuel BiasingYN---------xPower plant technologyCombustion is staged by diverting fuel from the upper level burners to thelower ones or from the center to the side burners to create fuel-rich andfuel-lean zones8 ReburningYN---------xKiln configuration not correct for thistechnology.Part of the total fuel heat input is injected into the furnace in a regionabove the primary (main burners) flames to create a reducing atmosphere(re-burn zone), where hydrocarbon radicals react with NOx to produceelemental nitrogen9 Load ReductionN------------xPower plant technology -productdemand side solutionThis is a strategy to reduce load on a power plant by reducing theelectrical demand throught efficiency projects.10 Energy Efficiency Projects YYY(for largeprojects likeheat-recoup)Y(for largeprojects likeheat-recoup)Site-specificxdecrease amount of fuel required to make an acceptable product11 Coal DryingYN---------xApplies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel isrequired to be burned. Specific energy efficiency project12Coal Addition to Pellets withLow Excess Air in theInduration FurnaceN------------xCheck on status of researchReduce flame temperature and energy requirements13 Ported KilnsYYY(grate-kilnsonly)N(Metso saysno NOximprovement)---x xApplicable to grate kilns.Provides additional oxygen for pellet oxidation which reduces the overallenergy use of the kiln14 Combustion Zone Cooling YN---------xBoiler technologyCooling of the primary flame zone by heat transfer to surroundingsurfaces15 Alternate FuelsYYY(for furnacescapable ofmultiple fuels)Y(not requiredby BART)Site-specificx xRequires case by case analysis.Typically, facilities experience lowerNOx when burning solid fuels.Lower combustion temps with solid fuels vs gas. May also reduce fuelNOx by using a fuel with less nitrogen.16Oxygen EnhancedCombustionN------------xResearch levelA small fraction of the combustion air is replaced with oxygen.Taconite BART AnalysisNOx ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

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

Reference No. 1NOxPollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle30SNOXN------------xEarly commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converterpasses through a novel glass-tube condenser in which the SO3ishydrated to H2SO4vapor and then condensed to a concentrated liquidsulfuric acid (H2SO4).31 SOx-NOx-Rox-BoxN------------xTechnology has not beendemonstratedDry sorbent injection upstream of the baghouse for removal of SOx andammonia injection upstream of a zeolitic selective catalytic reduction(SCR) catalyst incorporated in the baghouse to reduce NOx emissions.32 Electron (E-Beam) Process N------------xNo operating commercial applicationson coalElectron beam irradiation in the presence of ammonia to initiate chemicalconversion of sulfur and nitrogen oxides into components which can beeasily collected by conventional methods such as an ESP or baghouse.33 Electrocatalytic Oxidation N------------xSimilar to cold plasma. Will keepwatch for availability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using nonthermal plasma.On recent project, the vender was doing final trials on full-scaleapplications.34NOXSON------------Commercial version of adsorption.Limited experience (proof-of-concepttests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx fromflue gas from coal-fired utility and industrial boilers. In the process, theSO2is converted to a saleable sulfur by-product (liquid SO2, elementalsulfur, or sulfuric acid) and the NOx is converted to nitrogen and oxygen.35 Copper-OxideN------------xAbsorption and SCR. Experiencelimited to pilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheresof alumina, to form copper sulfate. Ammonia is injected into the flue gasbefore the absorption reactor and a selective catalytic reduction-typereaction occurs that reduces the nitric oxides in the flue gas. In theregeneration step, the copper sulfate is reduced in a regenerator with areducing agent, such as natural gas, producing a concentrated stream ofSO2.36 Cold PlasmaN------------xResearch Level37 BiofiltersYN---------xNot applicable to furnaces.Gas stream is passed through a filter medium of soil and microbes.Pollutants are adsorbed and degraded by microbial metabolism formingthe products carbon dioxide and water.38 Pahlman ProcessN------------xResearch LevelGas stream is passed through a filter baghouse in which speciallydeveloped, small-particle, high-surface area metal oxide sorbent havebeen deployed. Pollutants are removed from the gases by adsorption.1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART ReportsTaconite BART AnalysisSO2 ControlIndurating FurnacesAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2Reference(s)This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

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

Reference No. 1SO2Pollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?ApproximateControlEfficiency MPCA Taconite BART Report MPCA BART Guidance (Attachment 2) Other 2CommentsBasic Principle15 Electrocatalytic OxidationN ------------xSimilar to cold plasma. Will keep watch foravailability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-thermalplasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSON------------Commercial version of adsorption. Limitedexperience (proof-of-concept tests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gasfrom coal-fired utility and industrial boilers. In the process, the SO2is converted toa saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) and theNOx is converted to nitrogen and oxygen.17 Copper-OxideN ------------xAbsorption and SCR. Experience limited topilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheres ofalumina, to form copper sulfate. Ammonia is injected into the flue gas before theabsorption reactor and a selective catalytic reduction-type reaction occurs thatreduces the nitric oxides in the flue gas. In the regeneration step, the copper sulfateis reduced in a regenerator with a reducing agent, such as natural gas, producing aconcentrated stream of SO2.18 SNOXN ------------xEarly commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converter passesthrough a novel glass-tube condenser in which the SO3is hydrated to H2SO4vaporand then condensed to a concentrated liquid sulfuric acid (H2SO4).19 Cold PlasmaN ------------xResearch level1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART ReportsSummary of Relevant Economic Feasibility ($/ton) Control CostsAvg. Expected Values($/ton)Limiting/Marginal values($/ton)ReferenceRegulatory Body/RuleSO2NOxSO2NOxCommentsBART100 - 1000 100 - 100070 FR 39135BART281 - 129670 FR 39135 Table 3BART91970 FR 39133FR Notice 6JULY05 Final RuleBARTGuidelines disparagingly reference "thousands of dollars per ton"in commenting on the need to exceed MACT and its generalunreasonableness.70 FR 25210 CAIRCAIR1300Estimated Marginal cost 2009BART(proposed rule) 200-1000BART proposed lists this as values for 90-95% SO2 control,which is still assumed, or .1 to .15 lb/MMBtu. Dropped fromfinal to give states flexibility to require more. Says for scrubbers,bypasses aren't BART, only 100% scrubbing is BART.FR Notice 5MAY04 Proposed RuleBART(proposed rule)0.2 lb/MMBtu for NOx is assumed reasonable. Recognizes thatsome sources may need SCR to get this level. For those, statediscretion of the cost vs. visibility value is necessary.CAIR(using IPM)1000 1500CAIR ( 2009 in 1999$)9002400CAIR ( 2015 in 1999$)18003000Midwest RPO Report ReferencingCAIRCAIR (depending onNat'l emissions)1200 - 3000 1400- 2100This was modeled with TRUM (Technology RetrofittingUpdating Model) to develop the marginal values.Kammer EPA DecisionKammer Decision> 1000 > 1000LADCO Midwest RPO BoilerAnalysisLADCO/Midwest RPO 1240 - 3822 607 - 4493MANE-VU BART ControlAssessmentMANE-VU200 - 500 200 - 1500Bowers vs. SWAPCABowers vs. SWAPCA 300 300 1000 1000954-1134 was ruled too much, in favor of 256-310 for SO2. Thisdid consider incremental value. Sections XVII to XIXWRAP3000WRAP Trading ProgramMethodologyEPA - Referenced byWrapReferences EPA-600S\7-90-018. Low is <$500/ton, Moderate is$500-3000/ton, High is over $3000/tonThe dollars per ton estimates cited above were obtained from BART guidance, documentation of similar regulatory programs such as CAIR,and relevant court decisions. These materials indicate that most EPA sanctioned documents, including the final BART ruling, concretelysupport an average expected reasonable cost range of $1,300 to $1,800 per ton of NOx removed and a range of $1,000 to $1,300 per ton ofSO2removed. The BART presumptive limits were set based on cost effective controls that were on average less than these ranges. As anexample, the presumptive SO2limit was established based on an average cost effectiveness of less than $1,000/ton. As the cost analysisextends into RPO, WRAP and other regional planning documentation, the cost ranges become more variable and difficult to predict. Forease of comparison, the federally established ranges for NOx and SO2were used as a BART cost threshold basis.