Keetac BART Report 

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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
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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 SO2 Control Technology – Availability, Applicability, and 

Technical Feasibility ..................................................................................................25

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness.........................................26

Table 5-3 SO2 Control Cost Summary ........................................................................................28

Table 5-4 SO2 Control Technology Impacts Assessment.............................................................29

Table 5-5 Post- BART SO2 Control - Predicted 24-hour Maximum Emission Rates....................32

Table 5-6 Post-BART SO2 Modeling Scenarios - Visibility Modeling Results ............................33

Table 5-7 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility ..................................................................................................46

Table 5-8 Indurating Furnace NOx Control Technology Effectiveness ........................................47

Table 5-9 NOx Control Cost Summary........................................................................................48

Table 5-10 NOx Control Technology Impacts Assessment ............................................................50

Table 5-11 Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates...................52

Table 5-12 Post-BART NOX 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 NOX 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 
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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 analyses1

. The streamlined approach allows both the states and the 

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

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

for a streamlined analysis. 

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

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

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

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

for performance testing and continuous parametric monitoring for compliance demonstration. 

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

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 (SO2) and the furnace was only permitted to burn natural gas. 

 

1

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However, based on permit 13700063-003, two new SO2 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 SO2

and NOX for the Indurating Furnace: 

• BART for SO2: 

o SO2 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 SO2 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 SO2 compliance test and will be based on a 24-hour block 

average, consistent with the Taconite MACT and the permit. 
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• BART for NOx: 

o NOx emissions will be controlled by existing combustion controls and fuel 

blending. 

o NOx CEMS will be installed for the purpose of NOX monitoring. 

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

installation of the NOx 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 NOx CEMS and will be based on a 30-day rolling average. 

The schedule implementing the SO2 scrubber monitoring program, installing the NOx CEMS, and 

determining the appropriate NOx 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 NOx emission rates as determined during recent 

stack testing, the proposed BART controls will result in visibility improvement on the 98th 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.
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2. Introduction 

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

published regulations in 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. 
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Figure 2-1 Minnesota’s BART Geography 

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

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

(Source MPCA BART-Strategy October 4, 2005) 

By definition, reasonable progress means that the 20 best-visibility days must get no worse, and the 

20 worst-visibility days must become as good as the 20 worst days under natural conditions. 

Assuming a uniform rate of progress, the default glide path would require 1 to 2 percent 

improvement per year in visibility on the 20 worst days. The state must submit progress reports every 

five years to establish their advancement toward the Class I area natural visibility backgrounds. If a 

state feels it may be unable to adopt the default glide path, a slower rate of improvement may be 

proposed on the basis of cost or time required for compliance and non-air quality impacts. 
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2.A BART Eligibility 

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

must meet the following three conditions: 

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

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

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

plants, sulfur recovery plants, etc.); 

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

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

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

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

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

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

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

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

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

date from any other CAA requirements. 

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

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

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

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

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

are BART-eligible. 

2.B BART Determinations 

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

was previously part of a group BART determination, individual BART determinations must be made 

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

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

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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 

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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 protocol8

, 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. 

 

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 IBID 

8

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

BART in the State of Minnesota. 
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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. 

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

standard, or combination of these types of standards.”12

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

the Minnesota SIP. 

 

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3. Streamlined BART Analysis 

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

a streamlined approach for BART analyses13. 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: NOx, SO2, and PM. 

Relative to NOx and SO2, 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 NOx and SO2 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 NOx or SO2. The 

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

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

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

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

emissions.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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impact on visibility impairment, and no control requirements under the MACT standard is consistent 

with the intention of the BART analysis. 

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

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

to be equivalent to MACT according to MPCA guidance. 

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

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

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

identified 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 NOx and SO2, 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, 

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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. 
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Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis 
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4. Baseline Conditions and Visibility Impacts for 

BART Eligible Units 

As indicated in U.S. EPA’s final BART guidance16, 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 NOx, SO2, PM2.5 and 

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

approach when assessing visibility impacts. 

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 emissions17. 

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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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 SO2 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 SO2 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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Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions 

Data 
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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: 

• 98th Percentile: As defined by federal guidance and as stated in the MPCA’s document which 

identifies the Minnesota facilities that are subject to BART19, a source "contributes to 

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

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

protected Class I area receptor. 

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

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

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

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

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 98th percentile of the baseline conditions 

exceeds the threshold of 0.5 dV. The results of this modeling are also utilized in the post-BART 

modeling analysis in section 6 of this document. 

The full modeling analysis is presented in Appendix 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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Table 4-2 Baseline Visibility Modeling Results 
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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 NOx

and SO2: 

• 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 / PM10: 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. 

• SO2: SO2 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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stack test data, the SO2 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. 

• NOX: NOX is controlled through good combustion practices and fuel switches (lower NOx

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

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

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

Wet Walled Electrostatic Precipitator (WWESP) 

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

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

voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and 

collected on oppositely charged collector plates. Particles on the collector plates are released by 

rapping and fall into hoppers for collection and removal. 

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

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

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

absorber. 

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

as SO2 flue gas concentration, fuel used, and ore composition. Since the induration furnaces at this 

facility currently employ a wet scrubbers designed for removal of particulate matter, the scrubbers 

also perform as low efficiency SO2 wet scrubbers. The addition of a WWESP would act as a 

polishing SO2 control device and would experience reduced control efficiency due to lower SO2 inlet 

concentrations. A control efficiency as a polishing WWESP ranges from 30-80% dependent upon the 

process specific operating parameters. 

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

technology for SO2 reduction for this BART analysis. 

Wet Scrubbing (High and Low Efficiency) 

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

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

liquid, to remove SO2 in the waste gas. Crushed limestone, lime, or caustic are 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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For a wet scrubber to be considered a high efficiency SO2 wet scrubber, the scrubber would require 

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

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

design using water as a scrubbing solvent. Venturi rod scrubbers, which are frequently used for PM 

control at taconite facilities, will also remove some of the SO2 from the flue gas as collateral 

emission reduction. 

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

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

reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

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

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

more reactive reagent than limestone. The reactions for lime scrubbing are as follows: 

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

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

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

follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

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

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

equipment 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 SO2 control efficiency range for SO2 scrubbers on coal-fired utility boilers with low 

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

The highest control efficiencies can be achieved when SO2 concentrations are the highest. Unlike 
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coal-fired boilers, indurating furnaces operate with maximum excess air to enable proper oxidation of 

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

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

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

wet scrubber. 

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 SO2 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 SO2 from the existing scrubber as well as a high efficiency SO2 polishing wet scrubber, an 

estimated overall efficiency of the control train would then be approximately 80%. 

The new SO2 scrubbers which commenced operation in October 2005 have been evaluated, tested, 

and optimized for SO2 per the design of the scrubbers. Since the operation of the scrubber has 

recently been optimized, further improvement of SO2 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 SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Lime/limestone injection is a post-combustion SO2 control technology in which pulverized lime or 

limestone is directly injected into the duct upstream of the fabric filter. Dry sorption of SO2 onto the 

lime or limestone particle occurs and the solid particles are collected with a fabric filter. Further SO2

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

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

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

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

wet scrubber. The exhaust temperature is typically in the range of 100°F to 150°F and is saturated 

with water. For comparison, a utility boiler exhaust operates at 350 °F or higher and is not saturated 

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

saturated with moisture and plug both the filters and the dust removal system. Although this may be 

an available and applicable control option, it is not technically feasible due to the high moisture 

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

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

absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water 

evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the 

gas and collected with a fabric filter. When used to specifically control SO2, the term flue-gas 

desulfurization (FGD) may also be used. 

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

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

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

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

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

be further evaluated in this report. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a 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 SO2 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 (SO2) for another (NOx), as induration furnaces typically emit 
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significantly less NOx 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 SO2 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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To 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 SO2 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 SO2 control technologies that are 

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

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

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

Technical Feasibility 

Step 1 Step 2 

SO2 Pollution Control 

Technology 

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

Wet Walled Electrostatic 

Precipitator (WWESP) Y Y Y Y 

Secondary Wet Scrubber Y Y Y Y 

Modifications to Existing Wet 

Scrubbing (Low Efficiency) Y Y N N 

Dry Sorbent Injection Y Y Y N 

Spray Dry Absorption Y Y Y N 

Energy Efficiency Projects Y Y Y N 

Alternative Fuels Y Y Y 

N 

(not required 

by BART) 

Coal Processing Y Y Y N 
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5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

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

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

polishing control devices since wet scrubber currently operate as primary control. 

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Wet Walled Electrostatic Precipitator (WWESP) 80% 

Secondary Wet Scrubber 60% 

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

As illustrated in Table 5-2 above, the technically feasible 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 manual22

 

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

measure 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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Table 5-3 SO2 Control Cost Summary 
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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 pollutant24

. 

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

evaluated for visibility improvement, energy and other impacts. 

The cost of SO2 control 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 SO2 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 SO2 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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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 SO2 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 SO2. 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 SO2

emissions scenario is based on coal burning and the worst-case NOx 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 SO2, NOX, 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 SO2 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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• Current Operation: 

o Natural Gas Operation: The operation of the new SO2 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 SO2 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 SO2 Scrubber: 

o Natural Gas Operation: The operation of a second SO2 scrubber, in combination with 

the existing SO2 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 SO2 scrubber, in combination with the 

existing SO2 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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Table 5-5 Post- BART SO2 Control - Predicted 24-hour Maximum Emission Rates 
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Table 5-6 Post-BART SO2 Modeling Scenarios - Visibility Modeling Results 
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5.A.ii Nitrogen Oxide Controls 

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

mechanisms by which NOx production occurs: 

• Fuel bound nitrogen compounds in the fuel are oxidized in the combustion process to NOx. 

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

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

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

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

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

minor amounts of NOx are emitted as prompt NOx. 

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

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

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

not technically feasible? 

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

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

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

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

technology. 

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

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

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

External Flue Gas Recirculation (EFGR) 

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

thereby reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is 

collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is 

mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas 

reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen 

level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For 

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

the burner tip. 

The typical NOx 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 2,400o

F in order to meet 

product specifications. Existing burners are designed to meet these process conditions. 
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Application of EFGR would reduce flame temperatures. Lower flame temperatures 

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

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

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

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

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

equipment failures. 

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

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

Low-NOx Burners 

Low-NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation through 

the restriction of oxygen, flame temperature, and/or residence time. LNB is typically a staged 

combustion process that is designed to split fuel combustion into two zones, primary combustion and 

secondary combustion. This analysis utilizes the staged fuel design in the cost analysis because lower 

emission rates can be achieved with staged fuel burner than with a staged air burner. 

In the primary combustion zone of a staged fuel burner, NOx formation is limited by a rich (high 

fuel) condition. Oxygen levels and flame temperatures are low; this results in less NOx formation. In 

the secondary combustion zone, incomplete combustion products formed in the primary zone act as 

reducing agents. In a reducing atmosphere, nitrogen compounds are preferentially converted to 

molecular nitrogen (N2) over nitric oxide (NO).

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 NOx 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-NOx burners are not a feasible control technology for the 

indurating furnace. 
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Induced Flue Gas Recirculation Burners 

Induced flue gas recirculation burners, also called ultra low-NOx burners, combine the benefits of 

flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue 

gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel 

combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR 

burners in high temperature applications is 25-50%. 

As 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 NOx reduction, and it 

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

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

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

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

IFGR would adversely affect taconite pellet product quality. 

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

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

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a 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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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 NOX 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 NOX 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 NOx emissions at Keetac, it is important to note that solid 

fuels are typically burned in the furnaces and therefore, the actual improvement in NOX emissions 

would be significantly less than 5% estimate. 

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 SO2 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 (SO2) for another (NOx), as induration furnaces typically emit 

significantly less NOx 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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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 NOx CEMS or Other Parametric Monitoring 

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

emissions26. Based on conversations with MPCA staff, this work practice would include process 

adjustments, or optimization, to minimize NOx emissions. The impact of the process adjustments 

would be measured using the NOx CEMS. If NOx 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 NOx

CEMS on all five indurating furnaces. The use of the NOx 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 NOx CEMS has allowed Minntac 

to quantify the emissions rates for all fuel combinations. 

Although the NOx 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 NOx CEMS as a control technology. 

Therefore, process optimization as a control option will not be evaluated further in this report. 

Post Combustion Controls 

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

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

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

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

 

26 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 4. 
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In addition to these treatment systems, there are a large number of other processes being developed 

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

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

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

alternatives is described below.

Non-Selective Catalytic Reduction (NSCR) 

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

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

primarily in natural gas combustion applications. 

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

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

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

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

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

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

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

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

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

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

this report. 

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction 

SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue 

gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction: 

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2) 
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A catalyst bed containing metals in the platinum family is used to lower the activation energy 

required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a 

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

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

corrosion problems. A high temperature zeolite catalyst is also available; it can operate in the 600 °F 

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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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 

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

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

(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium 
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hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 

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

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

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

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

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

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

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

Tri-NOx

®

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

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

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

stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Another possible 

advantage of the Tri-NOx

®

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

Tri-NOx

®

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

exhaust gas (1,000 ppm NOx). NOx concentrations in taconite exhaust are typically no higher than 

300 ppm. Therefore, Tri-NOx

®

 is not applicable to taconite processing and will not be analyzed 

further in this BART analysis. 

Low Temperature Oxidation (LoTOx®

) 

BOC Gases’ Lo-TOx®

 is an example of a version of an LTO system. LoTOx® technology uses ozone 

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

scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a 
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scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an 

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

needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be 

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

generation. 

The first component of the technical feasibility review includes determining if the technology would 

apply to the process being reviewed. This would include a review and comparison of the chemical 

and physical properties required. Although it appears that the chemistry involved in the LTO 

technology 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 (Fe3O4) which would react with the 

ozone to form hematite (Fe2O3); since the ozone injection point would be before the scrubber, 

there can be more than 400 pounds per hour of taconite dust in the flue gas which could 

consume a significant amount of the ozone being generated which may change the reaction 

kinetics; consequently, this would necessitate either an increase in the amount of ozone 

generated or a decrease in the estimated control efficiency; 
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• The ozone that would be injected into the flue gas would react with the SO2, converting the 

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

• Since LTO has not been installed at a taconite plant, it is likely that the application of LTO to 

an indurating furnace waste gas could present technical problems which were not 

encountered, or even considered, in the existing LTO applications; 

• An LTO system at a taconite facility would also be a source of nitrate discharge to the 

tailings basin which would change the facility water chemistry which could cause operational 

problems and would likely cause additional problems with National Pollutant Discharge 

Elimination System (NPDES) discharge limits and requirements. 

Application of this technology has not been applied to taconite induration furnaces, to airflows of the 

magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high moisture content. 

Using LTO at a taconite plant would require research, test runs, and extended trials to identify 

potential issues related to design for high airflows and impacts on plant systems, including the 

furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of 

performance would be forthcoming in advance of a demonstration project. The timeline required to 

perform such a demonstration project would likely be two years to develop and agree on the test 

plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs 

for a reasonable study period, and evaluate and report on the results. The results would not be 

available within the time window for establishing emission limits to be incorporated in the state 

implementation plan (SIP) by December 2007. 

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

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

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

Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for 

this application and will not be evaluated further. 

Step 2 Conclusion 

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

available and applicable to the indurating furnace process are identified in Table 5-4. The technical 

feasibility as determined in Step 2 is also included in Table 5-6.
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Table 5-7 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility 

Step 1 Step 2 

SO2 Pollution Control 

Technology 

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

External Flue Gas 

Recirculation (EFGR) Y Y N --- 

Low-NOx Burners Y Y 

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 

NOx CEMS Y Y Y N 

Non-Selective Catalytic 

Reduction (NSCR) Y N --- --- 

Selective Catalytic Reduction 

(SCR) with conventional 

reheat 

Y Y Y Y 

Regenerative SCR Y N --- --- 

Selective Non-Catalytic 

Reduction (SNCR) Y N --- --- 

Low Temperature Oxidation 

(LTO) Y N --- --- 
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5.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 NOx Control Technology Effectiveness 

NOx 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 manual27 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. 
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Table 5-9 NOx Control Cost Summary 
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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 indirect 

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

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

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

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

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

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

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

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

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

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

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant29

. 

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. 
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The cost of NOX 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-NOx burners are 

presented in Table 5-10. 

Table 5-10 NOx Control Technology Impacts Assessment 

Control Technology Energy Impacts Other Impacts 

SCR with 

Conventional Reheat 

• Increased fan sizes 

due to increased 

pressure drop 

• Natural gas burning 

to reheat flue gas to 

reaction temperature 

• 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 NOx 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 SO2. 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. 
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Predicted 24-Hour Maximum Emission Rates 

Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts, 

the post-BART emissions to be used for the visibility impacts analysis should also reflect a 

maximum 24-hour average project emission rate. 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 SO2

emissions scenario is based on coal burning and the worst-case NOx 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 NOX 24-hour maximum emission rates for the postbaseline (i.e. post-BART) operations. The stack parameters (location, height, velocity, and 

temperature) were assumed to remain unchanged from the baseline modeling. 

Post-BART Visibility Impacts Modeling Results 

Results of the post-BART visibility impacts modeling for current operations are presented in Table 

5-12. 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 SO2 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 SO2 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. 
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Table 5-11 Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates 
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Table 5-12 Post-BART NOX Modeling Scenarios - Visibility Modeling Results 
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• 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 NOx 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. 
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6. Visibility Impacts 

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

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

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

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

The visibility impacts of individual control technologies were presented in Step 5 of sections 5.A.i.e 

and 5.A.ii.e. This section of the report evaluates the various BART control scenarios utilizing both 

SO2 and NOx controls, and determines the resulting degree of visibility improvement. 

The intent of this section is to present the modeling scenarios for combinations of SO2 and NOx

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 SO2, NOX and PM10 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 SO2 controls with NOx 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 SO2 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. 
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Table 6-1 Post-BART Modeling Scenarios – Predicted 24-hour Maximum Emission Rates 
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o Coal Operation: The operation of the new SO2 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 SO2 Scrubber: 

o Natural Gas Operation: The operation of a second SO2 scrubber, in combination with 

the existing SO2 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 SO2 scrubber, in combination with the 

existing SO2 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 NOx 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. 
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• 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 SO2 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 SO2 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 
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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. 
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Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results 
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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 SO2 and NOx. 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 SO2, add-on secondary wet scrubber to control 

additional SO2 control, ported kiln, SCR (with conventional flue gas reheat), and NOx 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 SO2 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 NOx

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

SCR

Application of SCR is not cost effective at $9514/ton NOx 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 NOx. The 

spent catalyst would create a new solid waste. In addition, ammonia, a visibility impairing 

pollutant, would be emitted due to ammonia slip from the process and would 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 SO2 and NOX for the Indurating Furnace: 

• BART for SO2: 

o SO2 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 SO2 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 
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based on the initial SO2 compliance test and will be based on a 24-hour block 

average, consistent with the Taconite MACT and the permit. 

• BART for NOx: 

o NOx emissions will be controlled by existing combustion controls and fuel 

blending. 

o NOx CEMS will be installed for the purpose of NOx monitoring. 

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

installation of the NOx 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 NOx CEMS and will be based on a 30-day rolling average. 

The schedule implementing the SO2 scrubber monitoring program, installing the NOx CEMS, and 

determining the appropriate NOx 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 NOx emission rates as determined during recent 

stack testing, the proposed BART controls will result in visibility improvement on the 98th 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 Analysis

Emission 

Unit # Emission Unit Description

NOx Max. 24-hr 

Actual

Emissions (lb/day)

SO2 Max. 24-hr 

Actual

Emissions 

(lb/day)

PM10 Max. 24-

hr Actual

Emissions 

(lb/day)

MACT

PM Emission 

Limit

*

(g/dscf)

Stack 

Number 

3.A. Indurating Furnaces

EU 030 Grate Kiln - Indurator Waste Gas, Phase II 33,295.2 5,213.4 2,452.1 0.010 SV051M BART 

3.B. PM-Only Taconite MACT Emission Units

EU 001 Gyrator Crusher - Primary Crusher No. 1 --- --- 6.6 0.008 SV001M 

EU 002 Gyrator Crusher - Primary Crusher No. 2 --- --- 4.9 0.008 SV002M 

EU 003 Conveyor Transfer - Drive house No. 1 Primary Conveyor --- --- 46.4 0.008 SV003M 

EU 004 Conveyor Transfer - Drive house No. 2 Primary Conveyor --- --- 7.2 0.008 SV004M 

EU 005 Conveyor Transfer - Crude Ore Feed --- --- 88.4 0.008 SV005M 

EU 006 Conveyor Transfer - Crude Ore Feed --- --- 88.4 0.008 SV006M 

EU 007 Conveyor Transfer - Crude Ore Feed --- --- 88.4 0.008 SV007M 

EU 008 Conveyor Transfer - Crude Ore Feed --- --- 88.4 0.008 SV008M 

EU 009 Conveyor Transfer - Crude Ore Feed --- --- 88.4 0.008 SV009M 

EU 010 Conveyor Transfer - Crude Ore Feed --- --- 88.4 0.008 SV010M 

EU 011 Conveyor Transfer - Crude Ore Feed --- --- 2.9 0.008 SV011M 

EU 012 Conveyor Transfer - Crude Ore Feed --- --- 2.9 0.008 SV012M 

EU 013 Conveyor Transfer - Crude Ore Feed --- --- 2.9 0.008 SV013M 

EU 014 Conveyor Transfer - Crude Ore Feed --- --- 2.9 0.008 SV014M 

EU 022 Grate Kiln - Grate Discharge, Phase II --- --- 23.9 0.008 SV022M 

EU 024 Cooler Dump Zone, Phase II --- --- 22.1 0.008 SV024M 

EU 026 Pellet Cooler, Phase II --- --- 386.6 0.008 SV026M 

EU 032 Pellet Cooler Product Belts, Phase II --- --- 12.2 0.008 SV032M 

EU 034 Pellet Loadout Drive House --- --- 66.3 0.008 SV034M 

EU 037 Pellet Screening - Phase II, Pellet Screening System --- --- 9.8 0.008 SV037M 

EU 038 Pellet Screening - Phase II, Conveyor Drop --- --- 9.8 0.008 SV038M 

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

NONE --- --- --- --- --- --- 

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

EU 015 Additive Blending, Phase I --- --- 0.6 --- SV015M 

EU 016 Additive Blending, Phase II --- --- 4.4 --- SV016M 

EU 017 Addititive Silo, Phase I --- --- 4.8 --- SV017M 

EU 018 Addititive Silo, Phase II --- --- 2.3 --- SV018M 

EU 018 Additive Blending --- --- 2.3 --- SV049M 

3.E. Other Combustion Units 

NONE --- --- --- --- --- --- 

* The taconite MACT emission limits are based on EPA Method 5 and include the applicable averaging and grouping provisions, as presented in the regulation.
Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data 

EU # EU Description

SO2 Maximum 

24-hr Emission 

Rate (lbs/day)

NOx Maximum 

24-hr Emission 

Rate (lbs/day)

PM2.5 

Maximum 24-

hr Emission 

Rate (lbs/day)

PM10 Maximum 

24-hr Emission 

Rate (lbs/day) SV #

Stack 

Easting 

(utm)

Stack 

Northing 

(utm)

Height of 

Opening 

from 

Ground (ft)

Base 

Elevation 

of 

Ground 

(ft)

Stack 

length, 

width, or 

Diameter 

(ft)

Flow 

Rate at 

exit 

(acfm)

Exit 

Temp 

(°F)

Basis for SO2 

24-hour Actual 

Emissions

Basis for NOx 

24-hour Actual 

Emissions

Basis for 

PM2.5 24-

hour 

Actual 

Emissions

Basis for 

PM10 24-hour 

Actual 

Emissions

EU 030

Grate Kiln - 

Indurator Waste 

Gas, Phase II

7,152 33,288 n/a 2,452 SV051M 495489 5251028 156 1480 13 848,000 132 Stack Test October 2005 Stack Test July 2000 n/a Stack Test July 2000

EU 001

Gyrator Crusher - 

Primary Crusher 

No. 1

n/a n/a n/a 6.627945205 SV001M 495040.2 5251860.4 63 1390 2.7 19,500 77 n/a n/a n/a

Emission 

factors from 

stack tests

EU 002

Gyrator Crusher - 

Primary Crusher 

No. 2

n/a n/a n/a 4.897315068 SV002M 495002 5251960.9 64.7 1390 2.9 23,700 77 n/a n/a n/a

Emission 

factors from 

stack tests

EU 003

Conveyor Transfer - 

Drive house No. 1 Primary Conveyor

n/a n/a n/a 46.39561644 SV003M 495103.7 5251488.6 115 1500 1.9 10,900 77 n/a n/a n/a

Emission 

factors from 

stack tests

EU 004

Conveyor Transfer - 

Drive house No. 2 Primary Conveyor

n/a n/a n/a 7.21709589 SV004M 495096.1 5251488.6 118 1500 2.3 16,600 77 n/a n/a n/a

Emission 

factors from 

stack tests

EU 005 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 88.37260274 SV005M 495196.2 5251103.9 62 1480 2.5 11,500 77 n/a n/a n/a Emission factors from stack tests

EU 006 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 88.37260274 SV006M 495195.8 5252644.5 62 1480 2.5 11,500 77 n/a n/a n/a Emission factors from stack testsEU 007 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 88.37260274 SV007M 495209.2 5252659.1 62 1480 2.5 11,500 77 n/a n/a n/a Emission factors from stack testsEU 008 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 88.37260274 SV008M 495212.9 5252688.3 62 1480 2.5 11,500 77 n/a n/a n/a Emission factors from stack testsEU 009 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 88.37260274 SV009M 495183.7 5252705.4 62 1480 2.5 11,500 77 n/a n/a n/a Emission factors from stack testsEU 010 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 88.37260274 SV010M 495184.1 5251180.7 62 1480 2.5 11,500 77 n/a n/a n/a Emission factors from stack testsEU 011 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 2.872109589 SV011M 495230 5252739.5 127 1480 1.9 13,400 77 n/a n/a n/a Emission factors from stack tests

EU 012 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 2.872109589 SV012M 495227.6 5252754.1 127 1480 1.9 13,400 77 n/a n/a n/a Emission factors from stack tests

EU 013 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 2.872109589 SV013M 495225.2 5252772.4 127 1480 1.9 13,400 77 n/a n/a n/a Emission factors from stack testsEU 014 Conveyor Transfer - Crude Ore Feed n/a n/a n/a 2.872109589 SV014M 495222.9 5252869.3 127 1480 1.9 13,400 77 n/a n/a n/a Emission factors from stack testsEU 022 Grate Kiln - Grate Discharge, Phase II n/a n/a n/a 23.93424658 SV022M 495403.2 5250986.7 155.5 1480 4.2 27,400 85 n/a n/a n/a Emission factors from stack tests

EU 024 Cooler Dump Zone, Phase II n/a n/a n/a 22.09315068 SV024M 495410.5 5250930.6 155.5 1480 5.2 59,000 125 n/a n/a n/a Emission factors from stack tests

EU 026 Pellet Cooler, Phase II n/a n/a n/a 386.630137 SV026M 495405.6 5250942.8 151 1480 13.5 388,804 975 n/a n/a n/a Emission factors from stack tests

EU 032

Pellet Cooler 

Product Belts, 

Phase II

n/a n/a n/a 12.15123288 SV032M 495410.5 5250942.8 156 1480 5.1 29,350 77 n/a n/a n/a

Emission 

factors from 

stack tests

EU 034 Pellet Loadout Drive House n/a n/a n/a 66.27945205 SV034M 495466.3 5250790.3 44 1480 2.2 11,500 77 n/a n/a n/a Emission factors from stack tests

EU 037

Pellet Screening - 

Phase II, Pellet 

Screening System

n/a n/a n/a 9.757808219 SV037M 495437.2 5250887.9 70 1480 5 65,000 120 n/a n/a n/a

Emission 

factors from 

stack tests

EU 038

Pellet Screening - 

Phase II, Conveyor 

Drop

n/a n/a n/a 9.757808219 SV038M 495457.9 5250883.6 44 1480 1.6 18,780 120 n/a n/a n/a

Emission 

factors from 

stack tests

EU 015 Additive Blending, Phase I n/a n/a n/a 0.621523973 SV015M 495280.2 5251016.1 131 1480 2.2 3,800 77 n/a n/a n/a Emission factors from stack tests

EU 016 Additive Blending, Phase II n/a n/a n/a 4.350667808 SV016M 495438.6 5251046.3 150 1480 3.1 14,800 77 n/a n/a n/a Emission factors from stack tests

EU 017 Addititive Silo, Phase I n/a n/a n/a 4.823145205 SV017M 495354.5 5251016 87 1480 1 3,100 77 n/a n/a n/a Emission factors from stack tests

EU 018 Addititive Silo, Phase II n/a n/a n/a 2.257643836 SV018M 495464 5251028 89 1480 1 2,300 77 n/a n/a n/a Emission factors from stack tests

EU 018 Additive Blending n/a n/a n/a 2.257643836 SV049M 495464 5251028 89 1480 1 2,300 77 n/a n/a n/a

Emission 

factors from 

stack tests
Table 4-2 Baseline Visibility Modeling Results

2002 2003 2004 

Scenario # SO2 NOx

Class I 

Area with 

Greatest 

Impact

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

0

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

VNP 1.372 49 1.197 42 1.008 31 

Scenario Control Technology
Table 5-3 SO2

 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/a
Table 5-5 Post- BART SO2 Control - Predicted 24-hour Maximum Emission Rates

Scenario Control Technology SO2 

Control 

Scenario SV #

Emission 

Unit SO2 NOx % Reduction

Max 24-hour 

lbs/day % R

1 SV051M EU030

Current Operations

Burning Nat Gas 

(with new Scrubber)

Current Operations

Burning Nat Gas 

(with new Scrubber)

Max is stack test 

inlet with pH 7 

on scrubber 

(34% removal)

196.7

Max 

Nat

does

2 SV051M EU030

Current Operations

Burning Coal

(with new Scrubber)

Current Operations

Burning Coal

(with new Scrubber)

Max is Coal 

stack test pH 7 

(34%) with %S 

adjustment 

400.0

Max 

Coal 

May 2

3 SV051M EU030

Secondary Wet Scrubber 

(after existing scrubber)

Burning Natural Gas

Current Operations

Burning Nat Gas 

(with new Scrubber)

60% 78.7 

4 SV051M EU030

Secondary Wet Scrubber

(after existing scrubber)

Burning Coal

Current Operations

Burning Coal

(with new Scrubber)

60% 160.0

Max 

Coal 

May 2
Table 5-6 Post-BART SO2 Modeling Scenarios - Visibility Modeling Results

2002 2003 2004 

Scenario # SO2 NOx

Class I 

Area with 

Greatest 

Impact

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

0

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

VNP 1.372 49 1.197 42 1.008 31 

1

Current Operations

Burning Nat Gas 

(with new Scrubber)

Current Operations

Burning Nat Gas 

(with new Scrubber)

VNP 1.337 48 1.18 42 0.986 30 

2

Current Operations

Burning Coal

(with new Scrubber)

Current Operations

Burning Coal

(with new Scrubber)

VNP 0.642 17 0.534 9 0.447 6 

3

Secondary Wet 

Scrubber 

(after existing 

scrubber)

Burning Natural 

Gas

Current Operations

Burning Nat Gas 

(with new Scrubber)

VNP 1.297 47 1.156 39 0.96 30 

4

Secondary Wet 

Scrubber

(after existing 

scrubber)

Burning Coal

Current Operations

Burning Coal

(with new Scrubber)

VNP 0.537 12 0.46 5 0.392 4 

Scenario Control Technology
Table 5-11 Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates

Scenario Control Technology SO2 

Control 

Scenario SV #

Emission 

Unit SO2 NOx % Reduction

Max 24-hour 

lbs/day % R

1 SV051M EU030

Current Operations

Burning Nat Gas 

(with new Scrubber)

Current Operations

Burning Nat Gas 

(with new Scrubber)

Max is stack test 

inlet with pH 7 

on scrubber 

(34% removal)

196.7

Max 

Nat

does

2 SV051M EU030

Current Operations

Burning Coal

(with new Scrubber)

Current Operations

Burning Coal

(with new Scrubber)

Max is Coal 

stack test pH 7 

(34%) with %S 

adjustment 

400.0

Max 

Coal 

May 2

5 SV051M EU030

Current Operations

Burning Nat Gas 

(with new Scrubber)

Ported Kiln

Burning Nat Gas

Max is stack test 

inlet with pH 7 

on scrubber 

(34% removal)

196.7 

6 SV051M EU030

Current Operations

Burning Coal

(with new Scrubber)

Ported Kiln

Burning Coal

(No NOx Improvement)

Max is Coal 

stack test pH 7 

(34%) with %S 

adjustment 

400.0

Max 

Coal 

May 2

9 SV051M EU030

Current Operations

Burning Nat Gas 

(with new Scrubber)

SCR

With Conventional Reheat

Max is stack test 

inlet with pH 7 on 

scrubber 

(34% removal)

196.7 

10 SV051M EU030

Current Operations

Burning Coal

(with new Scrubber)

SCR

With Conventional Reheat

Max is Coal 

stack test pH 7 

(34%) with %S 

adjustment 

400.0 
Table 5-9 NOx

 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/a
Table 5-12 Post-BART NOx Modeling Scenarios - Visibility Modeling Results

2002 2003 2004 

Scenario # SO2 NOx

Class I 

Area with 

Greatest 

Impact

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of da

exceeding 

deciview

0

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

VNP 1.372 49 1.197 42 1.008 31 

1

Current Operations

Burning Nat Gas 

(with new Scrubber)

Current Operations

Burning Nat Gas 

(with new Scrubber)

VNP 1.337 48 1.18 42 0.986 30 

2

Current Operations

Burning Coal

(with new Scrubber)

Current Operations

Burning Coal

(with new Scrubber)

VNP 0.642 17 0.534 9 0.447 6 

5

Current Operations

Burning Nat Gas 

(with new Scrubber)

Ported Kiln

Burning Nat Gas

VNP 1.281 47 1.118 36 0.941 28 

6

Current Operations

Burning Coal

(with new Scrubber)

Ported Kiln

Burning Coal

(No NOx 

Improvement)

VNP 0.64 17 0.531 9 0.446 6 

9

Current Operations

Burning Nat Gas 

(with new Scrubber)

SCR

With Conventional 

Reheat

VNP 0.385 1 0.321 2 0.275 1 

10

Current Operations

Burning Coal

(with new Scrubber)

SCR

With Conventional 

Reheat

VNP 0.333 1 0.275 1 0.222 0 

Scenario Control Technology
Table 6-1 Post-BART Modeling Scenarios – Predicted 24-hour Maximum Emission Rates

Scenario Control Technology SO2 NO

Control 

Scenario SV #

Emission 

Unit SO2 NOx % Reduction

Max 24-hour 

lbs/day % Reduction

0 SV051M EU 030

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

n/a 7152.0 n/a 

1 SV051M EU 030

Current Operations

Burning Nat Gas 

(with new Scrubber)

Current Operations

Burning Nat Gas 

(with new Scrubber)

Max is stack test 

inlet with pH 7 

on scrubber 

(34% removal)

196.7

Max NOx on 

Natural Gas 

doesn't change

2 SV051M EU 030

Current Operations

Burning Coal

(with new Scrubber)

Current Operations

Burning Coal

(with new Scrubber)

Max is Coal 

stack test pH 7 

(34%) with %S 

adjustment 

400.0

Max NOx on 

Coal based on 

May 2005 Stack 

Test

3 SV051M EU 030

Secondary Wet Scrubber 

(after existing scrubber)

Burning Natural Gas

Current Operations

Burning Nat Gas 

(with new Scrubber)

60% 78.7 --- 

4 SV051M EU 030

Secondary Wet Scrubber

(after existing scrubber)

Burning Coal

Current Operations

Burning Coal

(with new Scrubber)

60% 160.0

Max NOx on 

Coal based on 

May 2005 Stack 

Test

5 SV051M EU 030

Current Operations

Burning Nat Gas 

(with new Scrubber)

Ported Kiln

Burning Nat Gas

Max is stack test 

inlet with pH 7 

on scrubber 

(34% removal)

196.7 0.1 

6 SV051M EU 030

Current Operations

Burning Coal

(with new Scrubber)

Ported Kiln

Burning Coal

(No NOx Improvement)

Max is Coal 

stack test pH 7 

(34%) with %S 

adjustment 

400.0

Max NOx on 

Coal based on 

May 2005 Stack 

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

Scenario Control Technology SO2 NO

Control 

Scenario SV #

Emission 

Unit SO2 NOx % Reduction

Max 24-hour 

lbs/day % Reduction

7 SV051M EU 030

Secondary Wet Scrubber 

(after existing scrubber)

Burning Natural Gas

Ported Kiln

Burning Nat Gas

60% 78.7 0.1 

8 SV051M EU 030

Secondary Wet Scrubber

(after existing scrubber)

Burning Coal

Ported Kiln

Burning Coal

(No NOx Improvement)

60% 160.0

Max NOx on 

Coal based on 

May 2005 Stack 

Test

9 SV051M EU 030

Current Operations

Burning Nat Gas 

(with new Scrubber)

SCR

With Conventional Reheat

Max is stack test 

inlet with pH 7 

on scrubber 

(34% removal)

196.7 0.8 

10 SV051M EU 030

Current Operations

Burning Coal

(with new Scrubber)

SCR

With Conventional Reheat

Max is Coal 

stack test pH 7 

(34%) with %S 

adjustment 

400.0 0.8 

11 SV051M EU 030

Secondary Wet Scrubber 

(after existing scrubber)

Burning Natural Gas

SCR

With Conventional Reheat

Max is stack test 

inlet with pH 7 on 

scrubber 

(34% removal)

196.7 0.8 

12 SV051M EU 030

Secondary Wet Scrubber

(after existing scrubber)

Burning Coal

SCR

With Conventional Reheat

Max is Coal 

stack test pH 7 

(34%) with %S 

adjustment 

400.0 0.8 
Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results

2002 2003 2004 

Scenario # SO2 NOx

Class I 

Area with 

Greatest 

Impact

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

0

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

VNP 1.372 49 1.197 42 1.008 31 

1

Current Operations

Burning Nat Gas 

(with new Scrubber)

Current Operations

Burning Nat Gas 

(with new Scrubber)

VNP 1.337 48 1.18 42 0.986 30 

2

Current Operations

Burning Coal

(with new Scrubber)

Current Operations

Burning Coal

(with new Scrubber)

VNP 0.642 17 0.534 9 0.447 6 

3

Secondary Wet 

Scrubber 

(after existing 

scrubber)

Burning Natural Gas

Current Operations

Burning Nat Gas 

(with new Scrubber)

VNP 1.297 47 1.156 39 0.96 30 

4

Secondary Wet 

Scrubber

(after existing 

scrubber)

Burning Coal

Current Operations

Burning Coal

(with new Scrubber)

VNP 0.537 12 0.46 5 0.392 4 

5

Current Operations

Burning Nat Gas 

(with new Scrubber)

Ported Kiln

Burning Nat Gas

VNP 1.281 47 1.118 36 0.941 28 

6

Current Operations

Burning Coal

(with new Scrubber)

Ported Kiln

Burning Coal

(No NOx 

Improvement)

VNP 0.64 17 0.531 9 0.446 6 

Scenario Control Technology
Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results

2002 2003 2004 

Scenario # SO2 NOx

Class I 

Area with 

Greatest 

Impact

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Modeled 98th 

Percentile Value 

(deciview)

No. of days 

exceeding 0.5 

deciview

Scenario Control Technology

7

Secondary Wet 

Scrubber 

(after existing 

scrubber)

Burning Natural Gas

Ported Kiln

Burning Nat Gas

VNP 1.241 45 1.093 36 0.915 28 

8

Secondary Wet 

Scrubber

(after existing 

scrubber)

Burning Coal

Ported Kiln

Burning Coal

(No NOx 

Improvement)

VNP 0.535 12 0.453 5 0.391 4 

9

Current Operations

Burning Nat Gas 

(with new Scrubber)

SCR

With Conventional 

Reheat

VNP 0.385 1 0.321 2 0.275 1 

10

Current Operations

Burning Coal

(with new Scrubber)

SCR

With Conventional 

Reheat

VNP 0.333 1 0.275 1 0.222 0 

11

Secondary Wet 

Scrubber 

(after existing 

scrubber)

Burning Natural Gas

SCR

With Conventional 

Reheat

VNP 0.334 1 0.29 1 0.25 1 

12

Secondary Wet 

Scrubber

(after existing 

scrubber)

Burning Coal

SCR

With Conventional 

Reheat

VNP 0.207 0 0.18 0 0.156 0 
United States Steel: Keewatin Taconite Company 9/6/2

BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Cost Summary

NOx Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Incremen

Control C

$/ton

Selective Catalytic Reduction with Reheat (SCR)

80% 830.8 3323.2 $63,936,099 $31,615,514 $9,514 $9,952

Ported Kilns 5% 3946.3 207.7 $6,465,590 $610,306 $2,938 n/a

SO2 Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Incremen

Control C

$/ton

Wet Walled Electrostatic Precipitator (WWESP)(after existing scrubber)

80% 190.1 760.4 $45,081,576 $11,531,318 $15,165 n/a

Secondary Wet Scrubber

(after existing scrubber) 60% 380.2 570.3 $30,203,843 $5,058,352 $8,870 n/a

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control CostsCost Summary 
United States Steel: Keewatin Taconite Company

BART Report - Attachment A: Emission Control Cost AnalysisTable A.2: Summary of Utility, Chemical and Supply Costs

Operating Unit: Indurating Furnace Study Year 2006

Emission Unit Number EU 030Stack/Vent Number SV051MItem Unit Cost Units Cost Year Data Source Notes

Operating Labor 61 $/hr Per Kevin Pylka e-mail 07-31-06

Maintenance Labor 61 $/hr Per Kevin Pylka e-mail 07-31-06

Electricity 0.051 $/kwh 2006

Expected annual average industrial price of electricity in the West North Central Division for 2007 - DOE http://tonto.eia.doe.gov/steo_query/

Natural Gas 9.2575 $/mscf 2005

Energy Information Administration. Average US Industrial Natural Gas Prices. July '05 to June '06. http://tonto.eia.doe.gov/dnav/ng/his

Water 0.28 $/mgal 0.20 1995

EPA Air Pollution Control Cost Manual, 6th Ed 2002, Section 5 Ch 1, page 1-40

Annual Costs for Packed Tower Abadjusted for 3% inflation.

Cooling Water 0.28 $/mgal 0.23 1999

EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1

Ch 1 Carbon Absorbers, 1999 $0.13% inflation

Compressed Air 0.32 $/mscf 0.25 1998

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 

Example problem; Dried & Filtered, inflation

Wastewater Disposal Neutralization 1.69 $/mgal 1.50 2002

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $1- $2/1000 gal. Co3 lists $1.30 - $2.15/1,000 gal

SCR Catalyst 141.00 $/ft3 Cormetech, Inc.

Chemicals & SuppliesLime 91.62 $/ton 91.62 2006 Estimate from Cutler-Magney Company.Oxygen 40.00 $/ton 2006 BOC estimate.

Ammonia (29% aqua.) 0.12 $/lb 0.101 2000

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2, page 2-50

Annual costs for a retrofit SCR systadjusted for 3% inflation.

Caustic 305.96 $/ton 280 2003 Hawkins Chemical 50% solution (50 Deg Be); includes 

OtherSales Tax 6.5% %Interest Rate 7.00% %

EPA Air Pollution Control Cost Manual Introduction, Chapter 2, section 2.4.2. Social (discount) rate used as a def

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control CostsUtility Chem$ Data 
Operating Information

Annual Op. Hrs 8400 HoursUtilization Rate 93%Equipment Life 20 yrs Engineering Estimate

Standardized Flow RateSV051M 704,757 scfm @ 32o F Calculated.

TemperatureSV051M 132 Deg F BART spreadsheet.

Moisture ContentSV051M 16.5% Per Kevin Pylka e-mail 07-31-06Actual Flow RateSV051M 848,000 acfm BART spreadsheet.

Standardized Flow RateSV051M 756,324 scfm @ 68o F Calculated.

Dry Std Flow RateSV051M 631,531 dscfm @ 68o F Calculated.

Max Emis1 Projected Future lb/hr ton/year

Pollutant Lb/Hr Actuals4 (tpy) ppmv ppmv

Nitrous Oxides (NOx)SV051M 1397.0 4,154.0 309 209.4

with 100% coal2 466.0

with 100% natural gas3 1270.0

Enter percent coal burned 40%Enter percent natural gas burned 60%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 Emis1 Projected Future

Sulfur Dioxides (SO2) Lb/Hr Actuals2 (tpy)

SV051M 400.0 950.5 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$ Data 
United States Steel: Keewatin Taconite Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3: NOx 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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 SCR EU030 SCR 4 of 17
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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 SCR EU030 SCR 5 of 17
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 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 756,324

Vol #2 11571.3 ft3

Amount Required 11,571 ft

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 H2O per layer

Press drop duct 3 in H2O 

Total 1640.1

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 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 dscf/MMBtu 108,262

Method 19 Factor dscf/MMBtu 9,200

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 15% of Operator Costs 19,215

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 SCR EU030 SCR 6 of 17
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)

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 

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 Reheat EU030 Reheat 7 of 17
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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 Reheat EU030 Reheat 8 of 17
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 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 Reheat EU030 Reheat 9 of 17
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 

Twi 132 Deg F - Temperature of waste gas into heat recovery

Tfi 750 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 565 Deg F - Temperature of waste gas out of heat recovery

Tfo 317 Deg F - Temperature of flue gas into of heat recovery 

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)

-hwg 0 Btu/lb Heat of combustion waste gas

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

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

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F

Qwg 756,324 scfm - Flow of waste gas 

Qaf 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)

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 Reheat EU030 Reheat 10 of 17
United States Steel: Keewatin Taconite Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4: NOx

 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, "NOX 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: SO2

 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 (SO2) 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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 WWESP 9/7/2006 Page 12 of 17
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 multiplier3

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 WWESP 9/7/2006 Page 13 of 17
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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Keetac\Keetac Control Costs

EU030 WWESP 9/7/2006 Page 14 of 17
United States Steel: Keewatin Taconite Company

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6: SO2 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 (SO2) 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 multiplier5

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 $/ft3

Amount Required 0 ft3

Packing Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 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 Rate2

32,224 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 796 gpm

Evaporation Loss4

 = 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 15% of Operator Costs 4,804

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 
!;

N

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

0 100

Kilometers

MODELING DOMAIN

Taconite BART Modeling

Taconite Industry Group

Minnesota

0 100

Miles

Legend

Modeling Domain

Class I Area

BWCA

Voyageurs
TERREL

Variable Description Value Default Comments

GTOPO30 GTOPO 30-sec data - n/a 1 degree DEM files will be used

XREFKM Reference point coordinates for grid 168 n/aYREFKM Reference point coordinates for grid 720 n/a

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

CTGPROC

Variable Description Value Default Comments

XREFKM Reference point coordinates for grid 168 n/aYREFKM Reference point coordinates for grid 720 n/a

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

CALMET

Variable Description Value Default Comments

NUSTA Number of upper air stations 4 14898, 14918, 94983, 4837

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

XORIGKM Reference point coordinates for grid 168 n/a

YORIGKM Reference point coordinates for grid 720 n/a

NOOBS No Observation Mode 0 Y Include Surface, Upper Air and 

NSSTA Number of Surface Stations 74 n/a 74 surface weather stationsNPSTA Number of Precipitation Stations 68 n/a 68 precipitation stations

RMAX2 Maximum radius of influence over land aloft 50 n/a Similar to PSD with ObservatioRMAX3 Maximum radius of influence over water 500 n/a Similar to PSD with Observatio

R1 Relative weighting of the first guess field and observations in the surface layer (km) 10 n/a Similar to PSD with ObservatioR2 Relative weighting of the first guess field and observations in the layers aloft (km) 20 n/a Similar to PSD with Observatio

ISURFT Surface met. Stations to use for the surface temperature - n/a Hibbing Met station

IUPT Upper air station to use for the domain scale lapse rate - n/a International Falls Upper Air sta

ITPROG 3D temperature from observations or from prognostic data? 0 Y Inclusion of Surface and Upper 

TRADKM Radius of influence for temperature interpolation 500 Y Similar to PSD with Observatio

JWAT1 Beginning land use category for temperature interpolation over water 99 n/a CALMET may fail when using 5JWAT2 Ending land use category for temperature interpolation over water 99 n/a CALMET may fail when using 5

SIGMAP Radius of influence (km) 100 Y Precipitation Observations are 

Input Group 0bInput Group 2Input Group 2Input Group 2Input Group 4Input Group 5Input Group 6
CALPUFF

Variable Description Value Default Comments

NX Number of X grid cells in met grid 40 n/a

NY Number of Y grid cells in met grid 30 n/a

XORIGKM Reference point coordinates for met grid 168 n/a

YORIGKM Reference point coordinates for met grid 720 n/a

IBCOMP X index of LL corner 1 n/a

JBCOMP Y index of LL corner 1 n/a

IECOMP X index of UR corner 40 n/a

JECOMP Y index of UR corner 30 n/a

MOZ Ozone data input option 1 N OZONE.DAT from MN, WI, an

NREC Number of non-gridded receptors 1222 n/a Using only BWCA and Voyage

Input Group 11Input Group 17Input Group 4
N

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100

0 100

Meters

Keetac 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, Final1

, with the modifications found in Appendix B. 

The CALPUFF system consists of three main components (CALMET, CALPUFF and CALPOST) and a 

number of pre-processing programs. These pre-processing programs are designed to prepare available 

meteorological and geophysical data for input into CALMET. Each of these modeling components are 

described below: 

• CALMET is a meteorological model that develops hourly wind and temperature fields on a threedimensional gridded modeling domain. Associated two-dimensional fields such as mixing 

heights, terrain elevations, land use categories and dispersion properties are also included in the 

file produced by CALMET. 

• CALPUFF is a transport and dispersion model that follows the “puffs” of material emitted from 

one or more sources as they travel downwind. CALPUFF simulates dispersion and chemical 

transformations as each puff moves away from the source, using the multi-dimensional grids 

generated by CALMET. 

• CALPUFF produces an output file containing hourly concentrations of pollutants which are 

processed by CALPOST to yield estimates of ambient air extinction coefficients and related 

measures of visibility impairment at selected averaging times and locations. 

Lambert conformal coordinates (LCC) were used in the modeling. To accommodate this coordinate 

system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets 

and overcome other size limitations, CALPUFF was recompiled with several size parameters increased. 

 

1

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

Subject to BART in the State of Minnesota. 
CALMET 

Three years (2002-2004) of MM5 prognostic mesoscale meteorological data, surface weather data, 

precipitation data, and upper air data were used to generate the CALMET data set for use in the 

CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells 

(north-south) with a grid spacing of 12 km. This grid encompasses the facility sources, the BWCAW and 

Voyageurs National Park. USGS digital elevation maps (DEMs) and land use land cover (LULC) files 

required by CALMET were obtained from the MPCA. 

CALPUFF 

CALPUFF model input files were set up for each year of CALMET data. Model parameters were set to 

the values specified in the revised modeling protocol (Appendix B). 

The CALPUFF modeling considered the emission of SO2, NOx, PM10 (coarse particulate matter, 2.5μ to 

10μ), and PM2.5 (fine particulate matter, under 2.5μ). 

The CALPUFF modeling also tracked SO4, NO3, and HNO3, which are generated by the chemical 

transformation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates 

of transformation. The MESOPUFF-generated transformation rates are a function of the background 

ozone and ammonia concentrations, the former set by observations, the latter using monthly average 

values provided by MPCA. 

The CALPUFF modeling used the receptors for the Boundary Water Canoe Area Wilderness and 

Voyageurs National Park provided by the MPCA in the original subject-to-BART modeling files. 

CALPOST 

CALPOST converted the hourly concentration and monthly average relative humidity files generated by 

CALPUFF into 24-hour time-averaged extinction coefficients. These emissions-based extinction 

coefficients were compared to the 20% best days background extinction coefficients designated in the 

modeling protocol. 
2. Visibility Impacts Analysis 

As indicated in EPA’s final BART guidance2, states are required to consider the degree of visibility 

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

and technical feasibility, when determining BART for an individual source. 

The CALPUFF program models how a pollutant contributes to visibility impairment with consideration 

for the background atmospheric ammonia, ozone and meteorological data. Additionally, the interactions 

between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part in predicting 

impairment. It is therefore important to take a multi-pollutant approach when assessing visibility impacts. 

Assessing Visibility Impairment 

The visibility impairment contribution for different emission rate scenarios can be determined using the 

CALMET, CALPUFF, and CALPOST modeling templates provided by the Minnesota Pollution Control 

Agency (MPCA). The Minnesota BART modeling protocol3 describes the CALPUFF model inputs 

including the meteorological data set and background atmospheric ammonia and ozone concentrations 

along with the functions of the CALPOST post processing. There are two criteria with which to assess the 

expected post-BART visibility improvement: the 98th percentile delta deciview and the number of days 

on which a source exceeds an impairment threshold. 

As defined by federal guidance4

 a source "contributes to visibility impairment” if the 98th percentile of 

any year’s modeling results meets or exceeds the threshold of five-tenths of a deciview (dV) at a federally 

protected Class I area receptor. The pre-BART evaluation of this criterion conducted by the Minnesota 

Pollution Control Agency identified this facility as having BART eligible source(s)5

 that could cause or 

contribute to visibility impairment at Minnesota Class I areas. In addition to establishing whether or not a 

source contributes to impairment on the 98th percentile, the severity of the visibility impairment 

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

on which a source exceeds 0.5 dV. 

 

2

 40 CFR 51, Appendix Y. 

3

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

4

 40 CFR 51, Appendix Y. 

5

 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota. 
Predicting 24-Hour Maximum Emission Rates 

Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for preBART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should 

reflect a maximum 24-hour average basis. 

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

respectively. 

Modeled Results 

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for 

the predicted post-BART emission scenario(s). Results for the 98th percentile and number of days above 

0.5 dV at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are 

included in Table 6-3. 
Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

Combustion Controls

1 Overfire Air (OFA) Y N --- --- --- x NOx formation front is not stationary in an indurating furnace Combustion air is separated into p

achieve complete burnout and to e

than NOx

2 External Flue Gas Recirculation (EFGR) Y Y N --- --- x x Mixes flue gas with combustion ai

therefore reduces flame temperatu

3 Low-NOx Burners Y Y

Y 

(preheat 

burners)

Y 

(preheat 

burners)

10-20% x x x

Higher control efficiency at the burner, but the listed control efficiency is for 

the entire furnace.

Burners are designed to reduce Noxygen, flame temperature, and/o

4 Induced Flue Gas Recirculation Burners Y Y N --- --- x x x Need to be upfired. Need convective loop to get gas recirculated Draws flue gas to dilute the fuel in 5 Low Excess Air Y N --- --- --- x Need high O2 for process requirements and product quality Reduces oxygen content in flue g

6 Burners out of Service (BOOS) Y N --- --- --- x Need capacity of all burners for worst case scenario Shut off the fuel flow from one bur

lean zones

7 Fuel Biasing Y N --- --- --- x Power plant technology

Combustion is staged by diverting lower ones or from the center to th

fuel-lean zones 

8 Reburning Y N --- --- --- x Kiln configuration not correct for this technology.

Part of the total fuel heat input is iabove the primary (main burners) (re-burn zone), where hydrocarbo

elemental nitrogen

9 Load Reduction N --- --- --- --- x Power plant technology -product demand side solution This is a strategy to reduce load o

electrical demand throught efficien

10 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

Site-specific x decrease amount of fuel required 

11 Coal Drying Y N --- --- --- x Applies only to facilities that burn coal Dry coal will increase the as-burn

required to be burned. Specific e

12

Coal Addition to Pellets with 

Low Excess Air in the 

Induration Furnace

N --- --- --- --- x Check on status of research Reduce flame temperature and en

13 Ported Kilns Y Y

Y

(grate-kilns 

only)

N

(Metso says 

no NOx 

improvement) --- x x Applicable to grate kilns. Provides additional oxygen for pe

energy use of the kiln 

14 Combustion Zone Cooling Y N --- --- --- x Boiler technology Cooling of the primary flame zone 

surfaces

15 Alternate Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Site-specific x x

Requires case by case analysis. Typically, facilities experience lower NOx when burning solid fuels.

Lower combustion temps with soliNOx by using a fuel with less nitro

16 Oxygen Enhanced Combustion N --- --- --- --- x Research level A small fraction of the combustion 
Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

17 Preheat Combustion N --- --- --- --- x Research level

Pulverized coal preheated and vocompounds are released in a contnitrogen compounds are reduced 

18 ROFA-ROTAMIX Y N --- --- --- x

Can't achieve correct temperature window (1400-1800F). Too hot in kiln 

too cold in reheat

Combination of OFA and SCR. Wutilizes high velocity overfire air. Awith ammonia injection (Rotamix)

19 NOx CEMS Y N --- --- --- x x Optimization of combustion

20 Parametric Monitoring Y N --- --- --- x x Optimization of combustion

38 Catalyst Injection (EPS Technologies) N --- --- --- --- x Research Level A combustion catalyst is directly in

delivered to the combustion site, i

the dynamics of the flame.

Post Combustion Controls

21 Non-Selective Catalytic Reduction (NSCR) Y N --- --- --- x x For clean services. Too much stuff in flue gas would poison catalyst Under near stoichiometric conditio

reduced by CO, resulting in nitrog

22 Low Temperature Oxidation (LTO) - Tri-NOx® Y N --- --- --- x x Used for higher flue gas concentrations Utilizes an oxidizing agent such a

including NOx

23 Low Temperature Oxidation (LTO) - LoTOx Y N --- --- --- x x x Has been included as an "applicable and available" technology in recent BACT analyses from multiple facilities. Utilizes an oxidizing agent such a

including NOx

24 Selective Catalytic Reduction (SCR) Y Y Y Y 80% x x x

Need to inject at appropriate temperature (reheat will be required). Applicable on clean side only.Although this hasn't been demonstrated on an indurating furnace, the stream characteristics appear to make this technology feasible.

Ammonia (NH3) is injected into the 

catalyst to convert NOx into N2 an

25 Regenerative SCR Y N --- --- --- x Clean side only

26 Selective Non-Catalytic Reduction (SNCR) Y N --- --- --- x x Can't achieve correct temperature window (1400-1800F). Too hot in kiln too cold in reheat Urea or ammonia-based chemical

convert NO to molecular nitrogen, 

27 Adsorption N --- --- --- --- x Still in research stages. Use of char (activated carbon) to 

28 Absorption Y N --- --- --- x Similar to TriNOx

Use of water, hydroxide and carbosolutions, molten alkali carbonate

nitrogen.

29 Oxidizer Y N --- --- --- x Redundant to regenerative SCR

Gas stream is sent through the re

direct fired oxidizer where pollutandestroyed.
Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

30 SNOX N --- --- --- --- x Early commercial development stage

Catalytic reduction of NOx in the p

catalytic oxidation of SO2 to SO3. 

passes through a novel glass-tube 

hydrated to H2SO4 vapor and then 

sulfuric acid (H2SO4).

31 SOx-NOx-Rox-Box N --- --- --- --- x Technology has not been demonstrated Dry sorbent injection upstream of 

ammonia injection upstream of a z(SCR) catalyst incorporated in the 

32 Electron (E-Beam) Process N --- --- --- --- x No operating commercial applications on coal Electron beam irradiation in the pr

conversion of sulfur and nitrogen easily collected by conventional m

33 Electrocatalytic Oxidation N --- --- --- --- x Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NO

dioxide (NO2), sulfuric acid, and m

thermal plasma.On recent project, the vender was applications.

34 NOXSO N --- --- --- --- Commercial version of adsorption. Limited experience (proof-of-concept 

tests).

Uses a regenerable sorbent to sim

flue gas from coal-fired utility and SO2 is converted to a saleable su

sulfur, or sulfuric acid) and the NO

35 Copper-Oxide N --- --- --- --- x Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with cop

of alumina, to form copper sulfatebefore the absorption reactor and reaction occurs that reduces the nregeneration step, the copper sulfreducing agent, such as natural gSO2.

36 Cold Plasma N --- --- --- --- x Research Level

37 Biofilters Y N --- --- --- x Not applicable to furnaces.

Gas stream is passed through a fiPollutants are adsorbed and degr

the products carbon dioxide and w

38 Pahlman Process N --- --- --- --- x Research Level

Gas stream is passed through a fideveloped, small-particle, high-subeen deployed. Pollutants are rem

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports
Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Tacondistributed without the full texnot taken out of context.

Reference No.1 SO2 Pollution Control Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency

MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other2 Comments B

1 Wet Scrubbing (High Efficiency) Y Y Y Y 90-95% x x x Absorption and reaction using an al

2 Wet Scrubbing (Low Efficiency) Y Y Y Y <50% x x x Absorption and reaction using an al3 Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y 80% x x Suspended particles are separated f

collected in hoppers

4 Dry sorbent injection Y Y Y N --- x x x

Pulverized lime or limestone is direfilter. Dry sorption of SO2 onto the 

particles are collected with a fabric 

5 Spray Dryer Absorption (SDA) Y Y Y N --- x x Lime slurry is sprayed into an absor

slurry, forming CaSO3/CaSO4

6 Alternative Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Site-specific x x Natural gas is base case Use a fuel with lower sulfur conten

7 Load Reduction N --- --- --- --- x Power plant technology This is a strategy to reduce load on 

demand throught efficiency project

8 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

Site-specific x decrease amount of fuel required to 

9 Coal Drying Y N --- --- --- x Applies only to facilities that burn coal Dry coal will increase the as-burned 

to be burned. Specific energy effici

10 Bio Filters N --- --- --- --- x Research level

Gas stream passes through a packe

supports the growth of active bactebiodegraded or biotransformed into water, chloride ion in water, sulfate 

11 CANSOLV Regenerable SO2 N --- --- --- --- x Research level

An aqueous solution of proprietary 

countercurrent absorption tower. Tstripping, giving a byproduct of pur

recycling to the absorber.

12 Pahlman Process N --- --- --- --- x Research level

Gas stream is passed through a filteparticle, high-surface area metal oxremoved from the gases by adsorpt

13 SOx-NOx-Rox-Box N --- --- --- --- x Technology has not been demonstrated

Dry sorbent injection upstream of tinjection upstream of a zeolitic seleincorporated in the baghouse to red

14 Electron (E-Beam) Process N --- --- --- --- x No operating commercial applications on coal Electron beam irradiation in the pre

conversion of sulfur and nitrogen ocollected by conventional methods 
Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Tacondistributed without the full texnot taken out of context.

Reference No.1 SO2 Pollution Control Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency

MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other2 Comments B

15 Electrocatalytic Oxidation N --- --- --- --- x Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NO

dioxide (NO2), sulfuric acid, and m

plasma.On recent project, the vender was d

16 NOXSO N --- --- --- --- Commercial version of adsorption. Limited experience (proof-of-concept tests).

Uses a regenerable sorbent to simul

from coal-fired utility and industria

a saleable sulfur by-product (liquid 

NOx is converted to nitrogen and o

17 Copper-Oxide N --- --- --- --- x Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with copp

alumina, to form copper sulfate. Amabsorption reactor and a selective c

reduces the nitric oxides in the flue is reduced in a regenerator with a rconcentrated stream of SO2.

18 SNOX N --- --- --- --- x Early commercial development stage

Catalytic reduction of NOx in the p

catalytic oxidation of SO2 to SO3. T

through a novel glass-tube condens

and then condensed to a concentrat

19 Cold Plasma N --- --- --- --- x Research level

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports





















Summary of Relevant Economic Feasibility ($/ton) Control Costs 

Avg. Expected Values 

($/ton) 

Limiting/Marginal values 

($/ton) 

Reference Regulatory Body/Rule SO2 NOx SO2 NOx Comments 

BART 100 - 1000 100 - 1000 70 FR 39135 BART 281 - 1296 70 FR 39135 Table 3 BART 919 70 FR 39133 FR Notice 6JULY05 Final Rule 

BART 

Guidelines disparagingly reference "thin commenting on the need to exceed Munreasonableness. 

70 FR 25210 CAIR CAIR 1300 Estimated Marginal cost 2009 

BART(proposed rule) 200-1000 

BART proposed lists this as values for which is still assumed, or .1 to .15 lb/Mfinal to give states flexibility to require 

FR Notice 5MAY04 Proposed Rule bypasses aren't BART, only 100% scru

BART(proposed rule) 

0.2 lb/MMBtu for NOx is assumed reasome sources may need SCR to get thidiscretion of the cost vs. visibility valu

CAIR(using IPM) 1000 1500 CAIR ( 2009 in 1999$) 900 2400 CAIR ( 2015 in 1999$) 1800 3000 

Midwest RPO Report Referencing CAIR 

CAIR (depending on Nat'l emissions) 1200 - 3000 1400- 2100 This was modeled with TRUM (Techn

Updating Model) to develop the margi

Kammer EPA Decision Kammer Decision > 1000 > 1000 LADCO Midwest RPO Boiler Analysis LADCO/Midwest RPO 1240 - 3822 607 - 4493 MANE-VU BART Control Assessment MANE-VU 200 - 500 200 - 1500 Bowers vs. SWAPCA Bowers vs. SWAPCA 300 300 1000 1000 954-1134 was ruled too much, in favor 

did consider incremental value. Section

WRAP 3000 WRAP Trading Program 

Methodology EPA - Referenced by 

Wrap 

References EPA-600S\7-90-018. Low $500-3000/ton, High is over $3000/ton 

The dollars per ton estimates cited above were obtained from BART guidance, documentation of similar regulatory 

and relevant court decisions. These materials indicate that most EPA sanctioned documents, including the final BAR

support an average expected reasonable cost range of $1,300 to $1,800 per ton of NOx removed and a range of $1,0SO2 removed. The BART presumptive limits were set based on cost effective controls that were on average less tha

example, the presumptive SO2 limit was established based on an average cost effectiveness of less than $1,000/ton. 

extends into RPO, WRAP and other regional planning documentation, the cost ranges become more variable and di

ease of comparison, the federally established ranges for NOx and SO2 were used as a BART cost threshold basis.